ML20132F295

Rev 0 to NSPLMI-96001, Prairie Island Nuclear Generating Plant Ipeee

ML20132F295
Person / Time
Site:	Prairie Island
Issue date:	12/12/1996
From:	NORTHERN STATES POWER CO.
To:
Shared Package
ML20132F283	List: ML20132F278 ML20132F295
References
NSPLMI-96001, NSPLMI-96001-R, NSPLMI-96001-R00, NUDOCS 9612240185
Download: ML20132F295 (220)

Text

{{#Wiki_filter:. _ . _ . . _ _ _ _ _ . _ - __._ _ _ _ _ . . O I PRAIRIE ISLAND 4 INDIVIDUAL PLANT EXAMINATION

OF EXTERNAL EVENTS (IPEEE) i 8

i NSPLMI - 96001 Revision 0 December 1996 O l

l Prepared by Ib Date 12//2/'i6

. O b.ldlAlbrLh Date I&l% C4J W Date Wi>l% Reviewed by L 4 Date n o W. l

                              /              /                        /  '

Approved by efdd h4 "" A'C Date /4 2/fg I a I ( 9612240185 961216 PDR ADOCK 050002G2  ! P PDR _ l 1

n V PRINCIPAL CONTRIBUTORS d Nonhern States Power Comoany Randy Best Tom Asmus Dan Brown p TENERA. Inc. I Dave Blanchard Wes Brinsfield Robert Buell Rich Newman Peter Szetu Ravi Thuraisingham Peter Turi i 1 EOE International Phil Hashimoto Dave Nakaki O 'L O  ;

ACKNOWLEDGEMENTS The authors of this report wish to acknowledge and thank the members of the in-house review team who Swed and commented on the draft version of this repon. Their input and insights have helped i imprc he quality of this repon, the analysis that suppons it, and an increased understanding of the Prahie. nd plant. The review team members are (specialty areas in parentheses)

Reviewers Associated Titles / Positions at PINGP Albrecht, Kenneth General Superintendent, Engineedng Ballou, Edc L Sr. Engineer (Fire Protection, Environmental Qualification) Breene, Thomas L Superintendent, Nuclear Engineering Cunis,Jeffrey Superintendent, Electrical Systems Engineering Goldsmith, John E General Superintendent, Nuclear Generation Services Gonyeau, Joseph A Sr. Nuclear Consultant, Life Cycle Mgmt. (Maint. Rule /PM Coord.) c Hall, Michael Sr. TechnicalInstructor(Severe Accident Management) '.0 94106702.007 ii

, ,A Hill, Jirn Manager, Quality Services i Hoffman, Jim Project Manager (Appendix R, Electrical Issues) Lenertz, George General Superintendent, Maintenance Leveille, Jack Sr. Engineer (Licensing) Lindsey, Richard General Superintendent, Safety Assessment Maki, Jeff Superintendent, Outage Planning ! McKeown, Mark V Sr. CivilEngineer(Seismic) i Mundt, Chris Superintendent, I&C Systems Engineering Pearson, Richard Consulting Engineer, Life Cycle Mgmt. (Steam Generator Issues)

Peterson, Robert Principle Electrical Engineer (Design Basis Documents)

Riedel, Patricia J Sr. Engineer (PRA, Monticello Plant)

Schuelke, Don General Superintendent, Radiation Protection and Chemistry Sorensen, Joel General Superintendent, Operations Stephens, Ben Superintendent, Mechanical Systems and Programs Engineering Valtakis, Peter Shift Manager, Operations Wadley, Michael Plant Manager, PINGP Walker, Parks Manager, PITraining Center Wemer, Michael Site Safety and Fire Protection Administrator Westphal, Dennis Superintendent, Operations Training i

o t I 9410s702.007 iii

Q V Table Of Contents EXECUTIVE

SUMMARY

.. . ...... ..... .. .. . . .. .. ... . . ......... ..... . . .. . .. .. .. .... . ... . . . . . ... .. . . ... ... ... .. .. . .... ... . ... v

1. EXAMINATION DESCRIPTION .. . . . .. .... . ...... . ... . . . ... . .. .. ...... . . . ... ... .. ... ..... . .. ... .... ..... .. . .. ... I 1.1 Introduction .. ........ ........... .. .. ..............................................................I 1.2 Conformance with Generic Letter and Supporting Materials........ .... .......................... 2 1.3 Structure ofIPEEE Report.......................... .... ........ . ..... .... .. . ... . ...................3

2. UTILITY PARTICIPATION AND INTERNAL REVIEW TEAM ............. .......... .............. 5 2.1 IPEEE Program Organization......... . . .. . .........................................5 2.2 Composition of the Internal Review Team . .. .......... ...... ........ ........... . ...... ............ 5

3. IPEEE INSIGHTS FOR PRAIRIE ISLAND AND RECOMMENDATIONS .... . ..........6 3.1 Conclusions and Insights from the IPEEE Analyses....... . .. .. .. ............ ................... 6 3.1.1 Seismic Analysis... . ...... .. . .... .... . .. ..... ... .. . . . .. . . . .. . .... ... .... . 6 3.1.2 Internal Fires Analysis... ...... . . . . . .... ... ......... ......... .. ..... .. ................. .... 7

• 3.1.3 High Winds, Floods, and Others. . .. . . ... .... .... . .... 8 g APPENDICES

( Appendix A: Seismic Analysis - Appendix B: InternalFires Analysis Appendix C: High Winds, Floods, and Others 1 ( 94108702.007 IV 1

i EXECUTIVE

SUMMARY

This repon documents Nenhem States Power Company's (NSP) response to Supplement 4 of Generic ' Letter (GL) 88-20, " Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities", which was issued in June of 1991. The IPEEE extends the analysis perfonned for the Individual Plant Examination of intemal events (IPE) which is the subject of the Generic letter and its first three supplements. NSP's IPE report for the Prairie Island plant was submitted to the NRC for review on March 1,1994. The IPEEE assessments described in this report address the extemal events idenW m kpplement 4 of GL 88-20, namely canhquakes (seismic activity), intemal fires, high winds, uoods, and other credible extemal events. For the seismic investigation, NSP elected to complete the Prairie Island seismic IPEEE by conducting the equivalent of a reduced scope seismic margins assessment with an additional focus on a few key components, in accordance with Supplement 5 of Generic Letter 88-20. NSP determined that the internal fire assessment could best be done with a PRA approach using the updated IPE models, combined with the deterministic evaluation techniques of the EPRI Fire Induced Vulnerabilities Evaluation (FIVE) Methodology. The evaluation of other external events was I performed using a combination of probabilistic and deterministic techniques. The analyses for these assessments beganin 1994. The attached report summarizes the results of the assessments conducted to consider the potential for severe accident vulnerabilities due to the set of extemal events identi6ed by Generic Letter 88-20, - Supplement 4. Based on this report, it is concluded that there are no significant vulnerabilities to severe accidents that exist at Prairie Island that would be attributable to seismic, fire, or other extemal events. This report completes commitments made in regard to the Generic Letter with respect to the IPEEE. 94108702.007 V

l I l L EXAMINATION DESCRIPTION , L1 Introduction In July and August of 1985, the NRC published its policy statement on issues related to severe accidents in NUREG-1070 and 10 CFR Part 50. The Severe Accident Policy states that, on the basis of currently available information, existing plants pose "no undue risk" to the health and safety of the i public. Therefore, the NRC sees no justification to take immediate action on generic mle making or I other regulatory changes for existing plants because of issues related to severe accidents. The Commission's conclusion of"no undue risk" is based upon actions taken as a result of the Three Mile Island action plan (NUREG-0737), information that resulted from NRC and industry-sponsored research, information obtained from published Probabilistic Risk Assessments (PRAs) and operating expedence, and the results of the Industry Degraded Core Rulemaking Committee (IDCOR) technical program. Since November,1988, the NRC staffissued Generic Letter 88-20 and five supplements which formalized the requirement for an Individual Plant Examination (IPE) under 10 CFR 50.54(f). This generic letter requested utilities to perform their IPEs, provided reporting requirements (Supplement 1), identified accident management strategies to be considered as part of the IPE (Supplement 2) and established containment performance improvement considerations (Supplement 3). The Generic Letter and the requirements for each ofits supplements were addressed in thePraideIsland IPE submittal to the NRC on March 1,1994. O Supplement 4 to Generic Letter 88-20, Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities, was issued in June of 1991 The IPEEE is to specifically address seismic and intemal fire events, and then other remaining risk concerns from external initiators (e g., high winds, floods). Supplement 5 modified the scope of the seismic portion of the IPEEE to be l equivalent to a reduced scope seismic margins assessment with a focus on a few key cdtical components. l The primary objectives of the IPEEE, as stated by the NRC in the Genede Letter, are for each utility to develop an appreciation of severe accident behavior; understand the most likely severe accident j sequences that could occur at its plant under full-power operating conditions; gain a qualitative j understanding of the overall likelihood of core damage and radioactive releases by modifying hardware and procedures that would help prevent or mitigate severe accidents. The specific objectives are to:

• Identify the potential accident sequences that contribute to the overall core damage frequency. '

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• Identify cost effective modifications to the plant design, operating procedures, training or i maintenance procedures that would reduce the likelihood of any accident outliers that are identified.
• Maximize panicipation in the evaluation process by NSP personnel.
• Provide a well organized and clearly written summary of the Prairie Island IPEEE to facilitate communication of the results to both NRC and NSP, as well as to serve as a tool for  !

communicating the results to interested members of the public. l

• Develop the risk-based tools and methods, and the essociated documentation, to suppon resolution of future regulatory, safety, or operational issues for Prairie Island. ,

l M Conformance with Generic Letter and Supportine Materials NSP's Probabilistic Risk Assessment (PRA) Group has been actively involved with the IPEEE process since its inception. Lead responsibility for the IPEEE effon was assigned to the PRA Group, which is a part ofNSP's Licensing and Management Issues depanment. The PRA Group directed all aspects of I the analysis, with general consulting services provided by TENERA, Inc., and EQE International. The PRA Group directed the effon, coordinated the work with affected members of the plant staff, was involved in various aspects of the analysis process, and has actively worked with the consultants to ensure the transfer of technology to NSP, so that future applications of the IPEEE can be performed by (] NSP personnel with the need for only limited extemal resources. Further details of the organization are provided in Section 3 of this report. l This repon documents NSP's completion of the IPEEE in accordance with Supplement 4 and 5 to Generic Letter 88-20. A comprehensive review of the IPEEE work was performed by NSP personnel.  ; A review team composed of plant s;aff and corporate personnel of various disciplines reviewed this repon prior to its publication as described in Section 2. In addition to the reviews of the completed analyses, various reviews and validations were performed as pan of the analytical process. Walkdowns supporting each of the topics reviewed in the IPEEE j were performed to confirm input assumptions and final conclusions. References to these walkdowns . are provided in each appendix. I For the seismic IPEEE, a modified focused scope seismic margins assessment was performed. Screening of the capacity of systems, structures and components (SSCs) was evaluated at 0.3g in accordance with EPRI NP-6041-SL (A Methodology for Assessment of Nuclear Power Plant Seismic Margin). The critical safety functions necessary to respond to the postulated conditions following a seismic event were reviewed to identify the key systems used to accomplish those functions. Through work performed as pan of the SQUG program, it was demonstrated that there is high confidence that O mos702.co7 2

multiple systems would be available to accomplish core cooling and containment pressure control for pb seismic events as large as the SSE. The results of this modified focused scope seismic margins assessment are provided in Appendix A. The fire IPEEE analysis was completed by performing a fire PRA supported by the deterministic evaluation techniques of EPRfs Fire Induced Vulnerability Evaluation Methodology (FIVE). The analysis concluded that the overall core damage frequency is low (on the order of 6E-5/yr) which is comparable to the intemal events PRA results. Sensitivity analyses were performed for the intemal fire analysis to identify important fire areas, operator actions, and plant components that drive the potential risk associated with intemal fires. The results of the fire PRA are presented in the discussion of accident sequence results in Appendix B. The majority of the assessment of other extemal events (Appendix C) did not require detailed evaluation or sensitivity analyses, as most issues could be resolved by comparison with the NRC's Standard Review Plan. When additional probabilistic or deterministic analyses were needed for these other external events, bounding analyses or sensitivity studies were performed to address specific uncertainties. M Structure ofIPEEE Report NUREG 1407, " Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities", identifies reponing guidelines for IPEEE (] V submittals. A cross-reference between the headings in the standard table of contents suggested in NUREG-1407 and this report is provided in Table 1. The most notable difference between the suggested format and that used in this report is that the individual evaluations for severe accident vulnerabilities for seismic events, intemal fires, and other extemal events are contained in separate appendices at the end of this report. The seismic margins assessment is in Appendix A; the assessment ofintemal fires is in Appendix B; and the evaluation of other extemal events is in Appendix C. Each appendix is designed to stand alone in order to faci'itate their separate review. (3 Y 94108702 007 3

i t Table 1 C Cross-Reference Between NUREG-1407 Topics and Contents of this Report NUREG 1407, Table C.1 Topic Location in this Report Executive Summary: 2 - Background and Objectives Main report and section 1.1 of each appendix i - Plant Familiarization Section 1.2 of each appendix

    - OverallMethodology                    Main report and section 1.3 of each appendix
    - Summary ofMajor Findings              Main report and section 1.4 of each appendix

. Examination

Description:

    - Introduction                          Section 1.1 ofmain report
    - Conformance with Generic Letter       Section 1.2 of main report 1

and supporting material

    - General Methodology                   Section 2 of each appendix i
    - Information Assembly                  Section 2 of each appendix Seismic Analysis (seismic margins       Appendix A assessment)

InternalFires Analysis Appendix B 1 High Winds, Floods and Others Appendix C Licensee Participation and Section 2.0 ofmain repon Internal Review Team Plant Improvements and Appendix A, Section 2 Unique Safety Features Appendix B, Section 2 I Appendix C, Sections 2.2 - 2.4 Summary and Conclusions Section 3 of main report (Overall) and Appendix A, Section 2.6 Appendix B, Section 2 Appendix C, Section 3.0 J scos702.co7 4 i

I h V A UTILITY PARTICIPATION AND INTERNAL REVIEW TEAM i Lj, IPEEE Pmeram Orvanization I l The Director of NSP's Licensing and Management Issues depanment has the overall review and l approval responsibility. The members of NSP's PRA group report to the Director of Licensing and I Management Issues and, as a team, act as the NSP PRA/IPEEE Program Manager. The PRA group is ) responsible for the details and overall project management for all PRA and IPEEE analyses at NSP. j Three PRA group members worked on the Prairie Island PRA/IPEEE, all of whom are located at the plant site. The experience and training of these team members includes the following:

     >        One formerly SRO-licensed engineer, currently Nuclear 'tertified" per the NSP nuclear certification training program; another nuclear certified engineer; and one associate engineer with a plant operations background.                                                               ;
     >        All three PRA Group members were primary contributors to the PINGP IPE analysis.
     >        Involvement of the group members in utility initiatives includes membership in the                i Westinghouse Owner's Group Risk-Based Technologies Working Group, the EPRI Risk and               l Reliability Workstation User's Group, and the EPRI Safety and Reliability Assessment Target Steedng Committee.
     >        Collectively, these team members have over 35 years ofnuclear power plant experience.

TENERA, Inc. and EQE Intemational, provided consulting services in support of the IPEEE program. TENERA has worked with the NSP PRA group since the inception of NSP's IPE program. EQE Intemational provided expertise in the seismic / structural engineering area, having extensive industry experience in seismic PRAs, seismic margin assessments, and USI A-46 programs. TENERA and EQE Intemational actively worked with the NSP PRA group at PINGP to ensure the transfer of IPEEE technology was accomplished. 12 Comoosition of the Internal Review Team In addition to the involvement by NSP's PRA group in the IPEf E program, various plant organizations were involved throughout the evaluations as well as during an internal review process of the IPEEE results. For the IPEEE, a review team was selected that would provide a thorough and diverse consideration of both the assumptions input to the analyses, and the results and conclusions produced by those analyses. This review took advantage of specific organizations that have related programs underway to review the IPEEE results. Examples include the Prairie Island SQUG (Seismic Qualification User's Group) effort (associated with Unresolved Safety Issue A-46) and the Fire Protection group (associated with maintaining the Appendix R analyses). O O 94108702.007 5

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i 1 IPEEE INSIGHTS FOR PRAIRIE ISLAND AND RECOMMENDATIONS

! 11 Conclusions and Insiehts fmm the IPEEE Analyses The external events examination was conducted in three distinct phases, seismic,' internal fires, and i other external events. Each of these individual studies is described in the appendices of this report. l The following summarizes the conclusions of these assessments, including the specific insights and l recommendations for plant improvements.

3.1.1 Seismic Analysis ,

NSP originally planned to respond to Generic Letter 88-20, Supplement 4, by performing a seismic  !

probabilistic risk assessment (PRA) for Praine Island. By letter dated September 25,1995, Prairie I Island notified the staff of a change in the manner in which the seismic IPEEE would be completed. .i

} This change is based on new information regarding large reductions in the seismic hazard estimates for  ; l sites in the eastem United States, as presented in draft NUREG-1488, " Revised Livermore Seismic i Hazard Estimates for 69 Nuclear Power Plant Sites East of the Rocky Mountains," issued April of ! 1994. This new information was incorporated within Supplement 5 of Generic Letter 88-20, which ! provides the basis for NSP's decision to change the approach ofcompleting the seismic IPEEE from a j seismic PRA to a seismic margins assessment. l A portion of the effort for the PRA was accomplished (i.e., walkdowns and initial screening) when the i NRC issued Supplement 5 to the Generic Letter. NSP elected to change its approach in accordance ! with Supplement 5 and has completed the analysis of seismic events in the form of a reduced scope l i seismic margins assessment with the focus on a few known weaker, but critical, components. The 2 majority of the components included in the assessment were determined to meet the screening criteria i established in EPRI NP-6041-SL. This result in itselfindicates that most of the components have a relatively high seismic capacity. The remaining components; i.e., those not meeting the screening l  ; ! criteria, were evaluated further and 1) were determined either to be adequatt. for the safe shutdown 3 earthquake (SSE); 2) were determined to be unnecessary due to the particular seismic failure mode 1 and/or available plant equipment redundancy; or 3) are to be addressed under the closure of the Prairie

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j lsland SQUG program. Overall, it was concluded that there is no significant plant vulnerability to severe accidents attributable to seismic events at Prairie Island.  : i l ! It should be noted that the seismic analysis conducted as part of the IPEEE program was done in ! conjunction with the efforts at Prairie Island to address seismic issues associated with the USI A-46 i program. This coordination of programs is the basis for crediting certain components that will be upgraded to the SSE level under the closure of the SQUG program. Further, it was shown that many unscreened components that were not diepositioned in the USIA-46 program would not be expected to i lead to the inability to cool the core if they were assumed to fail following a seismic event. In each case, additional random failures of equipment are necessary before inadequa*e core cooling would be j expected. 3 O sc os702.oo7 6 i

Other signi6 cant conclusions of the seismic margins assessment include:

 .        The seismic walkdowns perfonned as part of the IPEEE found most of the components and structures reviewed to be seismically adequate (i.e., suitably anchored and/or seismically rugged).

Those items that could be considered potentially vulnerable were subjected to the more rigorous seismic evaluation referred to above; e Concrete block walls were either screened from further consideration because their failure would cause no adverse consequences, or they were further evaluated and found to have sufficient seismic capacity;

• The review of relays credited in the IPE revealed that there were relays beyond those considered in the SQUG program scope that had to be evaluated. However, it was determined that none of these relays are considered " bad actors";

e Few flat bottom tanks fell solely under the scope of the seismic IPEEE (i.e., SQUG has identified some tanks as outliers that will be addressed under the closure of that program). Those that did were either screened or shown to have limited consequences should they fail;

• A review of containment response reveals no conditions that are unique to seismic events or that have not already been evaluated as part of the intemal events PRA (IPE).
• A recommendation from the seismic margins assessment is to restrain or remove wall hung ladders and scaffolding that are located near safety related equipment to reduce the impact of seismicallyinduced relay chatter.

3.1.2 IntemalFires Analysis The core damage frequency resulting from fires is estimated to be less than 7E-5/yr. This total is on-the same order of magnitude as the core damage frequency of the internal events PRA. It should be noted that these results include a number of conservative assumptions. For example, automatic or i manual fire suppression were not credited except in the control room, cable spreading room, and the { AFW pump rooms. Fires were also assumed to completely engulf an area once ignited. l 1 More than 75 percent of the plant risk associated with the intemal fires can be traced to five fire areas / burn areas. These rooms / burn areas are the Auxiliary Building Ground Floor Unit 1 (Fire Area 58), the cable spreading or relay room (FA 18), the main control room (FA 13), the Turbine Building Ground & Mezz Floor Unit 1 (FA 05, 08,14, 21, 27, 57, 69, 94), the 480V Safeguards Switchgear ) Room-Bus 121 (FA 22), and Access Control (FA 15). Of these, the largest contnbutor to core i damage frequency is the Auxiliary Ground Floor Area, containing both trains of Safety Injection, RHR, l l O 94108702.007 7 i, I

M (N Component Cooling and all three charging pumps. This fire area is important due to the equipment l b located in this area that provides cooling to the Reactor Coolant Pump (RCP) seals. For this area, l Auxiliary Feedwater remains available to proside secondary heat removal. Protection of the cables for j a train of componett cooling as well as the ability to crosstie Unit 2 component cooling prosides  ; adequate protection from a RCP seal LOCA. l Operator actions that dominate the fire PRA are associated with starting the standby component cooling water train, crossticing the Unit 2 component cooling water system, and activating the hot shutdown panel. The purpose of the first two actions is prevention of a seal LOCA should all charging and component cooling water be lost during a fire. Activating the hot shutdown panel is important for ~ the relay room and control room fires. The principal finding of this analysis is that there is no credible single fire in the plant that would lead directly to the inability to cool the core. Without additional random equipment failures unrelated to ' damage caused by the fire, core damage will not occur. As a result, this study concludes that there are no major vulnerabilities due to fire events at the Prairie Island Nuclear Generating Plant. l l 3.1.3 Hich Winds. Floods. and Others j The assessment of other extemal events shows that there are no other credible external events that are of a safety concern to the Prairie Island plant site. No vulnerabilities were identified, and the screening criteria contained in NUREG-1407 and Generic Letter 88-20 (Supplement 4) were satisfied for all events. A simple walkdown was performed to confirm these results. ( l b(3 wos7o2.oo7 2

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4 !Q L1 i I I i 1 4 ,' 1 i i. Prairie Island 1 Individual Plant Examination l of External Events (IPEEE) i 1 l NSPLMI-96001 I i s l 4 !, O 1 i l l

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i Appendix A l Revision 0 i Seismic Analysis 1 i l 4 it 4 l 1 1 I i O 3 A-1 j

l 1 1 . 4 Q U Table of Contents l i A.I. INTRODUCTION . . . . . . . . . . -. A-4 i A.I.i BACKGROUND- -. .  : A-4 i A. I .2 PLANT FAMILIARIZATION.. . A-4 I A.1.3 OVERALL METilODOLOGY . . - A-4 I A. I .4

SUMMARY

OF MAJOR FINDINGS . A-5 A.2. SEISMIC ANALYSlS. . . . .. A-10 A.2.1 PLANT SYSTEMS .- A-11 A.2.1.1 Plant Frontline Systems included in the IPEEE.- ..A-12 A.2.1.1.1 Reactivity Control - A.12 A.2.1.1.2 RCP Seal Cooling A.12 i A.2.1. l .3 Secondary llcat Removal.- - A.13 I A.2.1.1.4 Short Term Inventory Control (Injection Mode) ., A.13 l A.2.1. l .5 Long Term Inventory Control (Recirculation). A.14 A.2.1. l .6 Containment Pressure Control -A.15 A.2.1.2 Support Systems included in the IPE11PEEE.. ..A-16 A.2.1.3 Supporting Components included in the lPEEE-. .. A-19 A.2.2 PLANT WALKDOWN.. A-19 A.2.2.1 Pre-ll'alLlown Preparation . ..A-19 A.2.2.2 Initial Plant II'alkdown.. ,. A-20

   %_./        A.2.2.2.1   Walldown Procedures                                                            A.20 A.2.2.2.2   Walldown Documentation :                                                       A-22 i A.2.2.3 Final Plant II'alkdowns..                                                          .. A-22  !

A.2.2.4 Findingsfrom the Plant il'alkdowns . ..A.22 j A.2.3 COMPONENT SCREENING-- A-25 A.2.3.1 Structure Screening.. .. A-25 i A.2.3.2 Concrete Block ll'allScreening - A.25 l A.2.3.3 Component Screening.. .. A-26 A.2.3.4 Relay Screening.. .. A-27 A.2.4 RESULTS ... .. . . A-49 l A.2.4.1 Disposition ofComponents Needing Additional Evaluation.. ..A-49 A.2.4.1.1 Disposition Based on SQUG Program Results - A-49 A.2.4.1.2 Disposition Based on Systems Analysis A-51 A.2.4.1.3 Outliers Potentially Addressed by Maintenance Procedures.. A.58 A.2.4.2 Safe Shutdown Functions Following a Seismic Event.. .. .. A.59 A.2.5 ANALYSIS OF CONTAINMENT PERFORMANCE = A.72 A.2.5.1 Basisfor the Scope ofthe Analysis.. . ..A-72 A.2.5.2 Containment Structures and Systems . . ..A-72 A.

2.6 CONCLUSION

S AND RECOMMENDATIONS - .A-80 A.2.7 UNRESOLVED SAFETY ISSUES AND OTIIER SEISMIC SAFETY ISSUES .  : A-81 A.

2.8 REFERENCES

A-83 A A-2

1 i 4 List of Tables I Table A.1 Prairie Island Seismic IPEEE: Summary of Major Findings.. A-7

Table A.2.3-1 Seismically Rugged Components-- . A-28 j Table A.2.3-2 Relays Outside the SQUG Program Scope-- . . . . . . . A-47 j Table A.2.4-1 Disposition of Components Not Meeting Reduced Scope Screening- A-63 i Table A.2.5-1 Prairie Island Level 1 to Level 2 Dependencies...... .... ..... ..-: A-78 j Table A.2.5 2 Contributors to Containment isolation Failure.. . . ... . A 79

? 4 p 4 i i 1 'I 1 1 1 e l 5 l I , d i j i j 1 1 7 ? i f I A-3

l l p A.I. INTRODUCTION A.1.1 Background l This report documents Northern States Power Company's (NSP's) response to Supplement 4 of i Generic Letter 88-20, " Individual Plant Examination of External Events (IPEEE) for Severe

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Accident Vulnembilities," for the Prairie Island Nuclear Generating Plant. The assessment I described in this appendix addresses seismic events. The analysis and its results, which are described in the following sections, provide insights with respect to the response of the Prairie Island plant to a seismic event. As described in Supplement 5 to Generic Letter 88-20, an l evaluation equivalent to a reduced scope seismic margins assessment was performed for Prairie i Island with an additional focus on a few key critical components. A.1.2 Plant Familiarization The Prairie Island Nuclear Generating Plant is a two unit facility, each unit consisting of a 2-loop pressurized water reactor within large dry containments. Westinghouse Electric Corporation designed and supplied the nuclear steam supply system and the turbine-generator units. Pioneer l Service and Engineering (now Fluor Power Services, Inc.) was the plant's architect-engineer. l Northern States Power Company constructed the plant. Each reactor core produces 1650 MWt l with an electrical output of 560 MWe, using 121 fuel assemblies. The plant is located within the l city limits of Red Wing, Minnesota. Construction started on June 26,1968. Full commercial l operation began on December 16,1973 for Unit I and December 21,1974 for Unit 2. The original design considered seismic events in the design of Class I systems, structures and components. Chapter 12.2.1 of the Prairie Island USAR defines Class I as " structures and components including instruments and controls whose failure might cause or increase the l severity of a loss-of-coolant accident or result in an uncontrolled release of substantial amounts of radioactivity, and those structures and components vital to safe shutdown and isolation of the reactor." Class I structures and equipment are designed for a horizontal ground acceleration of 0.06g for the Operating Basis Earthquake (OBE) and 0.12g for the Safe Shutdown Earthquake (SSE).  : i Seismic evaluations of masomy walls were performed in the early 1980s under I&E Bulletin 80-11 activities. These evaluations resulted in modifications that increased the seismic capacity of certain masonry walls.  ; A.1.3 Overall Methodology NSP originally planned to respond to Generic Letter 88-20, Supplement 4 [1], by performing a seismic probabilistic risk assessment (PRA) for Prairie Island. The walkdowns and screening l i evaluations of essential structures and equipment were performed following procedures ! applicable to a focused scope plant, which was how Prairie Island was categorized in NUREG-1407. In accordance with Supplement 5 to Generic Letter 88-20 [2], NSP subsequently elected A--4

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i i to complete the Prairie Island seismic IPEEE by conducting the equivalent of a reduced scope i O. seismic margins assessment with an additional focus on a few critical key components identified in Attachment I to Supplement 5. il l The overall methodology for the Prairie Island seismic IPEEE thus consists of the following

steps

l 1. Systems and components considered in the seismic IPEEE were identified based on insights from the intemal events PRA.

2. A walkdown of key plant structures, systems, and components was performed following the EPRI NP-6041-SL [3] procedures for a focused scope seismic margin evaluation to screen seismically rugged structures and components from further review.

3. A list was compiled of components that did not meet the screening criteria in the preceding step. This compilation of unscreened components represents a conservative set of outliers for a reduced scope seismic margin assessment.

4. Following the guidance of NUREG-1407 [14], components were evaluated using the criteria of the Generic Implementation Procedure (GIP) [22] using the ground and in-structure SSE response spectra.

5. Structures and components outside the SQUG program scope that were not screened by the O GIP criteria were subsequently evaluated to the SSE level using the requirements of the USAR.

6. For any outliers that remained, a systems analysis was performed by reviewing the effect of component failure on plant systems needed to respond to a seismic event in bringing the plant to a safe shutdown condition.

These steps are described in more detail in Section A.2. l l A.1.4 Summary of Maior Findines  ! The Prairie Island seismic margins assessment concludes that all important safety functions can i be accomplished following a seismic event. The safety functions considered for the IPEEE are j similar to those used to defime the accident sequence types quantified in the IPE:

• Reactivity Control e Reactor Coolant Pump (RCP) Seal Cooling e Secondary Heat Removal l e Short Term Inventory Control (Injection) e Long Term Inventory Control (Recirculation)

                . Containment Pressure Control V            e    Important Support Systems A-5

I t ! Most components included in the seismic margin assessment for Prairie Island that support these l functions have relatively high seismic capacities. Components that do not meet the reduced scope I j seismic margins assessment screening criteria and contribute to the safety functions noted above are summarized in Table A.I. These results apply equally to both units I and 2 as compete walkdowns and seismic margins assessments were performed for both units. i Some components identified in Table A.1 are to be addressed under the SQUG program. These include outliers that will be seismically upgraded or otherwise shown to be seismically adequate . to the SSE. i i 1 1 e t i 4 I . t , l 2  ! n I i j I t ' ) + + 1 4  ; 1 1 3-1 1 4 2 1 1-A-6

                                                                                                               -- ~_                      - ~-                         .+.- ~~.-           ..          - --                        -        .        - -    . ~

Tcble A.1 Prairie Isl=d Seismic E: S1mmnry cf M:j:r Firdings F unction / Components beismic f ailure Mode Postulated Effect of Failure Conclusions , Reactisity Control N/A N/A All Components Screened

• RCP Seal Cooling I
• 13,23 charging pumps
• Anchorage - Loss of seal cooling supply
• Unnecessary due to redundancy from charging j pumps !I,12,21 and 22 -

Component Cooling Water valves

• Interaction
• Unable to change position
• Valves aircady in correct position; position does not MV-32117 & 32267 need to change l
• CC pump auto-start signal is redundant to ESF j PS 16262 thru 16265
• Mercoid Switch
• Loss of CC auto-start signal signal; manual start is also available r Secondary liest Removal
• SG levellogic relays /bistables
• Anchorage - tess of AFW auto-start signal
• Turbine driven AFW start signal occurs on LOOP
• Operator action can recover valve i

 -     AFW TripShrottle Valves CV-

• Seismic-induced trip
• tess ofI train of AFW per unit 31059 and 31060
• Not credited; operators can align cooling water to
• Condensate storage tanks
• Not scismically designed
• Less of SG makeup suction of AFW pumps from the control room i t

Short 't erm Inventory Control (Injection) * * *

• SI Cold Leg inj_ MV-32068
• Interaction
• Unable to change position
• Valve in correct position; no change needed RCS Cooldown and Depressurization

 -     Pressuriier Relief Valves iRC

• Seismic capacity
• Loss of primary depressurization
• Function not credited i I&2,2RC-10-l&2

 -     Boric Acid Filters & Transfer

• Anchorage
• Loss of additional source of boric
• Function not credited Pumps acid

 -    CV-31421

• Interaction
• Loss of train of auxiliary spray
• Function not credited
• Emergency Boration Supply MV-
• Interaction a Valve unable to open
• Function not credited, valve does not need to open 32086

 . SG PORV Accumulators Long-I erm lesentory Control                                          N/A                                                    N/A

• All components screened (Recirculation)

Containment Pressure Control a 13 Fan Coil Unit

• Seismic capacity
• Reduced capacity for containment
• To be addressed by SQUG I cooling
• Containment Spray Pumps
• Anchorage
• Loss ofone means ofcontainment
• Not credited due to capacity of FCUs pressure control
• Transmitters IPT-948 and 2PT-945
• Interaction
• Reduced redundancy in P signal
• Unnecessary due to not crediting containment sprsy source A-7

_ - - _ _ _ _ _ _ . . _ - ----_ma_ ___-m____.--a. . _ _ . . _ _ _ - _ _ _ _ _ m ___- _ _ 2 _ _ _ . _ _ _ . _ _ - _i- - _ _ _ _ _ _ _ _ _ > _m-__+

• e_ -- _

( ,) w/ Tcble A.1, co;tized: Prairic Istrd S IPEEE: S:mrx:ry cf M:j:r Findi:gs (v ) F unction /Componcats heismie Failure Mode Postulated LITeet of Failure Conclusions Support Systems: Coolmg Water

• FCU Cooling Water Supply, CV-
• Interaction
• Loss of cooling to FCUs
• To be addressed by SQUG 39401 & 39409
• FCU Cooling Water Return, CV-
• Interaction
• Damage to limit suitch; unable to
• Valve in correct position and does not need to 394II change position change positions
• II & 21 Screenhouse Roof
• Anchorage - Potential impact to Cooling Water
• To be addressed by SQUG Exhaust Fans dicsci rump

- 12 & 22 Diesel Cooling Water

• Anchorage and shaft instability
• toss of cooling waref
• To be addressed by SQUG Pumps

- Air Compressors for 12 & 22 - Anchorage

• Loss of charging to alr receivers
• Charging function not credited, air receivers Cooling Water Pumps sumcient to start dicscis
• 121 Cooling Water Pump - Anchorage and shaft instability
• Reduced redundancy in Cooling
• Not credited due to capacity of diesel CL pumps Water pumps
• FCU Cooling Water Supply MV.
• Interaction
• Unable to change position - Valve is already in correct position; interaction 32386 woni cause valve to change positions
• Cooling Water Pump Discharge - Mercoid switches
• Loss of Cooling Water pump auto-
• Redundancy in start signal sumcient; manual start Ileader Pressure Switches (PS- start signal capability also exists 16002.16009,16259)

Fuel Oil

• 121/122 CL Pump FO Storage - Undetermined flexibility of - Fuelloss leads to loss of Cooling
• To be addressed by SQUG Tanks buried pipe Water

- 121/123 IX} FO Storage Tanks - Undetermined flexibility of - To be addressed by SQUG buried pipe Fuel loss leads to loss of Emergency AC

• 122/124 DG FO Storage Tanks - Undetermined ficxibility of sourceFuelloss leads to loss of
• Unnecessary due to capacity availabic in Tanks 121 buried pipe Emergency AC source and 122 (Assumed 121 and 123 have been dispositioned by SQUG)

Room Cooling

• Relay Room North (121/I22)&
• Anchorage
• Exceed critical ambient temperature
• To be addressed by SQUG South (121/122) Unit Coolers orcquipment
• 121/122 Control Rcom Chillers
• Unrestrained vibre' ion
• Exceed critical ambient temperature - To be addressed by SQUG isolators ofequipment

- l1,12,21,22 RilR Unit Coolers

• Exceed critical temperature of RllR - Room cooling function determined to be
• Structural integrity pump motor unnecessary

- Switchgear/ Bus Room Cooling

                                                                                            -      Exceed critical temperature of bus
                                      -   Anchorage                                               room equipment

• Room cooling functinn determined to be
• DS/D6 Bus Room Aux Air urmecessary.

llandlers & Aux Condensing Units - Exceed critical temperature of bus

• Anchorage room eqt?ipment
• Room cooling function detcrmined to be unnecessary DC Power

- 1I,12,21,22 Datteries

• Inadequate supports
• Loss of DC supplies - To be addressed by SQUG
• 11.12,22 Battery Chargers = Anchorage
• Loss of battery support - To be addressed by SQUG a

- Panels 11,12 & 22

• Anchorage
• toss of DC distribution To be addressed by SQUG
• Panet153 - Interaction and anchorage
• Loss of DC distribution -

Does not support credited equipment A-8

Tcble A.I,contim:ed: PrairieIsi:nd IPEEE: Sumnixty cf M JorFindi gs Fumet 6eeWComponents setem6e FaHere Mode Postulated Effect of FaHeee Concleatees AC Power

• Dl/D2 Gage Panels
• Unrestrained vibration
• Potentialloss of DG engines
• To be addressed by SQUG '

isolators

• 12/22 DG Jacket IlX
• Loss of engine cooling
• To be addressed by SQUG
• Inadequate connection
• 480V MCCs I ABl. I AB2, IKI,
• less of trains ofvarious credited
• To be addressed by SQUG IL2,2K2, ITAI, ITA2,2LA2 * . Interaction and anchorage systems (e.g., SI, charging, FCUs)
• Panels 132 & 133 .* Loss of 4LV and 480V bus room
• Room cooling function determined to be
• Interaction cooling unnecessary
• Buses II,12,13 & 14
• No adverse clTect
• 480V MCCs IMl,1M2, IMAI,
• Anchorage
• No adverse effect
• Do not support credited equipment IMA2
• Anchorage
• Do not support credited equipment
• No adverse elTect
• 14 and 24 Inverters
• Panels 117 and 217
• Anchorage
• No adverse clTect
• Do not support credited equipment
• Pancis 313 and 3I33
• Anchorage
• No adverse efTect
• Do not support credited equipment
• Bus 22 Undervoltage Relays 2-
• Interaction
• No adverse cITect
• Do not support credited equipment 27A/B22-XA and 2-27B/B22-XA
• Interaction and anchorage
• Do not support credited equipment
• D2 DG Control Panel
• Loss ofI train ofemergency AC
• Interaction with wall-mounted power
• Outlier,to be addressed by mahntenance
• Bus 25 scalTolding
• Interaction with wall-hung
• Loss ofI train ofemergency AC
• Outlier, to be addressed by maintenance ladder power Miweltaneous
• Control Room Ceiling
• DitTuser panels falling
• Potential damage to pancis and threat =

To be addressed under SQUG to operators A-9

n

   \ A.2. SEISMIC ANALYSIS (G

A seismic margins assessment of the Prairie Island Nuclear Generating Plant was conducted ) between 1994 and 1996 to address the requirements of Generic Letter No. 88-20, Supplement 4, l , " Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities," dated June 1991. In accordance with Supplement 5 to Generic Letter 88-20, the assessment is equivalent to a reduced scope seismic margins assessment with an additional focus on a few key components. These components include relays, block walls, flat-bottom tanks, and other components identified during the plant walkdowns. The Prairie Island seismic margins assessment follows the guidance of EPRI NP-6041-SL with additional input from the internal events probabilistic risk assessment (PRA). This assessment included the following elements:

          . System, structure and component success path selection
          . Plant walkdowns e   Component screening

• Seismic margin assessment l l

The success paths for the Prairie Island seismic IPEEE were derived from the logic models l developed for the internal events PRA. Active components of all systems that could be available Q following a loss of offsite power were included on ine equipment list used during the walkdown and screening activities. With this approach, multiple potential success paths were identified for each safety function. The list was further supplemented with some passive components that were not modeled in the internal events PRA, such as tanks, heat exchangers, panels, cabinets, and support structures. The plant walkdowns were conducted following the guidelines for a seismic margin assessment presented in EPRI NP-6041-SL. The walkdown was performed to screen seismically rugged structures and components from further review, to identify the potential failure modes and system interactions for components that could not be screened from further review during the walkdown, and to obtain data for use in subsequent evaluations. The walkdown teams included systems analysts and seismic capability engineers. The walkdown screening was based on a seismic margin earthquake having a peak 5% damped spectral acceleration of 0.8g or less. This screening level is applicable to a focused scope plant and is conservative for a reduced scope plant. The results of the walkdowns were recorded on data sheets for future reference. Seismic issues requiring further review were identified. Evaluations were performed to further screen components from more detailed review. The component screening evaluations were performed following NUREG-1407 guidance for seismic margin assessment of reduced scope plants. Seismic input was based on the ground and in-structure h) m SSE response spectra. Equipment and vessels were screened using the criteria of the GIP. A-10

Structures and components outside the scope of the SQUG program for which the GIP criteria were not p applicable (e.g., civil structures, masonry walls, and NSSS components) were screened to the SSE V following the requirements of the USAR. Based on the walkdown and the screening evaluations, nearly all of the essential components were screened from further review. Many components were found acceptable to the SSE level by the Prairie l Island SQUG program or will be seismically uPr aded for the SSE by the SQUG program as part of l the actions to resolve the identified outliers.  : For those components that were not eliminated from further review during the walkdown and screening evaluations, systems analyses were used as an additional screen. These systems analyses considered the effect of failure of the components as well as determining whether other systems would be available to provide the critical safety functions needed during an accident following a seismic event. The remaining unscreened components are outliers, which include components with potential seismic interactions from wall-hung ladders and scaffolding. These outliers can be addressed by restraining or relocating the ladders through a maintenance activity. A.2.1 Plant Systems The plant systems considered in the seismic IPEEE are a subset of those considered in the IPE. An earthquake could reasonably produce a loss of offsite power (LOOP) and/or a small-break loss of coolant accident (SLOCA) initiating event. The seismic portion of the IPEEE focused on the frontline ( and support systems that would be called upon to prevent core damage for these two initiating events. Support systems that may not be seismically rugged, such as Instrument Air, were not credited (i.e., they were assumed to have failed as a result of the earthquake). The systems considered are listed below by the functims they support.

     . Reactivity Control e   Reactor Protection System
     . Reactor Coolant Pump Seal Cooling

• Chemical & Volume Control (Charging Pumps) e Component Cooling Water e Secondary IIcat Removal e Auxiliary Feedwater System

     . Short Term Inventory Control (Injection)
         . Safety Injection (High Head Injection Mode)
         . Residual Heat Removal (Low Head Injection Mode)
     . Long Term Inventory Control (Recirculation)
         . Safety Injection (High Head Recirculation Mode)

• Residual Heat Removal (Shutdown Cooling Mode)

Residual Heat Removal (Low Head Recirculation Mode) (

     . Containment Pressure Control
         . Containment Air Cooling System (FCUs)

A-11

e Containment Spray n . Important Support Systems U e Emergency Diesels and auxiliaries / 4kV l

• 480 VAC  !

               . 120 VAC                                                      -

l

• 125 VDC l

               . Cooling Water This section discusses the plant systems considered in the seismic IPEEE and the specific equipment        l comprising those systems.

A.2.1.1 Plant Frontline Systems Included in the IPEEE A discussion of the frontline plant systems included in the seismic IPEEE by functional area is included in this section. A brief discussion of those systems consid': red in the IPE but not credited in the IPEEE is also provided. A.2.1.1.1 Reactivity Control  ; Reactor Protection System (RPS) i l Instrumentation associated with the Reactor Protection System (RPS) monitors key plant parameters to determine whether the plant processes are within bounds ofimportant operating parameters associated l

 /7   with normal operation. A seismic event sufficiently large to cause equipment damage is expected to         I U    result in an RPS trip signal from a variety of causes. Further, the conditions postulated to exist in the plant as a result of a seismic event include a loss of off-site power or a small loss of coolant accident, either of which would cause a reactor trip. In response to these postulated conditions, rods are expected to be inserted quickly.

ATWS Mitigation System Actuation Circuitry (AMSAC) AMSAC is a means of control rod insertion triggered by separate and diverse logic from the RPS. The potential for a failure to trip coincident with an earthquake is considered to be oflow potential and AMSAC is not considered to be necessary in the seismic IPEEE. A.2.1.1.2 RCP Seal Cooling Chemical & Volume Control System (CVCS) The IPE considered two functions of CVCS: RCP seal injection, and Auxiliary Spray for the pressurizer. The system consists of three variable speed positive displacement pumps that take suction from the Volume Control Tank (VCT) or the Refueling Water Storage Tank (RWST) as a backup. In the IPEEE, no credit is taken for the system capacity for RCS make-up. Similarly, no credit is taken for the Auxiliary Spray function. The RCP seal cooling function requires one pump to be n'.ing suction from either the VCT or RWST and supplying flow through a seal injection filter to the RCP ( ) seals. A return path is also necessary through either the seal return heat exchanger to the VCT or through the seal return relief valve. A-12

Component Cooling (CC) Water System O The Component Cooling Water System provides an intermediate cooling system between the heat exchangers in potentially radioactive systems and the Cooling Water System. CC is a safeguards system consisting of two parallel loops each of which is composed of a pump, heat exchanger, and associated piping and instrumentation. The two loops are capable of being cross-connected at the suction and discharge of the pumps. Either loop also has the capability of being cross-connected with either loop in the opposite unit. The system provides cooling water to important components including the RHR heat exchangers, heat exchangers for the Containment Spray, Safety Injection and RHR pumps, and the RCP thermal barrier. A.2.1.1.3 Secondary Heat Removal Auxiliary Feedwater System (AFW) The function of the Auxiliary Feedwater System is to supply steam generator makeup for nonnal transients such as heatup and cooldown when the water demands are low or main feedwater is not available. The system also provides high pressure make-up to the steam generators under emergency conditions to assure a reactor coolant system heat sink is always available. The AFW system consists of two independent full capacity parallel trains. One train is equipped with a motor-driven pump while the other train is equipped with a steam turbine-driven pump. If needed, the motor-driven AFW pump from the opposite unit can be aligned for makeup. The steam supply for the turbine-driven pump can g) D be supplied from either steam generator. The plant's design allows both pumps to take suction from either the condensate storage tanks or the cooling water system. For the seismic IPEEE, no credit is taken for the condensate storage tanks since they are not seismically designed. The pumps can be aligned to take suction from the cc,oling water system which is fed from the Mississippi River. The success criteria for adequate AFW flow is one of the pump trains for each unit supplying design capacity flow to either one of the two steam generators. Main Feedwater System Normally, the Main Feedwater System provides the cooling water Dow to the steam generators to remove the heat from the Reactor Coolant System. Main Feedwater is not available following a seismic event because of the postulated loss of off-site power. Therefore, no credit is taken for this system in the seismic IPEEE. A.2.1.1.4 Short Term Inventory Control (Injection Mode) Safety Iniection (High Head Injection) The primary function of the Safety Injection (SI) system is to remove stored energy and decay heat from the reactor core following a loss of primary or secondary coolant. The system has two operating modes: High Head injection mode in which water from stored sources is injected into the RCS, and High Head Recirculation mode in which water from the containment sump (collected from the loss of coolant breach) is returned to the RCS. For Short Term Inventory Control, SI responds in the Injection mode, which is described below. l i A-13 1

l The Si system consists of two independent trains. Each train consists of a pump with associated q suction and discharge valves. The pumps are motor-driven centrifugal pumps with a capacity of V approximately 700 gpm at 1300 psig, and a shutoff head of approximately 2170 psig . The trains initially take suction from one of from the highly concentrated boric acid storage tanks (BAST), then automatically switch to the Refueling Water Storage Tank (RWST) when the BAST reaches its low level setpoint. The SI Injection mode ends when the RWST reaches its low level setpoint (33%). At this point, the suction of one train of the SI pumps can be manually transferred to the containment sump B via the RIIR pump discharge. This marks the beginning of the Long Term Inventory Control i phase and the Iligh liead Recirculation mode of St. Pressurizer Power Operated Relief Valves (PORV)s There are two pressurizer PORV trains per unit. These valves, when open, allow flow from the top of the Pressurizer to the Pressurizer Pressure Relief Tank. Each train consists of a motor operated block valve and an air operated relief valve. Each PORV is an air operated, fail-closed, valve. The incoming air supply line to each PORV is equipped with an air accumulator and a check valve to allow approximately 15 valve openings should instrument air be lost. Since instrument air is assumed to be unavailable, pressurizer PORVs and bleed and feed operations are not credited in the seismic IPEEE. Residual Heat Removal (Low Head iniection) The Residual 11 eat Removal (RI1R) system has a similar purpose to that of the SI system, except that g RIIR operates when the RCS has significantly depressurized. The system has three modes of , U operation: Low IIead Injection in which water from stored sources is injected into the RCS, Low liead Recirculation in which water from the containment sump (collected from the loss of coolant breach) is returned to the RCS, and Shutdown Cooling in which RCS decay heat is rejected through the RiiR heat exchangers. For the seismic IPEEE, in which it is postulated that the earthquake has caused a loss j of off-site power or a small loss of coolant accident, the injection mode is not considered since the j RCS can not be depressurized easily without instrument air which is assumed to be unavailable  ; following a seismic event. Instead, R11R supports the Long Term Inventory Control function through l the Low 11ead Recirculation and Shutdown Cooling modes, which are described in the following i section. A.2.1.1.5 Long Term Inventory Control (Recirculation) Safety iniection (High Head Recirculation)  : The SI system, and its liigh Head injection mode of operation, was described in the previous section. , In the Long Term Inventory Control function, the SI system transitions to its liigh liead Recirculation mode of operation. In this mode, the Si pump suction source is transferred from the RWST (now depleted) to the discharge line of the RIIR pumps which are drawing on the collected RCS coolant j (spilled from the small loss of coolant break location) in containment sump B. The water that collects in containment sump B is drawn by the RIIR pumps and cooled through the associated RIIR heat exchanger before the SI pumps inject it back into the RCS. L A-14

Residual Heat Removal (Low Head Recirculation, Shutdown Cooling) As described above, the RHR system has two modes of operation that could be called upon in responding to the seismic event: Low Head Recirculation and Shutdown Cooling. To support these i modes of operation, the RCS must be depressurized to effect transition from SI to RHR. The RHR system is also used to provide suction for the SI and Containment Spray systems when they are in the recirculation mode of operation. The RHR system is divided into two trains. Each train contains one pump and one heat exchanger. Each pump has a rated capacity of approximately 2000 gpm at 120 psig, and a shutoff head of approximately 140 psig. Each train of RHR has a dedicated injection path to the reactor vessel. In recirculation mode, RHR pump suction is aligned to containment sump B which is a collection point for water spilled from the postulated small loss of coolant accident break location. Sump fluid is pumped through the RHR Heat Exchangers (cooled by the Component Cooling Water System) and then directed into the reactor vessel through the injection nozzles. Under the conditions postulated for the seismic IPEEE, the RHR Low Head Recirculation mode may not be available. Decay heat removal would be accomplished through S1 (injection and recirculation) and then RHR in the Shutdown Cooling mode which is described below. The Shutdown Cooling mode of the RHR system is used to provide decay heat removal for small

LOCA events and steam generator tube ruptures. After the RCS has depressurized below pump shutoff head pressure, the RHR pumps take suction on the RCS hot legs and discharge through the associated i

O V heat exchangers back into the RCS at the loop B cold leg. The success criteria for the Shutdown Cooling mode of RHR is for one train to take suction from the RCS hot legs, transfer heat to the Component Cooling Water system through the associated heat exchanger and retum the fluid to the RCS through the loop B cold leg. The availability of safety injection in recirculating mode is a backup l should depressurization not occur. In this event, the SDC mode of RHR is unnecessary. A 2.1.1.6 Containment Pressure Control Containment Air Cooling System Adequate heat removal capability for the containment is provided by two separate, full capacity, engineered safeguards systems: Containment Air Cooling and Containment Spray. These systems involve different engineering principles and serve as independent backup for one another. . Containment Air Cooling consists primarily of four Fan Coil Units (FCUs) within the containment vessel designed into two independent trains. Each train consists of two condensing units, two I circulating fans and associated ductwork and dampers. All FCUs are operating under normal conditions, receiving cooling water flow from the non-safety chilled water system. Under emergency j conditions, the cooling medium switches to the safety related cooling water system (CL). To successfully respond to the conditions postulated following a seismic event, the Containment Air Cooling system must have two of four FCUs available (taking no credit for Containment Spray). A-15

Containment Sprav [ The Containment Spray system cools the containment environment under LOCA or steamline break accident conditions by spraying through spray nozzles located at the containment dome. The system is automatically initiated by a "P" signal which is generated either manually or by containment pressure reaching 23 psig. The system consists of two independent parallel trains. Each train consists of a motor-driven pump, associated piping and valves, and a spray ring header attached to the containment dome. Each train takes suction from both the borated refueling water sway tank (RWST) and a caustic addition standpipe. Each pump is capable of discharging caustic borated flow of approximately 1300 gpm at 220 psig to an independent spray header. The success criteria for the system is one train fully operational (taking no credit for the containment FCUs). Containment Spray need not be credited for response to post-earthquake conditions postulated here if Containment FCU are available. A.2.1.2 Support Systems Included in the IPF/IPEEE Off-Site AC Power The seismic events considered for the IPEEE are those that are sufficiently large to cause a loss of off-site power. If the seismic event does not cause a loss of off-site power, sufficient systems are assumed to remain available such that the potential for core damage could be considered to be bounded by the internal events PRA. On-Site AC Power t C- The on-site AC power system is made up of emergency diesel generators (two per unit) and the plant AC distribution system. (No credit is given in the IPEEE for operation of two non-safeguards diesel generators or the service building AC distribution system.) The AC distribution system is made up of six 4kV buses per unit feeding the large motors, and various 480V load centers. Loss of voltage or degraded voltage on the essential buses will stan the emergency diesel generators and initiate load shedding to allow the diesels to supply their respective buses. The Unit I and 2 emergency 4KV buses can also be cross-tied to allow the train-related diesel generator on the opposite unit to supply a bus with a failed diesel generator. DC Power and DC Distribution System The purpose of this system is to supply an adequate power supply for vital loads such as instrumentation, reactor protection,4160 V switchgear and EDG control power. No credit is given for the non-safeguards service building DC system. During emergency situations, the station batteries and the DC distribution system are designed to provide power to instruments and controls needed to place the plant in a safe shutdown condition following a loss of all AC power. Each unit has two complete and separate 125 VDC distribution systems. Each unit has two battery trains and associated power distribution equipment. The combined output of the battery and the battery charger is supplied to the main distribution panel. Individual loads and smaller distribution panels are

 ]

C serviced from the main distribution panel. Non-safeguard equipment is supplied by either battery as appropriate to balance the DC loading on each battery. The success criteria for the DC powe: system is one train of DC supplied to plant components for two hours through the batteries. A-16

Instrument Air

 /   The Instrument Air system provides dry compressed air to various plant instruments and controls. The system also provides compressed air to operate control valves within various systems. For the seismic IPEEE, the Instrument Air system is conservatively ignored since system piping and supports are distributed throughout the plant and assessment of piping integrity and secondary interactions as a      l result of the earthquake motion has not been performed.

Cooling Water (CL) , The primary functions of the Cooling Water system are as follows: provide an adequate cooling water supply for plant equipment loads, provide a cooling water supply to all safeguards equipment during nromal and emergency operating conditions, and provide an alternate feedwater supply to the steam generators. Cooling Water is a safeguards system consisting of five pumps feeding a ring header shared by both units. Assuming a loss of offsite power as a result of a seismic event, three of the five pumps (two diesel-driven and one motor-driven) are available to support Cooling Water loads. The Cooling Water header can be automatically or manually separated into two redundant supply headers (headers A and B). The normal water supply for the CL system is from the circulating water pump bays in the screenhouse. The three vertical safeguards pumps take a suction on an emergency bay and discharge to the common CL header. The emergency bay receives water normally from the circulating water bays through sluice gates, but also has a separate emergency supply intake pipe (36" diameter) which ( supplies water directly from the Mississippi River. The emergency intake pipe would be required only if the normal path from the Mississippi River through the outer screenhouse were to become blocked. If such blockage were postulated, the cooling water supply would be limited to the inventory in the intake canal plus the flow through the 36" safeguards pipe. As the flow required for two-pump operation exceeds the capacity of the safeguards pipe, operator action to reduce cooling water loads is I required. These actions include isolating turbine building loads and containment fan coil units. Given the size of the intake canal, more than four hours are available to reduce and manage Cooling Water loads undet these conditions. The success criteria for the CL system varies depending on the initiating event. For the case of a loss of offsite power (assumed in the case of an earthquake), a single CL pump is required. For a LOCA, a single pump is required assuming that at least one of the CL header isolation valves closes. 120V Instrument AC Power The 120 V Instrument AC system supplies highly regulated single-phase AC power to plant instrumentation. The system as modeled in the IPE consists of four static inverters which supply four  ! distribution panels, each of which supply power to a separate channel ofinstrumentation. The static l inverters normally are supplied with 480 VAC power from the safeguards 480 V buses. This power j supply is backed up by the plant batteries. The inverters then provide an uninterruptable, regulated 120 ! VAC supply to their corresponding instrument distribution panel. pJ A-17 , i

The distribution panels, also called instrument buses, have two supply breakers which are mechanically p interlocked such that only one can be shut at a time. The power supplies are either the associated C/ inverter or panel 117 (217 for Unit 2) which is an unregulated 120 V source. SI Signal The safety injection signal ("S" signal) is sent when conditions indicative of a loss of coolant accident exist. The purpose of the signal is to initiate automatic features in the plant designed to prevent core damage and/or mitigate the effects of the accident. The safety injection signal is initiated when any of the following conditions exist:

• Pressurizer pressure less than 1815 psig,

       . Containment pressure greater than 4 psig, e   Main steamline pressure in either line less than 500 psig,                                        j
       . Manual actuation.                                                                                 l The safety injection signal initiates many functions throughout the plant. Some of the more important functions are:

• Reactor Trip signal,

       . Start signal to all ECCS pumps and various motor-operated valves receive open or close signals    j to align ECCS for injection, 1

m . Start signal to both Emergency Diesel Generators, ) b . Containment FCUs shifted to slow speed and realign to discharge to the containment dome, e Containment FCUs cooling medium is realigned to Cooling Water, e Start signal to the Auxiliary Feedwater pumps,

       . Cooling water headers split and diesel cooling water pumps receive a start signal.

The seismic IPEEE may rely on some of the automatic actuation features caused by an S signal in response to an earthquake-induced plant condition. However, these features can also be initiated by operator actions in some cases. These situations are noted when reliance has been shifted from automatic to operator-initiated actions. Safevuards Chilled Water The Safeguards Chilled Water system consists of two independent trains. Each train is a closed loop chilled water system that consists of a centrifugal chiller, a chilled water pump, and associated piping, valves and unit coolers. Each train supplies room cooling to its associated safeguards equipment including 4160 V and 480 V switchgear, the relay room and computer room, control room air handler, and the RHR pits. Supply and return header cross-connect valves allow either chilled water pump and chiller to supply both trains. The cross-connect valves are automatically shut on an S signal to ensure system reliability. O The success criteria for the system is for one chiller and chilled water pump in a train to be running and U supplying chilled water to the Unit 14160 V safeguards switchgear room coolers. Analyses were conducted for the 4 kV bus rooms which determined that the critical temperature is reached within one A-18

i j to two hours following loss of chilled water. Operator actions (i.e., opening the door to the rooms to allow natural circulation to occur) are proceduralized to prevent excedence of the critical temperature. j 1 A.2.1.3 Supporting Components Included in the IPEEE i The seismic IPEEE included distributed systems whose failure could cause a loss of function of the systems listed above, such as piping, cable trays, and conduit. The HVAC ducting need not function to ensure performance of essential systems, but the potential for the HVAC ducting to interfere with other

systems during an earthquake was included in the seismic IPEEE.

1 } A.2.2 Plant Walkdown The objectives of the plant seismic walkdowns were (1) to identify any equipment having sufficiently high seismic capacity that no further review was needed, (2) to identify the potential failure modes and 3 system interactions for equipment that could not be screened from further review, and (3) to obtain data l on equipment and structures for use in detailed evaluations of the potential failure modes and system interactions. Preparation for the initial plant walkdown is described in Section A.2.2.1.- General descriptions of the initial and final plant walkdowns, including procedures and documentation, are l presented in Sections A.2.2.2 and A.2.2.3. Significant walkdown findings are identified in Section A.2.2.4. i A.2.2.1 Pre-Walkdown Preparation  ! Activities performed prior to the initial plant walkdown included (1) information collection and review, (2) equipment list review, (3) identification of equipment locations, and (4) walkdown data sheet preparation. Information Collection Information relevant to the seismic IPEEE was collected. The following categories of plant documentation were obtained prior to and during the plant walkdowns: e Updated Safety Analysis Report (USAR)

          . Structural, architectural, and equipment layout drawings

• Equipment anchorage drawings
• Drawings for selected equipment components e Specifications for construction of civil structures
• Seismic criteria and analysis reports for building structures e Geotechnical investigation reports

          . I & E Bulletin 80-11 documentation on masonry wall seismic qualification

• Design basis evaluation report on the NSSS Components This documentation was reviewed prior to the walkdown to obtain an understanding of the plant configuration, design, and construction, vital safety systems, structure response characteristics, and structure and equipment capabilities.

A-19

A preliminary listing of all equipment included in the IPE systems model and used for the seismic p IPEEE was developed by NSP. Additions and deletions of selected equipment components were V suggested by seismic analysts based upon past experience in seismic margins assessment. Further revisions were identified during the walkdown. The essential equipment that was considered in the seismic margins assessment is listed in Tabics A.2.3-1 and A.2.4-1. Components included in the equipment list were located on the mechanical layout drawings to the extent possible. Prior knowledge of equipment locations helped in planning routes through the plant during the walkdown and identification of components in the field. NSP walkdown team members were highly familiar with equipment locations, thus greatly expediting the walkdown, Walkdown data sheets were prepared for each of the components on the equipment list. To the extent possible, general information was entered into these data sheets by members of the walkdown team before the walkdown. Such information included the equipment class, description, identification number, location (building, floor elevation, and room number), and manufacturer and model number.  ! A.2.2.2 Initial Plant Walkdown The initial plant walkdowns were conducted in the Unit I containment in June 1994 and in the balance of the plant during November 1994. The June 1994 walkdown was condueted by one walkdown team, while the November 1994 walkdown was performed by two teams. Each walkdown team consisted of two seismic capability engineers and at least one plant engineer. The seismic capability engineers were experienced in the seismic evaluation structures and equipment. The plant engineers participating in the walkdowns were familiar with the functions of the various plant systems, the component layout in the plant, as well as with the PRA model. Walkdowns in November 1994 were conducted for components in the Auxiliary Building, Turbine Building, Screenhouse, D5/D6 Building, and the Intake Screenhouse. These buildings and their l separation gaps, where accessible, were reviewed. In addition, components in the yard outside of the buildings as well as tanks housed in buried concrete vaults were reviewed. Walkdowns were not ) performed for components with'n the Unit 2 containment structure as the plant was in operation. Walkdown within the Unit 2 containment was performed in June 1995 as described in Section A.2.2.3. A.2.2.2.1 Walkdown Procedures 1 The walkdown followed the procedures recommended by EPRI NP-6041-SL. Walkdown screening of I components was conservatively performed following the recommendations of EPRI NP-6041-SL for a j review level earthquake having a peak 5% damped spectral acceleration of 0.8g or less. Components were surveyed in the walkdown to ensure that caveats implicit in the screening criteria were satisfied. Structures Data required for screening or seismic margin assessment of civil structures are typically obtained from design drawings rather than from walkdowns. A complete set of structural drawings was reviewed to / develop a general understanding of the building construction and configuration as well to identify any C data to be obtained in the walkdown. The walkdown was performed to (1) verify that the structures are A-20

generally in conformance with the design drawings, (2) identify any gross deficiencies that might affect (] the structure capacities, and (3) confirm that separations between the buildings are consistent with the

, V  design drawings.

Masonry Walls Masonry walls supporting or in proximity to essential equipment were identified on equipment walkdown data sheets as potential seismic interaction concems. Documentation on the Prairie Island masonry wall evaluations performed in response to USNRC I&E Bulletin 80-11 was reviewed to obtain an understanding of the block wall construction, configuration, and seismic capacity. Equipment and Vessels The initial plant walkdown surveyed components in accessible areas. Detailed inspections were performed for numerous components. Other components, while not inspected in detail, were  ; determined to be similar to those for which detailed inspections were performed. Sufficient reviews I were performed to establish that similarities exist in terms of component construction and anchorage. J Any component specific features, such as anchorage details or system interaction issues, were  ! recorded. I Key elements of the component walkdowns included review of component configuration and construction, anchorage, and potential system interactions. These reviews followed the walkdown guidelines of EPRI NP-6041-SL. j p V Configuration and construction details of the components and their supports were reviewed to ensure l structural integrity and post-earthquake functionality. Following checklists on the walkdown data sheets, components were inspected to ensure that they possessed adequate seismic design features. i i These included attributes such as adequate stiffness and strength of seismic load paths and adequate 1 attachment for appurtenances. Components were also inspected to identify any seismic vulnerabilities, such as unreinforced cabinet cutouts, unrestrained vibration isolators, and excessive component or attachment weight. Inspection of component anchorage included verifying that the load paths have adequate stiffness and identification of any specific concerns, such as high shims or excessive concrete cracking in the vicinity of the anchor. Screening of anchorage strength for most components was deferred until after the initial plant walkdown, at which time SQUG component anchorage calculations were reviewed and additional quantitative evaluations were performed. Data on component anchorage were recorded for use in these evaluations. Inspection was performed to identify any systems interaction concerns associated with proximity, Class II-over-Class I interactions, and spray and flooding. Essential components in close proximity to adjacent objects were reviewed for potential damage due to relative seismic motion. Only soft targets, such as gauges or small tubing, were considered vulnerable to impact damage. Electrical cabinets

  -  potentially containing essential relays were also identified for possible impact induced relay chatter.

Any Class II-over-Class I interactions associated with a non-essential component falling on an essential component were identified. Potential Class II-over-Class I interactions include failure of A-21

concrete block walls or ceiling systems. Any credible sources of spray or flooding that could impair O the function of an essential component were identified. Potential sources of spray and flooding include failure of wet fire water piping with threaded joints or mechanical couplings and non-essential tanks. If such sources were identified, further review was performed to identify any mitigating features, such as spray shields or floor drains. NUREG-1407 guidance for relay evaluation is to follow SQUG procedures for a plant such as Prairie Island that is required to address USI A-46 [U.S. Nuclear Regulatory Commission,1987). Consequently, no relay walkdown was performed for the Prairie Island IPEEE, but instead was deferred to the SQUG review. Distributed Systems Distributed systems reviewed in the walkdown included piping, cable trays, and conduit. General surveys of these systems were performed during the walkdowns to identify the presence of any seismic vulnerabilities. HVAC ductwork'is not required for room cooling. However, HVAC duct work in proximity to essential components were reviewed for potential system interaction concerns. A.2.2.2.2 Walkdown Documentation Documentation of the walkdown consisted of data sheets, photographs, and field notes for the equipment and structures surveyed. Walkdown data sheets following the formats recommended in EPRI NP-6041-SL were used. These data sheets vary according to the generic equipment component category. They contain checklists of seismic adequacy issues to be addressed in the inspection of a component and the data sheets include space to record additional notes and sketches. Photographs were taken to supplement any notes or details taken during the walkdown. For a component, photos of the overall configuration, anchorage, and any other notable features or systems interactions were typically taken. A.2.2.3 Final Plant Walkdowns Subsequent walkdowns were conducted in June 1995 and in October 1996. Both walkdowns were performed by a team consisting of two seismic capability engineers and at least one plant engineer. Components that were reviewed in the June 1995 walkdown included those within the Unit 2 containment, which was in an outage at that time. In the final walkdown during October 1996, reviews were conducted to gather additional data for seismic evaluation and to resolve certain open issues. A.2.2.4 Findings from the Plant Walkdowns Significant findings from the plant walkdowns are summarized below. The potential seismic concerns discussed in Section A.2.4. Structures Building separation gaps were reviewed in the field, where accessible. The gaps appeared consistent with the details noted on the structural drawings. A-22

Concrete Bloch Walls Block walls posing potential seismic interaction hazards to essential equipment were typically found to be safety- related walls previously evaluated in the I&E 80-11 program. Some non-safety related walls were identified as interaction concerns. These non-safety related walls were addressed by comparisons to bounding safety-related walls. Mechanical Equipment CV-31059 and CV - 31060 : Trin and Throttle Valves for 11 and 22 Turbine Driven Auxiliary Feedwater Pumns. Each valve has a trip device which may be vibration- sensitive. An earthquake-induced trip wasjudged to be credible. CV-39401 and CV-39409 FCU .#11 FCU Cooline Water Sunnly and #12/#14 FCU Cooline Water Return Valves: Seismic interactions were identified since the valve operators contact adjacent conduit. Failure of the solenoid connection could occur due to relative displacements between the valves and I conduit. CV-39411 #11/#13 FCU Cooline Water Return Valve: A limit switch on the valve operator touches the limit switch for an adjacent valve mounted on another pipe. Seismic- induced motion may damage l the limit switch. 121 and 122 Control Room Chillers: These chillers are supported by unrestrained vibration isolators.  ! 1 12 and 22 Diesel Driven Cooline Water Pumns and 121 Cooline Water Pumn: Anchor bolts for these pumps do not satisfy minimum edge distance requirements and the vertical shaft lengths exceed the l maximum length identified by the component caveats.

Electrical Equipment 12 and 22 Batteries

Missing spacers were noted in the battery racks.

D1 and D2 Diesel Generator Gace Panels: Both panels are supported with very flexible, unrestrained i vibration isolators. D2 Diesel Generator Control Panel: Scaffolding was found to be hung on wall hooks behind the panel. Sbid the scaffolding fall off the hooks due to earthquake motion, impact with the control panel could l cause relay chatter. Damage to the panel and its anchorage due to impact by the scaffolding is unlikely. DC Panels 11.12. and 22: Bases of these panels are elevated above the floor which would result in seisniic-induced bending stresses in the anchorage. 4160V Bus 25: A wall-mounted ladder was found to be located behind the cabinet. Should the ladder fall off the wall-hooks due to earthquake motion, impact with the bus cabinet could cause relay chatter. Damage to the cabinet and its anchorage by the ladder is unlikely. U A-23

MCC 1 Kl: "RIIR Lifting Block Fixtures" were found to be mounted on the wall behind the MCC. p Should these items fall off the wall-hooks, impact with the MCC could cause relay chatter. Damage to Q the MCC and its anchorage due to impact is unlikely. MCC IL2 : A rod hung pipe is located close to the cables feeding into the top of the MCC. The pipe could swing due to earthquake motion and strike the cables, potentially resulting in relay chatter. Damage to the MCC cabinet and its anchorage is unlikely. l MCC 2K2: A rod hung pipe is located close to the MCC cabinet. The pipe could swing due to earthquake motion. Impact between the pipe and the MCC could cause relay chatter. Damage to the MCC and its anchorage is unlikely. l l MCC 1 TAI and MCC ITA2: Both MCCs are supponed on high shims which will lead to seismic- { induced anchor bolt bending. l MCC 2LA2: The welded anchorage is very minimal. Tanks and Heat Exchangers l 12 and 22 Jacket Heat Exchancers for 12 and 22 Diesel Cooline Water Pump Encines: No structural connection between the heat exchanger vessel and the saddle supports was observed. I 1.12. and 22 Condensate Storace Tanks: Anchorage for the 12 and 22 condensate storage tanks includes epoxied anchor bolts, which are considered outliers by the GIP criteria. Anchorage for the 11 i f') condensate storage tank includes a combination of cast-in-place anchor bolts and concrete expansion anchors. The expansion anchors may not have adequate seismic capacity. l Distributed Systems The essential piping, cable trays, conduit, and HVAC ductwork were found to be seismically adequate. Other Seismic vulnerabilities were identified for the control room ceiling. The diffuser panels represent falling hazards which may strike the main control panels. 4 Additional generic observations included potential seismic interaction hazards due to overhead fluorescent lights hung with open S-hooks and ladders hung on wall hooks. Should either the lights or the ladders fall due to earthquake motion, impact with the essential component could cause relay chatter. Damage to the components and their anchorage is unlikely. The open S-hooks could be corrected by crimping them closed. This activity was identified as part of the outlier resolutions of the SQUG program. Therefore, no further review was conducted for the overhead lights. Components with interactions from wall hung ladders were identified for funher review. The placement of the ladders appeared to be transient as they were not always found in the same locations in subsequent walkdowns. A b A-24

A.2.3 Component Screenine

 /Q Components identified in the walkdowns to be seismically rugged were screened from further review U  following the walkdown guidelines of EPRI NP-6041-SL. This walkdown screening was conservatively performed using focused scope plant criteria.

Following issuance of Supplement 5 to Generic Letter 88-20, further component and structure screening was performed following NUREG 1407 guidelines for reduced scope plants. Seismic input for this screening consisted of the ground and in-structure SSE response spectra at 0.12g. Equipment 4 and vessels were screened using the criteria of the GIP. Component screening used the results of the SQUG program supplemented with quantitative evaluations of bounding cases. These bounding calculations were typically performed using conservative approximations and input in order to screen components from further detailed analysis. Structures and components outside the SQUG scope for which the GIP criteria are not applicable (e.g., civil structures, masonry walls, and NSSS components) were screened to the SSE level using USAR requirements. A.2.3.1 Structure Screening The following structures were found not to need more detailed analyses: A. ShieldBuildings B. Containment Vessels C. Auxiliary Building D. Portions ofthe Turbine Building housing Class 1 equipment E. Screenhouse F. D5/D6 Building l 4 < All of the above structures are identified as Class I structures in the Prairie Island USAR. All were

                                                                                                             )

designed using dynamic analyses for an SSE with a peak ground acceleration of 0.12g. The auxiliary l building, turbine building (areas housing Class I equipment), screenhouse, and the D5/D6 building all I have seismic load resisting systems comprised of reinforced concrete shear walls, floor diaphragms, and foundations. The shield buildings are reinforced concrete each consisting of a cylindrical shell capped with a dome and supported on a reinfoiced concrete mat foundation. The Unit 1 and Unit 2 containment vessels are free-standing steel containment structures which are embedded in the foundation mats. Also, a review of the building structural drawings identified no significant seismic vulnerabilities. Thus, the structures were screened from further review based on the design basis USAR criteria. A.2.3.2 Concrete Block Wall Screening Masonry walls identified in the walkdown to pose credible seismic interaction hazards to essential equipment typically consisted of safety related walls. A few non-safety related walls were identified as seismic interaction concerns. These non-safety walls are bounded by other safety related walls. The

p. safety-related walls were previously evaluated and upgraded for seismic adequacy to the SSE level in d the I&E 80-11 program. Since masonry walls are outside of the SQUG program scope and the GIP is not applicable, they were consequently screened using SSE seismic input and the requirements of the A-25

USAR. Screening of the masonry walls was based on a review of the documentation for the I&E 80-11 7q evaluations. Based on this review, the masonry walls were concluded to be seismically adequate to the d SSE and were screened from further review. A.2.3.3 Component Screening Components that were screened fra further review are listed in Table A.2.3-1. Components on this . table have been screened at the SSE or higher. General comments on these components are listed I below. The remaining components, for which further analysis was needed, are discussed in greater detail in Section A.2.4. Mechanical Equipment Most mechanical equipment was verified to be adequate to retain structural integrity and post- , earthquake functionality based on the walkdowns. Most mechanical components could be screened from further review based on the results of the SQUG program. For components within the SQUG scope, bounding cases were identified for the different equipment categories and the corresponding SQUG evaluations were reviewed to confirm concurrence between the IPEEE and SQUG assessments. For components outside of the SQUG program, anchorage evaluations were performed using bounding cases of different generic component categories using the criteria of the GIP. For example, horizontal pumps were screened by evaluating the anchorage of a bounding case pump. The bounding pump anchorage was found to be adequate. Consequently, all of the horizontal pumps enveloped by the bounding case were screened from further review. A few mechanical components were flagged for seismic concerns due to system interactions or conditions not satisfying the equipment screening caveats as noted in the walkdowns. These components were identified for further review. Electrical Equipment Most electrical equipment was verified to be adequate to retain structural integrity and post-earthquake functionality based on the walkdowns. Most of the electrical components were screened from further , review based on the results of the SQUG program. Electrical equipment identified for 'urther review included components with seismic interaction concerns or that had conditions which did not satisfy the equipment screening caveats. Tanks and Heat Exchangers Most tanks and heat exchangers were screened from further review based on the results of the SQUG program, the walkdowns, and bounding calculations. For vessels outside of the SQUG program, evaluations of bounding cases were performed using the criteria of the GIP. For example, the vertical tanks outside the scope of SQUG were grouped together. Evaluating and confirming the adequacy of the bounding case allowed for all of the tanks in the group to be screened from further review. p G A-26

Distributed Systems (O Walkdown of representative lines verified that essential piping is seismically adequate and could be screened from further review. With the exception of a few valves with identified system interaction concerns, the valm were screened from further review based on the walkdown data. Cable trays and conduit were verified to be seismically adequate based on walkdowns of representative samples and the results of the SQUG evaluation. The SQUG evaluation included the selection and review of representative bounding cases. These bounding cases were found to be adequate and, thus, cable trays and conduit were screened from further review. HVAC ducting is not required for room cooling in support of essential systems for IPEEE. Therefore, HVAC ductwork was only reviewed as potential seismic system interaction concerns for essential equipment. HVAC ductwork is typically rod-hung and was found to be seismically adequate based on the walkdowns of representative samples. A.2.3.4 Relay Screening Because Prairie Island is subject to USI A-46 [4] requirements, the evaluation of relay chatter at Prairie Island was conducted following SQUG procedures. The Prairie Island SQUG Program has determined that Prairie lsland does have some relays that are considered to have low seismic ruggedness. This is documented in the Prairie Island USI A-46 report [ 25]. According to NUREG- 1407, plants under the Reduced Scope bin have no actions to consider for the IPEEE; i.e., the USI A-46 review is considered sufficient. Plants in the Focused Scope bin also follow the USI A-46 program, unless low seismic ruggedness relays are discovered as part of USI A-46. The evaluation of relay chatter for Prairie Lland was therefore expanded to include relays outside of the scope or the SQUG program but within the scope of the IPEEE, consistent with Section 3.2.4.2 of NUREG-1407. An initial identification and functional screening of the relays was done in order to acquire an understanding of the potential elfect of relay chatter. The evaluation for the seismic IPEEE proceeded by identifying the relays appropriate for the IPEEE models, beginning with the IPE. The seismic IPEEE considers the potential for a both a loss of offsite power and small LOCA. The IPEEE models were configured to describe the availability of plant systems and components under these postulated conditions following the seismic event. Table A.2.3-2 provides the summary of relays credited in the seismic IPEEE but not in the SQUG Relay Evaluation Report [25]. The set of relays credited by the seismic IPEEE that are not in the SQUG program were reviewed to determine if any were potential outliers from the list of Low Ruggedness Relays in EPRI NP-7148-SL, Appendix E [13]. None of these relays is on the low ruggedness relay list. Therefore, of the relays credited in the seismic IPEEE, most relays are within the scope of the SQUG program, with all remaining relays having been determined to not be on the " bad actors" list. Ow k A-27 i

l l Table A.2.3-1 Seismically Rugged Components a f \ l COMPONENT IDNO SYSTEM ,1 11 INVERTER 11 INVERTER AC 120 121NVERTER 121NVERTER AC 120 13 INVERTER 13 INVERTER AC 120 17tNVERTER 171NVERTER AC 120 181NVERTER 1BINVERTER AC 120 PANEL 111 PNL 111 AC 120 PANEL 112 PNL 112 AC 120 PANEL 113 PNL 113 AC 120 PANEL 114 PNL 114 AC 120 PANEL 134 PNL 134 AC 230 PANEL 134 PHASE A 240/120V TRANSFORMER PNL 134/A XFMR AC 230 PANEL 134 PHASE B 240/120V TRANSFORMER PNL 134/B XFMR AC 230 PANEL 134 PHASE C 240/120V TRANSFORMER PNL 134/C XFMR AC 230 PANEL 135 PNL 135 AC 230 PANEL 135 PHASE A 240/120V TRANSFORMER PNL 135/A XFMR AC 230 PANEL 135 PHASE B 240/120V TRANSFORMER PNL 135/B XFMR AC 230 PANEL 135 PHASE C 240/120V TRANSFORMER PNL 135/C XFMR AC 230 PANEL 136 PNL 136 AC 230 PANEL 136 PHASE A 240/120V TRANSFORMER PNL 136/A XFMR AC 230 PANEL 136 PHASE B 240/120V TRANSFORMER PNL 136/B XFMR AC 230 PANEL 136 PHASE C 240/120V TRANSFORMER PNL 136/C XFMR AC 230 PANEL 137 PNL 137 AC 230 PANEL 137 PHASE A 240/120V TRANSFORMER PNL 137/A XFMR AC 230 PANEL 137 PHASE B 240/120V TRANSFORMER PNL 137/B XFMR AC 230 PANEL 137 PHASE C 240/120V TRANSFORMER PNL 137/C XFMR AC 230 BREAKER POSITION INDICATOR 52A/16-4 52 A/16-4 AC 4160 BREAKER POSITION RELAY 52A/15-4 52A/15 4 AC 4160 BUS 15 BUS 15 AC 4160 BUS 15 LOAD SEQUENCE CABINET BUS 15 CABINET AC 4160 BUS 15 LOGIC RELAY CABINET AC 4160 BUS 16 BUS 16 AC 4160 BUS 16 LOAD SEQUENCE CABINET BUS 16 CABINET AC 4160 BUS 16 LOGIC RELAY CABINET AC 4160 BUS 111480V BUS 111M AC 480 BUS 112 480V BUS 112M AC 480 BUS 121480V BUS 121 AC 480 BUS 122 480V BUS 122 AC 480 MCC 1 A BUS 1 MCC 1 A BUS 1 AC 480 MCC 1 A BUS 2 MCC 1 A BUS 2 AC 480 MCC 1 AC BUS 1 MCC 1 AC BUS 1 AC 4BO MCC 1 AC BUS 2 MCC 1 AC BUS 2 AC 480 MCC 1K BUS 2 MCC 1K BUS 2 AC 480 MCC 1KA2 MCC 1KA2 AC 480 MCC ll BUS 1 MCC 1L BUS 1 AC 480 MCC 11 A1 MCC 1LA1 AC 480 MCC 1LA2 MCC 1LA2 AC 480 MCC IT BUS 1 MCC 1T BUS 1 AC 480 MCC 1T BUS 2 MCC IT BUS 2 AC 480 MCC1X1 MCC 1X) AC 480 A-28

Table A.2.3-1, csntinu:d Seistnically Rugged Components , COMPONENT IDNO SYSTEM { MCC 1X2 MCC 1X2 AC 480 { l 11 SG LEVEL TRANSMITTER 1LT-461 1 LT-461 AF F l 11 SG LEVEL TRANSMITTER ILT-462 1 LT-462 AF 11 SG LEVEL TRANSMITTER 1LT-463 I LT-463 AF 11 TDAFWP RELAY CABINET A1640 TB A1640 AF 11 TURBINE DRIVEN AF PUMP 22 TD AFW PUMP AF 12 MOTOR DRIVEN AF PUMP 12 MD AFW PUMP AF 12 SG LEVEL TRANSMITTER 1LT-471 I LT-471 AF i 12 SG LEVEL TRANSMITTER 1LT-472 1 LT-472 AF 12 SG LEVEL TRANSMITTER 1LT-473 1 LT-473 AF CHECK VALVE AF 14 CD TO 11 AF PUMP SUCTION AF-141 AF CHECK VALVE AF-14 3 - CD TO 12 AF PUMP SUCTION AF-14 3 AF 6 j CHECK VALVE AF-15 11 AF TO 11 SG AF-15-1 AF l l CHECK VALVE AF-15 12 AF PUMP DISCHARGE AF 15-10 AF CHECK VALVE AF-15-2 -- 11 AF TO 12 SG AF-15 2 AF , CHECK VALVE AF-15 3 - 12 AF TO 11 SG AF 15 3 AF CHECK VALVE AF-15 12 AF TO 12 SG AF-15-4 AF CHECK VALVE AF-15 11 AF PUMP DISCHARGE AF-15-9 AF CHECK VALVE AF-16 AF TO 11 SG AF-161 AF CHECK VALVE AF-16 2 - AF TO 12 SG AF-16-2 AF l CHECK VALVE RS-15-1 RS-15-1 AF CHECK VALVE RS-15-2 RS-15-2 AF CV 31153 - 11 TD AFW PUMP RECIRC/ LUBE OIL CLNG VALVE CV 31153 AF l CV-31154 - 12 MD AFW PUMP RECIRC/ LUBE OIL CLNG VALVE CV-31154 AF CV 31998 - MS SUPPLY TO 11 TD AFW PUMP CV-31998 AF LIMIT SWITCH 33AC-31998 (on Valve) 33AC-31998 AF MANUAL VALVE AF-13-1 ON CROSS TIE BETWEEN 12 & 21 AF PUMPS AF-13-1 AF I l MV-32016 - 11 SG STEAM TO 11 TD AFW PUMP MV 32016 AF MV 32017 -- 12 SG STEAM TO 11 TD AFW PUMP MV-32017 AF MV 32025 - CL TO 11 TD AF PUMP SUCTION MV-32025 AF MV-32027 - CL TO 12 MD AF PUMP SUCTION MV-32027 AF MV-32238 -- 11 TD AF PUMP TO 11 SG MV-32238 AF MV 32239 - 11 TD AF PUMP TO 12 SG MV-32239 AF MV 32333 - CONDENSATE TO SUCTION OF 11 AF PUMP MV 32333 AF MV-32335 - CONDENSATE TO SUCTION OF 12 AF PUMP MV-32335 AF MV-32381 - 12 AF PUMP TO 12 SG MV 32381 AF MV-32382 - 12 AF PUMP TO 11 SG MV-32382 AF PRESSURE SWITCH PS-17700 (11 AF PUMP DISCHARGE) PS-17700 AF PRESSURE SWITCH PS-17704 (11 AF PUMP SUCTION) PS-17704 AF PRESSURE SWITCH PS-17776 (12 AF PUMP SUCTION) PS-17776 AF PRESSURE SWITCH PS-17777 (12 AF PUMP DISCHARGE) PS-17777 AF 11 CC HEAT EXCHANGER 11 CC HX CC i 11 CC PUM? 145-121 CC 11 CC SURGE TANK 11 CC SURGE TANK CC 12 CC HEAT EXCHANGER 135-032 CC 12 CC PUMP 145-122 CC CHECK VALVE CC-14-5 -- 11 RCP BEARING CC WATER RTN CC-14-7 CC i CHECK VALVE CC-14 6 - 12 RCP BEARING CC WATER RTN CC-14-6 CC CHECK VALVE CC-181 - 12 RCP BEARING CC SUPPLY CC-181 CC I ! A-29 l

1 Tcble A.2.3-1, c:ntinu:d Seismically Rugged Components COMPONENT IDNO SYSTEM CHECK VALVE CC-18 11 RCP BEARING CC SUPPLY CC 18-2 CC CHECK VALVE CC-29-1 -- 12 RCP TBHX CC IN CC-291 CC CHECK VALVE CC 29 11 RCP TBHX CC IN CC-29-2 CC CHECK VALVE CC 11 CC PUMP DISCHARGE CC 3-1 CC CHECK VALVE CC 3 2 - 12 CC PUMP DISCHARGE CC 3 ' CC CHECK VALVE CC 5 RETURN LINE TO 11 CC PUMP CC-5-1 CC CHECK VALVE CC 5 2 - RETURN LINE TO 12 CC PUMP CC-5 2 CC CHECK VALVE CC-61 TR. B SUPPLY TO 11/12 RCP BRG CLG CC-61 -1 CC CHECK VALVE CC-61 TR. A SUPPLY TO 11/12 RCP BRG CLG CC-61 2 CC MV-32093 - 11 RHR HEAT EXCHANGER INLET MV-32093 CC MV-32094 - 12 RHR HEAT EXCHANGER INLET MV-32094 CC i MV-32200 - CC SURGE TANK TO 11 CC PUMP MV 32200 CC MV-32201 - CC SURGE TANK TO 12 CC PUMP MV-32201 CC i MW32266 - TR. A CC SUPPLY TO 11/12 RCP MV 32266 CC 11 CLG WTR STRAINER 158-011 CL 11 DIESEL COOLING SUPPLY FAN CL 11 SCREENHOUSE DIESEL COOLING SUPPLY FAN CL 12 AIR RECEIVERS A/B FOR 12 CLG WATER PUMP CL 12 CL DAY TANK LEVEL (HIGH) SWITCH LA-16683 LA 16683 CL 12 CLG WTR. STRAINER 15B 012 CL 12 DIESEL COOLING WATER PUMP CONTROL PANEL CL 12 DIESEL GENERATOR FOR 12 CLG WATER PUMP CL 121 EMERGENCY BYPASS GATE 121 BYPASS GATE CL 1211NTAKE SCREEN BYPASS GATE HYDRAULIC ACCUM. CL 121 S.H. INTAKE BYPASS DRIVE UNIT CL \ 121 SFGD TRAVELLING SCREEN 121 TRAV. SCREEN CL 122 EMERGENCY BYPAS5 GATE 122 BYPASS GATE CL l 122 INTAKE SCREEN BYPASS GATE HYDRAULIC ACCUM. CL 122 S.H. INTAKE BYPASS DRIVE UNIT CL 122 SFGD TRAVELLING SCREEN 122 TRAV. SCREEN CL CHECK VALVE CL-43 12 CL PUMP DISCHARGE CL-43 2 CL CHECK VALVE CL-43 3 - 121 CL PUMP DISCHARGE CL-43-3 CL CHECK VALVE CW-121 - 11 FCU CL INLET CW-12-1 CL CHECK VALVE CW-12-2 -- 13 FCU CL INLET CW-12-2 CL CHECK VALVE CW 12 3 - 12 FCU CL INLET CW-12-3 CL CHECK VALVE CW-12 14 FCU CL INLET CW-12-4 CL CL-95 U1 CL PRESSURE REDUCING GOVERNOR VALVE CL-9 5-1 CL CV-39403 -- 12/14 FCU COOLING WATER SUPPLY VALVE CV 39403 CL D1 COOLING WATER INLET VALVE CV-31505 CV-31505 CL D2 COOLING WATER INLET VALVE CV 31506 CV-31506 CL MV 32034 - CL PUMP DISCHARGE HDR VALVE A MV-32034 CL MV 32035 - CL PUMP DISCHARGE HDR VALVE B MV-32035 CL MV 32132 -- 11 FCU CL OUTLET ISOL A MV 32132 CL MV-32133 - 11 FCU CL OUTLET ISOL B MV-32133 CL l MV-32135 - 12 FCU CL OUTLET ISOL A MV 32135 CL MV-32136 - 12 FCU CL OUTLET ISOLATION B MV-32136 CL MV-32138 - 13 FCU CL OUTLET ISOL A MV 32138 C6 MV-32139 -- 13 FCU CL OUTLET ISOL B MV-32139 CL MV-32141 - 14 FCU CL OUTLET ISOL A MV-32141 CL MV-32142 -- 14 FCU CL OUTLET ISOLATION B MV-32142 CL A-30

i 1 4 Tchle A.2.3-1, cantinurd ] Seismically Rugged Components 4 , COMPONENT IDNO SYSTEM , MV 32145 - 11 CC HX COOLING WATER INLET MV-32145 CL i MV-32146 -- 12 CC HX COOLING WATER INLET MV 32146 CL ) MV-32322 - LOOP A/B CL RETURN HDR CROSSOVER VALVE MV 32322 CL ] MV 32329 - AB LOOP A/B CL RETURN HDR CROSSOVER VALVE MV 32329 CL j MV 32377 - 11 FCU CL INLET MV-32377 CL j MV 32378 - 13 FCU CL INLET MV 32378 CL j MV-32379 - 12 FCU CL INLET MV 32379 CL } MV 32380 - 14 FCU CL INLET MV-32380 CL l CONTROL ROOM CONTROL PANEL A PNL A CRM ) CONTROL ROOM CONTROL PANEL B PNL B CRM l CONTROL ROOM CONTROL PANEL C PNL C CRM CHECK VALVE CS 16 - 11 CS PUMP SUCTION LINE CS-16 CS , CHECK VALVE CS 17 - 12 CS PUMP SUCTION LINE CS-17 CS - CHECK VALVE CS 11 CS PUMP DISCHARGE TO SPRAY RINGS CS-18 CS f CHECK VALVE CS-19 -- 12 CS PUMP DISCHARGE TO SPRAY RINGS CS-19 CS MV-32096 - 11 CS PUMP SUCTION FROM 11 RHR HX MV-32096 CS i MV 32097 - 12 CS PUMP SUCTION FROM 12 RHR HX MV 32097 CS l MV-32098 - 11 CS PUMP SUCTION FROM 1 RWST MV-32098 CS l MV-32099 - 12 CS PUMP SUCTION FROM 1 RWST MV 32099 CS MV-32103 - 11 CS PUMP DISCHARGE VALVE MV-32103 CS l MV-32105 - 12 CS PUMP DISCHARGE VALVE MV-32105 CS 11 BATTERY CHARGER 11 BTTRY CHRGR DC , 11 BATTERY DISCONNECT DC  ! 12 BATTERY CHARGER 12 BTTRY CHRGR DC  ! 12 BATTERY DISCONNECT 12 31 DC BT DC PANEL 12 PNL 12 DC i PANEL 15 PNL 15 DC PANEL 151 PNL 151 DC r PANEL 152 PNL 152 DC PANEL 16 PNL 16 DC PANEL 161 PNL 161 DC  ; PANEL 162 PNL 162 DC i PANEL 163 PNL 163 DC I PANEL 17 PNL 17 DC PANEL 18 PNL 18 DC PANEL 191 PNL 191 DC 121/122 OUTSIDE EXHAUST FANS DG CD-34049 TRN A DAMPERS - 121/122 DG ROOM OUTSIDE AIR CD-34049 DG CD-34049 TRN B DAMPERS - 121/122 DG ROOM OUTSIDE AIR CD 34049 DG D1 D.G. AIR EXHAUST MUFFLER DG D1 DAY TANK LEVEL SWITCH 71X/16698 71X/16698 DG D1 DG AIR INTAKE FILTER SILENCER DG D1 DG CONTROL PANEL D1 DG CON. PANEL DG D1 DG EXPANSION LEVEL TANK DG D1 DG SKID PANEL D1 SKID PANEL DG D1 DIESEL GENERATOR 034-011 DG D1 DIESEL GENERATOR 121 EXHAUST FAN D1 DG 121 FAN DG D1 DIESEL GENERATOR 121 SUPPLY FAN D1 DG 121 FAN DG D1 DSL GEN. RESERVE & MAIN AIR RCVR. tai 4KS 046-031 DG D1 E.G. INTAKE AIR SILENCER DG A-31

i l Tchle A.2.3-1, centinued Seismically Rugged Components

                                                                                               )

p COMPONENT IDNO SYSTEM D1 FO DAY TANK D1 FO DAY TANK DG D1 RELAY PANEL D1 RELAY PANEL DG ' 02 D.G. AIR EXHAUST MUFFLER DG D2 DAY TANK LEVEL SWITCH 71X/16699 71 X/16699 DG D2 DG AIR INTAKE FILTER SILENCER DG D2 DG EXPANSION LEVEL TANK DG l D2 DG SKID PANEL D2 DG SKID PANEL DG ' D2 DIESEL GENERATOR D2 DIESEL GEN. DG D2 DIESEL GENERATOR 122 EXHAUST FAN D2 DG 122 FAN DG j D2 DIESEL GENERATOR 122 SUPPLY FAN D2 DG 122 FAN DG l D2 DIESEL GENERATOR 122 SUPPLY FAN BREAKER 123-38 D2 DG BREAKER DG D2 DSL GEN. RESERVE & MAIN AIR RCVR. TANKS DG l D2 E.G. INTAKE AIR SILENCER DG D2 E.G. INTAKE AIR SILENCER DG D2 FO DAY TANK D2 FO DAY TANK DG D2 RELAY PANEL D2 RELAY PANEL DG TB 1203 AUX RELAY CABINET TB 1203 ED TB 1208 RELAY CABINET TB 1208 ED TB 1209 - RELAY ROOM TERMINAL BOX TB 1209 ED TB 1215 RELAY CABINET TB 1215 ED PANEL 1EMA PNL 1EMA EM PANEL 1EMB PNL 1EMB EM 121 CL FUEL OIL TRANSFER PUMP 121 CL FOTP FO 121 CL FUEL OIL TRANSFER PUMP 121 CL FOTP FO 121 FP FUEL OIL TRANSFER PUMP 121 F.W. FOTP FO 121 FUEL OIL TRANSFER PUMP 121 FOTP FO 122 CL FUEL OIL TRANSFER PUMP 122 CL FOTP FO 122 FUEL OlL TRANSFER PUMP 122 FOTP FO 123 FUEL OIL TRANSFER PUMP 123 FOTP FO 124 FUEL Olt TRANSFER PUMP 124 FOTP FO CHECK VALVE AT OUTLET OF 121 CL FOTP 121 CL OUTLET CV FO CHECK VALVE AT OUTLET OF 121 FOTP 121 OUTLET CV FO l CHECK VALVE AT OUTLET OF 122 CL FOTP 122 CL OUTLET CV FO I CHECK VALVE AT OUTLET OF 122 FOTP 122 OUTLET CV FO CHECK VALVE AT OUTLET OF 123 FOTP 123 OUTLET CV FO CHECK VALVE AT OUTLET OF 124 FOTP 124 OUTLET CV FO 12 STM GEN LOOP B WR LVL XMTR 1 LT-470 MS I 12 STM GEN LOOP B WR LVL XMTR 1 LT-488 MS 12 STM GEN LOOP B WR LVL XMTR 1LT 503 MS CV 31084 - 11 SG PORV CV-31084 MS CV-31089 - 12 SG PORV CV-31089 MS CV-31098 - 11 SG MAIN STEAM ISOLATION VALVE CV-31098 MS CV-31099 - 12 SG MAIN STEAM ISOLATION VALVE CV 31099 MS MN STM FR 11 STM GEN CHNNL 1 RED F XMTR 1 FT-464 MS MN STM FR 11 STM GEN CHNNL 11 WHITE F XMTR 1 FT-465 MS MN STM FR 12 STM GEN CHNNL 111 BLUE F XMTR 1FT-474 MS MN STM FR 12 STM GEN CHNNL IV YEL F XMTR 1 FT-475 MS CV-31231 - 1 P2R PORV B CONTROL VALVE CV-31231 RC CV-31232 - 1 PZR PORV A CONTROL VALVE CV-31232 RC MV-32195 - 1 PZR PORV A BLOCK VALVE MV-32195 RC A-32

i i Teble A.2.3-1,ccntinued Seismically Rugged Components COMPONENT IDNO SYSTEM MV-32196 - 1 PZR PORV B BLOCK VALVE MV-32196 RC TRAIN A HOT SHUTDOWN PANEL 51000 RC 11 RHR HEAT EXCHANGER 11 RHR HX. RH 11 RHR PUMP 11 RHR PUMP RH 12 RHR HEAT EXCHANGER 12 RHR HX. RH 12 RHR PUMP 12 RHR PUMP RH 1RCS1 1RCS1 RH 1RCS2 1RCS2 RH CHECK VALVE RH-3 12 RHR PUMP SUCTION LINE RH-3-1 RH CHECK VALVE RH-3 2 - 11 RHR PUMP SUCTION LINE RH 3-2 RH CHECK VALVE RH-3 12 RHR PUMP DISCHARGE LINE RH-3-3 RH CHECK VALVE RH-3 4 - 11 RHR PUMP DISCHARGE LINE RH-3-4 RH f CV-31235 - 11 RHR HEAT EXCHANGER OUTLET CV CV 31235 RH i CV 31236 - 12 RHR HEAT EXCHANGER OUTLET CV CV 31236 RH MV-32064 - 1 RHR TO RX VESSEL TRN A MV 32064 RH MV-32065 - 1 RHR TO RX VESSEL TRN B MV 32065 RH MV-32066 - 1 RHR RETURN TO LOOP B COLD LEG (SDC) MV-32066 RH MV-32084 - 1 RWST TO 11 RHR PUMP MV-32084 RH MV 32085 - 1 RWST TO 12 RHR PUMP MV 32085 RH I MV-32164 - 1 LOOP A HOT LEG TO RHR TRN A MV-32164 RH MV-32165 - 1 LOOP A HOT LEG TO RHR TRN B MV-32165 RH l MV-32230 - 1 LOOP B HOT LEG TO RHR TRN A MV 32230 RH MV 32231 - 1 LOOP B HOT LEG TO RHR TRN B MV-32231 RH l PRESSURE TRANSMITTER 1PT-419 1 PT-419 RH PRESSURE TRANSMITTER 1PT-420 1 PT-420 RH 1ARP1 1ARP1 S signal ' 1ARP2 1ARP2 S signal 1ARP3 1ARP3 S signal 1ARP4 1APD4 S signal 1ASG1 1ASG1 S signal IASG2 1ASG2 S signal 1BRP1 1BRP1 S signal IBRP2 1BRP2 S signal l 1BRP3 1RRP3 S signal 1BRP4 l 1BRP4 S signal { IBSG1 1BSG1 S signal l 1BSG2 1BSG2 S signal 1PLP 1PLP S signal 1PT-429 - PRESSURIZER PRESSURE TRANSMITTER 1 PT-429 S signal l 1PT-430 - PRESSURIZER PRESSURE TRANSMITTER 1 PT-430 S signal 1PT-431 - PRESSURIZER PRESSURE TRANSMITTER 1 PT-431 S signal IPT-449 - PRESSURIZER PRESSURE TRANSMITTER 1 PT-449 S signal 1PT-945 - CONTAINMENT PRESSURE TRANSMITTER 1PT 945 S signal IPT 946 -- CONTAINMENT PRESSURE TRANSMITTER 1PT 946 S signal 1PT-947 - CONTAINMENT PRESSURE TRANSMITTER 1PT 947 S signal 1PT-949 - CONTAINMENT PRESSURE TRANSMITTER 1 PT-949 S signal 1PT 950 - CONTAINMENT PRESSURE TRANSMITTER 1 PT-950 S signal 1 RVVST 153-101 SI 11 St ACCUMULATOR 101-011 SI 11 St PUMP 11 St PUMP Si l A-33

Teble A.2.3-1, c:ntinucd l Seismically Rugged Components { COMPONENT IDNO SYSTEM 12 SI ACCUMULATOR 101-012 Si l 12 S1 PUMP 12 S1 PUMP Si l 1LT-920 -- 1 RWST LEVEL TRANSMITTER A 1 LT-920 St 1LT-921 - 1 RWST LEVEL TRANSMITTER B 1LT 921 SI CHECK VALVE SI-10 11 St PUMP DISCHARGE SI-10-1 SI CHECK VALVE SI 10 2 - 12 St PUMP DISCHARGE SI-10-2 St CHECK VALVE SI-16-1 -- 11 St PUMP DISCHARGE TO TEST SI-6-1 St CHECK VALVE SI-16 12 St PUMP DISCHARGE TO TEST SI-6 2 SI CHECK VALVE SI 16 COLD LEG INJ LINE TO LOOP B COLD LEG Sl 16-4 St CHECK VALVE SI-16 COLD LEG INJ LINE TO LOOP A COLD LEG SI-16-5 51 l CHECK VALVE SI-6 12 ACCUMULATOR TO LOOP A CL SI-6-1 SI { CHECK VALVE SI-6 12 ACCUM TO LOOP A CL DWNSTM OF SI-6-1 SI-6-2 Si i CHECK VALVE SI-6 11 ACCUMULATOR TO LOOP A CL SI-6-3 St l CHECK VALVE SI-6 11 ACCUM TO LOOP A CL DWNSTM OF SI-6-3 SI-6-4 St CHECK VALVE SI 1 RWST TO 11 RHR PUMP SI 7-1 Si ! CHECK VALVE St-7 1 RWST TO 12 RHR PUMP SI-7-2 Si j CHECK VALVE SI COLD LEG INJ LINE TO LOOP B COLD LEG SI-9-1 Si l CHECK VALVE SI-9 COLD LEG INJ LINE TU LOOP A COLD LEG SI-9-2 SI CHECK VALVE SI-9 LOW HEAD Si TO TRN B RV NOZZLE SI-9-3 SI CHECK VALVE SI-9 LOW HEAD Si TO TRN A RV NOZZLE SI-9-4 Si CHECK VALVE SI-9-5 -- Hl/LO HEAD St TO B RV NOZZLE SI-9-5 SI CHECK VALVE SI-9 Hl/LO HEAD SI TO A RV NOZZLE SI-9-6 Si MV-32067 - 1 Si TO RX VESSEL TRN B MV-32067 St MV 32069 - 1 St TO RX VESSEL TRN A MV-32069 Si MV 32070 - 1 Si TO LOOP A COLD LEG MV-32070 Si i MV-32071 - 11 ACCUM TO LOOP A COLD LEG MV-32071 Si l MV-32072 - 12 ACCUM TO LOOP B COLD LEG MV-32072 SI MV-32075 -- SUMP B TO 11 RHR PUMP MV-32075 Si j MV-32076 - SUMP B TO 12 RHR PUMP MV 32076 Si ! MV-32077 - SUMP B TO 11 RHR PUMP MV-32077 Si MV-32078 - SUMP B TO 12 RHR PUMP MV-32078 St MV 32079 - 1 RWST TO S1 PUMPS TRN A MV-32079 Si MV-32080 - 1 RWST TO St PUMPS TRN B MV-32080 St MV-32081 - 1 BAST TO S1 PUMPS A MV-32081 Si i MV-32082 - 1 BAST TO S1 PUMPS B MV-32082 Si l MV-32162 - 11 St PUMP SUCTION MV 32162 SI MV-32163 - 12 St PUMP SUCTION MV-32163 Sl MV-32202 -- 1 St TEST LINE TO RWST TRN A MV-32202 St MV-32203 - 1 St TFST LINE TO RWST TRN B MV-32203 Sl MV 32206 - 11 RHR TO 11 Si PUMP MV-32206 St MV 32207 - 12 RHR TO 12 St PUMP MV-32207 SI RELIEF VALVE SI 251 SI-25-1 Si j RELIEF VALVE St 25-2 SI-25-2 SI ( 11 BAST 153 041 VC 11 BORIC ACID TRANSFER PUMP 145-611 VC 11 CHARGING PUMP 145-041 VC y 11 CHG PMP SPEED COMPUTER Hl/LO PRESSURE SWITCH 1 PSC-428 A/B VC l 11 CHG PMP SPEED CONTROL LOC SV SV 33687 VC 11 CHG PMP SPEED 1/P CONVERTER 1 LMS-428 A VC 11 CHG PMP SPEED MANUAL LOADER 1 HSC-428D VC A-34

d Tcble A.2.3-1, centinurd Seismically Rugged Components COMPONENT IDNO SYSTEM 11 CHG PMP SPEED RNG EXP XMTR 1 SPT-428A VC 7 11 CHG PMP SPEED TRANSMITTER 1 ST-428A VC 11 SEAL WATER INJECTION FILTER 169-031 VC i 11 SEAL WATER RETURN FILTER 169-061 VC i 11 VOLUME CONTROL TANK 153-021 VC j 12 CHARGING PUMP 145-042 VC j 12 CHG PMP SPEED COMPUTER Hl/LO PRESSURE SWITCH 1 PSC-428C/D VC 12 CHG PMP SPEED CONTROL LOC SV SV-33689 VC J 12 CHG PMP SPEED t/P CONVERTER 1LMS 428B VC 12 CHG PMP SPEED MANUAL LOADER 1HSC 428E VC 12 CHG PMP SPEED RNG EXP XMTR I SPT-428B VC 12 CHG PMP SPEED TRANSMITTER 1 ST-428B VC j 12 SEAL WATER INJECTION FILTER 169-032 VC t 12 SEAL WATER RETURN FILTER 169-062 VC i 1AMR1 1AMR1 VC ILT 106 - 11 BAST LEVEL TRANSMITTER IV (Y) I LT-106 VC f ILT 172 - 11 BAST LEVEL TRANSMITTER ll (W) 1LT 172 VC

1LT-190 -- 11 BAST LEVEL TRANSMITTER 1 (R) 1LT 190 VC 1LT-196 - 11 BAST LEVEL TRANSMITTER 111 (B) I LT-196 VC j CHECK VALVE VC-10 11 CHG PUMP DISCHARGE VC-10-1 VC i CHECK VALVE VC-10 12 CHG PUMP DISCHARGE VC-10-2 VC CHECK VALVE VC-10 13 CHG PUMP DISCHARGE VC-10-3 VC CHECK VALVE VC-13 BA FILTER TO BA BLENDER VC-13-3 VC CHECK VALVE VC 11 VCT OUTLET VC-2-1 VC

, [     CHECK VALVE VC 2 1 RWST TO CHG PUMP SUCTION                         VC-2-2                  VC CHECK VALVE VC-8-15 -- BA FILTER TO EMERG BORATION                      VC-8-15                 VC CHECK VALVE VC 8 4 - 12 RCP SEAL INJECTION                              VC-8-4                  VC

/ CHECK VALVE VC-8 6 -- 12 RCP SEAL INJECTION VC-8-6 VC CHECK VALVE VC-8-7 -- 11 RCP SEAL INJECTION VC-8-7 VC CV 31198 - CHARGING LINE TO 11 REGEN HX CV 31108 VC CV-31199 - BA TO 11 BA BLENDER CONTROL VALVE CV-31199 VC CV 31200 - 11 BA BLENDER TO CHG PUMPS SUCTION HEADER CV-31200 VC CV-31329 - AUX SPRAY TO 11 PZR CV 31329 VC CV 31334 - 11/12 RCP SEAL RETURN BYPASS CV CV-31334 VC CV 31335 - 11 RCP SEAL WTR OUTLET ISOL CV CV-31335 VC CV-31336 - 12 RCP SEAL WTR OUTLET ISOL CV CV 31336 VC LEVEL TRANSMITTER 1LT 112 ILT-112 VC LEVEL TRANSMITTER 1LT 141 1LT 141 VC MV-32060 - 1 RWST TO CHARGING PUMP SUCTION MV-32060 VC MV-32166 -- 1 RCP SEAL RTN/ EXCESS LETDOWN ISOL TRN A MV-32166 VC RELIEF VALVE VC-251 VC-25-1 VC 11 CONTAINMENT FAN COIL UNIT 174-011 ZC 12 CONTAINMENT FAN COIL UNIT 174-012 ZC 14 CONTAINMENT FAN COIL UNIT 174-014 ZC DAMPER CD-34072 - 11 FCU DISCH TO CNTMT DOME CD CD-34072 ZC DAMPER CD-34073 - 11 FCU NORM DISCH TO GAP & STRUCT CD CD-34073 ZC DAMPER CD-34074 - 12 FCU DISCH TO CNTMT DOME CD-34074 ZC DAMPER CD 34075 - 12 FCU DISCH TO GAP & STRUCT CD CD-34075 ZC DAMPER CD-34076- 13 FCU DISCH TO CNTMT DOME CD-34076 ZC DAMPER CD-34077 -- 13 FCU DISCH TO GAP & STRUCT CD CD 34077 ZC s A-35

Tcble A.2.3-1, continu:d Seismically Rugged Components O COMPONENT DAMPER CD-34078- 14 FCU DISCH TO CNTMT DOME DAMPER CD-34079 - 14 FCU DISCH TO GAP & STRUCT CD CD-34078 CD-34079 IDNO SYSTEM ZC ZC 121 CONTROL ROOM AIR HANDLER 121 CR AH ZH 121 CONTROL ROOM CHILLED WATER PUMP 045-591 ZH 122 CONTROL ROOM AIR HANDLER 122 CR AH ZH 122 CONTROL ROOM CHILLED WATER PUMP 045-592 ZH CHECK VALVE ZH-231 ZH-23-1 ZH l CHECK VALVE ZH 23-2 ZH-23-2 ZH , CV 31769 - 121 CRM CHLR CONDENSER CL OUTLET TCV CV-31769 ZH l CV-31785 - 122 CRM CHLR CONDENSER CL OUTLET TCV CV-31785 ZH  ! 211NVERTER 211NVERTER 2AC 120 22 INVERTER 221NVERTER 2AC 120 l 23tNVERTER 231NVERTER 2AC 120 271NVERTER 271NVERTER 2AC 120 281NVERTER 281NVERTER 2AC 120 PANEL 211 PNL 211 2AC 120 PANEL 212 PNL 212 2AC 120 PANEL 213 PNL 213 2AC 120 PANEL 214 PNL 214 2AC 120 PANEL 227 PNL 227 2AC 120 PANEL 228 PNL 228 2AC120 PANEL 234 PNL 234 2AC 230 PANEL 234, PHASE A XFRM PNL 234/A XFMR 2AC 230 PANEL 234, PHASE B XFRM PNL 234/B XFMR 2AC 230 0 PANEL 234, PHASE C XFRM PANEL 235 PANEL 235, PHASE A XFRM PNL 234/C XFMR PNL 235 PNL 235/A XFMR 2AC 230 2AC 230 2AC 230 PANEL 235, PHASE B XFRM PNL 235/B XFMR 2AC 230 PANEL 235, PHASE C XFRM PNL 235/C XFMR 2AC 230 BUS 25 AUX RELAY CABINET 2AC 4160 BUS 25 LOAD SEQUENCE CABINET BUS 25 CABINET 2AC 4160 BUS 26 BUS 26 2AC 4160 BUS 26 AUX RELAY CABINET 2AC 4160 BUS 26 LOAD SEQUENCE CABINET BUS 26 CABINET 2AC 4160 BUS 27 BUS 27 2AC 4160 221 TRANSFORMER 221 XFMR 2AC 480 BUS 211480V BUS 211 2AC 480 BUS 212 480V BUS 212 2AC 480 BUS 221480V BUS 221 2AC 480 BUS 222 480V BUS 222 2AC 480 MCC 2A BUS 1 MCC 2A BUS 1 2AC 480 MCC 2A BUS 2 MCC 2A BUS 2 2AC 480 MCC 2AC BUS 1 MCC 2AC BUS 1 2AC 480 MCC 2AC BUS 2 MCC 2AC BUS 2 2AC 480 MCC 2K BUS 1 MCC 2K BUS 1 2AC 480 MCC 2KA BUS 2 MCC 2KA BUS 2 2AC 480 MCC 2L BUS 1 MCC 2L BUS 1 2AC 480 MCC 2L BUS 2 MCC 2L BUS 2 2AC 480 MCC 2LA1 MCC 2LA1 2AC 480 O MCC 2TA1 MCC 2TA1 2AC 4BO A-36

Tcble A.2.3-1, c:ntinued Seismically Rugged Components COMPONENT IDNO SYSTEM MCC 2TA2 MCC 2TA2 2AC 480 MCC 2X1 MCC 2X1 2AC 480 MCC 2X2 MCC 2X2 2AC 480 21 AF PUMP (MOTOR DRIVEN) 21 MD AFW PUMP 2AF 21 SG LEVEL TRANSMITTER 2LT-461 2LT-461 2AF 21 SG LEVEL TRANSMITTER 2LT-462 2LT-462 2AF 21 SG LEVEL TRANSMITTER 2LT-463 2LT 463 2AF 22 AF PUMP (TUR8tNE DRIVEN) 22 TD AFW PUMP 2AF 22 SG LEVEL TRANSMITTER 2LT-471 2LT-471 2AF 22 SG LEVEL TRANSMITTER 2LT-472 2LT 472 2AF 22 SG LEVEL 1RANSMITTER 2LT-473 2LT-473 2AF 2ARP1 2ARP1 2AF CHECK VALVE 2MS-15-1 2MS-15-1 2Ar CHECK VALVE 2MS-15-2 2MS-15-2 *AF CHECK VALVE AF-14 5 - CD TO 21 AF PUMP SUCTION AF-14 5 2AF CHECK VALVE AF-14 CD TO 22 AF PUMP SUCTION AF 14 7 2AF CHECK VALVE AF-15 21 AF PUMP DISCHARGE AF-15-11 2AF CHECK VALVE AF-15-12 -- 22 AF PUMP DISCHARGE AF-1512 2AF CHECK VALVF AF-15 5 - 22 AF TO 22 SG AF-15-5 2AF { CHECK VALVE AF-15-7 -- 22 AF TO 21 SG AF 15-7 2AF CHECK VALVE AF-16-3 -- AF TO 22 SG AF-16-3 2AF CHECK VALVE AF-16 4 - AF TO 21 SG AF-16-4 2AF CV-31418 - 21 MD AFW PUMP REClRC/ LUBE OIL CLNG VALVE CV 31418 2AF CV-31419 -- 22 TD AFW PUMP RECIRC/ LUBE OIL CLNG VALVE CV-31419 2AF CV-31999 - MS SUPPLY TO 22 AF PUMP CV 31999 2AF LIMIT SWITCH 33AC-31999 (on Valve) 33AC-31999 2AF MANUAL VALVE 2AF-13-1 ON CROSS TIE BETWEEN 12 & 21 AF PUMPS 2AF 13-1 2AF MV-32019 - 21 SG STEAM TO 22 TD AFW PUMP MV-32019 2AF MV-32020 - 22 SG STEAM TO 22 TD AFW PUMP MV-32020 2AF MV-32026 - CL TO 21 MD AF PUMP SUCTION MV 32026 2AF MX32030- CL TO 22 AFW PUMP SUCTION MV-32030 2AF MV-32246 - 22 AF PMP DISCHRGE LN TO INLET OF 21 SG MV-32246 2AF MV 32247 - 22 AF PMP DISCHRGE LN TO INLET OF 22 SG MV 32247 2AF MV 32336 - CONDENSATE TO SUCTION OF 21 AF PUMP MV-32336 2AF MV 32345 - CONDENSATE TO SUCTION OF 22 AF PUMP MV 32345 2AF MV-32383 - LN 21 AF PMP DISCHRGE TO INLET OF 21 SG MV 32383 2AF MV-32384 - LN 21 AF PMP DISCHRGE TO INLET OF 22 SG MV-32384 2AF PRESSURE SWITCH PS-17701 (22 AF PUMP DISCHARGE) PS-17701 2AF PRESSURE SWITCH PS-17705 (22 AF PUMP SUCTION) PS-17705 2AF PRESSURE SWITCH PS-17778 (21 AF PUMP DISCHARGE) PS-17778 2AF PRESSURE SWITCH PS 17779 (21 AF PUMP SUCTION) PS 17779 2AF SOLENOID VALVE SV-33300 (ON CV-31999) SV-33300 2AF 21 CC HEAT EXCHANGER 21 CC HX 2CC 21 CC PUMP 245-121 2CC 22 CC HEAT EXCHANGER 22 CC HX 2CC 22 CC PUMP 245-122 2CC CHECK VALVE 2CC-14 21 RCP BEARING CC WATER RTN 2CC-14 5 2CC CHECK VALVE 2CC 14 6 - 22 RCP BEARING CC WATER RTN 2CC-14-6 2CC CHECK VALVE 2CC 18-1 -- 22 RCP BEARING CC SUPPLY 2CC-18-1 2CC CHECK VALVE 2CC 18 21 RCP BEARING CC SUPPLY 2CC-18-2 2CC A-37 J

Tcble A.2.3-1, cantinutd Seismically Rugged Components COMPONENT IDNO SYSTEM CHECK VALVE 2CC-3 21 CC PUMP DISCHARGE 2CC-31 2CC CHECK VALVE 2CC-3 22 CC PUMP DISCHARGE 2CC-3-2 2CC CHECK VALVE 2CC-5-1 -- RETURN LINE TO 21 CC PUMP 2CC-5-1 2CC CHECK VALVE 2CC-5 RETURN LINE TO 22 CC PUMP 2CC-5 2 2CC CHECK VALVE 2CC-61 1 - TR. B SUPPLY TO 21/22 RCP BRG CLG 2CC-61 1 2CC CHECK VALVE 2CC-61 TR. A SUPPLY TO 21/22 HCP BRG CLG 2CC-61 2 2CC CHECK VALVE 2CC-73 21 RCP TBHX CC IN 2CC-73-1 2CC CHECK VALVE 2CC 73 2 - 22 RCP TBHX CC IN 2CC-73-2 2CC MV-32128 - 21 RHR HX CC INLET MV 32128 2CC MV-32129 - 22 RHR HX CC INLET MV-32129 2CC MV-32211 - CC SURGE TK. TO 21 CC PUMP MV-32211 2CC MV-32212 - CC SURGE TK. TO 22 CC PUMP MV 32212 2CC MV-32268 - TR. B CC SUPPLY TO 21/22 RCP MV-32268 2CC MV 32269 -- TR. A CC SUPPLY TO 21/22 RCP MV-32269 2CC 21 CLG WTR. STRANER 258-011 2CL 21 DIESEL COOLING $UPPLY FAN 2CL 22 CLG WTR. STRAINER 258-012 2CL 22 DIESEL CLG WATER PUMP AIR RECEIVERS A/B 246-011 2CL 22 DIESEL COOLING WATER PUMP CONTROL PANEL 70350 2CL 22 DSL CL PUMP FUEL OIL DAY TANK HIGH LEVEL SWITCH 2CL 22 FO DAY TANK (CL) LA-16687 2CL 2CL-95 U2 CL PRESSURE REDUCING GOVERNOR VALVE 2CL 95-1 2CL CHECK VALVE 2CL-12-1 -- 21 FCU CL INLET 2CL-12-1 2CL CHECK VALVE 2CL-12 23 FCU CL INLET 2CL-12-2 2CL CHECK VALVE 2CL-12 3 - 22 FCU CL INLET 2CL 12-3 2CL CHECK VALVE 2CL-12 24 FCU CL INLET 2CL-12-4 2CL CHECK VALVE 2CL-43 2 - 22 CL PUMP DISCHARGE 2CL-43 2 2CL CV-39413 - 22/24 FCU CL SUPPLY CONTROL VALVE CV 39413 2CL CV-39415 - 21/23 FCb CL SUPPLY CONTROL VALVE CV 39415 2CL CV-39423 -- 21/23 FCU CL RETURN CONTROL VALVE CV-39423 2CL MV 32036 - CL PUMP DISCHARGE HDR VALVE C MV-32036 2CL MV-32037 - CL PUMP DISCHARGE HDR VALVE D MV-32037 2CL MV 32187 - 21 FCU CL OUTLET ISOL A MV 32147 2CL MV 32148 - 21 FCU CL OUTLET ISOL B MV-32148 2CL M_V ?,2150 - 22 FCU CL OUTLET ISOL A MV 32150 2CL MV-32151 - 22 FCU CL OUTLET ISOLATION B MV 32151 2CL MV-32153 - 23 FCU CL OUTLET ISOL A MV-32153 2CL MV-32154 - 23 FCU CL OUTLET ISOL B MV-32154 2CL MV-32156 - 24 FCU CL OUTLET ISOL A MV-32156 2CL MV-32157 - 24 FCU CL OUTLET ISOLATION B MV 32157 2CL MV-32160 - 21 CC HX COOLING WATER INLET MV-32160 2CL MV-32161 - 22 CC HX COOLING WATER INLET MV-32161 2CL MV 32387 - 22 FCU CL INLET MV-32387 2CL MV-32388 - 23 FCU CL INLET MV-32388 2CL MV-32389 - 24 FCU CL INLET MV-323P9 2CL CHECK VALVE CS 22 CS PUMP SUCTION LINE CS-46 2CS CHECK VALVE CS 21 CS PUMP SUCTION LINE CS-47 2CS CHECK VALVE CS 22 CS PUMP DISCHARGE TO SPRAY RINGS CS-48 2CS CHECK VALVE CS-49 -- 21 CS PUMP DISCHARGE TO SPRAY RINGS CS-49 2CS J MV-32108 - 21 CS PUMP SUCTION FROM 21 RHR HX MV-32108 2CS j l i f I A-38 l

Table A.2.3-1, continucd Seismically Rugged Components j COMPONENT IDNO SYSTEM MV 32109 - 22 CS PUMP SUCTION FROM 22 RHR HX MV-32109 2CS  ! MV 32110 - 21 CS PUMP SUCTION FROM 2 RWST MV 32110 2CS MV.32111 - 22 CS PUMP SUCTION FROM 2 RWST MV-32111 2CS MV-32114 - 21 CS PUMP DISCHARGE VALVE MV-32114 2CS MV-32116 - 22 CS PUMP DISCHARGE VALVE MV-32116 2CS 21 BATTERY CHARGER 21 BTTRY CHRGR 2DC 21 BATTERY DISCONNECT 2DC ] 22 BATTERY CHARGER 22 BTTRY CHRGR 2DC 22 BATTERY DISCONNECT 2DC PANEL 21 PNL 21 2DC PANEL 25 PNL 25 2DC PANEL 251 PNL 251 2DC PANEL 252 PNL 252 2DC PANEL 253 PNL 253 2DC PANEL 26 PNL 26 2DC PANEL 261 PNL 261 2DC PANEL 262 PNL 262 2DC PANEL 263 PNL 263 2DC PANEL 27 PNL 27 2DC PANEL 28 PNL 28 2DC 21 DS DIESEL GENERATOR BLDG. SUPPLY FAN 232-441 2DG 21 D5 DIESEL RM. RETURN AIR TEMP CONT. 2TC-5040 2DG 2105 DIESEL ROOM COOLING FAN 21 D5 COOL FAN 2DG 21 DS DSL GEN BLDG RETURN FAN 232-451 2DG 21 D5 FUEL OIL DAY TANK LEVEL INDICATOR 2Lt-5011 B 2DG 21 D5 VERTICAL PANEL 21 D5 PANEL 2DG 22 D6 DIESEL GENERATOR BLDG. SUPPLY FAN 232-442 2DG 22 D6 DIESEL ROOM COOLING FAN 22 D6 COOL FAN 2DG 22 D6 DSL GEN BLDG RETURN FAN 232-452 2DG 22 D6 VERTICAL PANEL 22 D6 PANEL 2DG 23 DS DG BLDG, SUPPLY FAN 232-443 2DG 23 DS DSL GEN BLDG RETURN FAN 232-453 2DG 24 D6 DG BLOG SUPPLY FAN 232-444 2DG 24 D6 DSL GEN BLDG RETURN FAN 232-C4 2DG D5 DIESEL GENERATOR DS DIESEL GEN 2DG D5 DIESEL RM. RETURN AIR TEMP CONT. 2TY-5040 2DG DS ENG 1 COMBUSTION AIR FILTERS 2DG D5 ENG 2 COMBUSTION AIR FILTERS 2DG DS ENG.1 AUX. DESK PANEL 2DG D5 ENG.1 HT EXPANSION TANK 253-401 2DG D5 ENG.1 HT/LT RADIATORS 262-441 2DG D5 ENG.1 LT EXPANSION TANK 253-411 2DG D5 ENG. 2 AUX. DESK PANEL 2DG D5 ENG. 2 HT EXPANSION TANK ?53 402 2DG 05 ENG. 2 HT/LT RADIATORS 262-442 2DG D5 ENG. 2 LT EXPANSION TANK 253-412 2DG D5 ENGINE 1 RADIATOR FAN 1 D5 EN'.,1 FAN 1 2DG DS ENGINE 1 RADIATOR FAN 2 05 ENG 1 FAN 2 2DG D5 ENGINE 2 RADIATOR FAN 1 D5 ENG 2 FAN 1 2DG DS ENGINE 2 RADIATOR FAN 2 D5 ENG 2 FAN 2 2DG A-39

Tnble A.2.3-1, c::ntinu:d ' 4 Seismically Rugged Components COMPONENT IDNO SYSTEM D5 FO DAY TANK DS DAY TANK 2DG l D5 FUEL OIL TRANSFER FILTERS 2DG j D5 INTAKE LOUVERS 2DG DS START AIR RECElVERS 1 A/1B 3681/1 & 3681/3 2DG CS START AIR RECEIVERS 2A/28 2DG I DS TEMP CONTROLLERS 2TE 5040 2DG 05 TEMP CONTROLLERS 2TE-5558 2DG D5 TEMP CONTROLLERS 2THL-5041 2DG D5 TEMP CONTROLLERS 2TSL 5042 2DG D6 DIESEL GENERATOR D6 DIESEL GEN 2DG D6 DIESEL RM. RETURN AIR TEMP CONTROL 1 2TC-6040 2DG D6 DIESEL RM. RETURN AIR TEMP CONTROL 2 2TY-6040 2DG D6 ENG 1 COM8USTION AIR FILTERS 2DG D6 ENG 2 COMBUSTION AIR FILTERS 2DG D6 ENG.1 AUX. DESK PANEL 2DG D6 ENG.1 HT EXPANSION TANK 253-403 2DG D6 ENG.1 HT/LT RADIATORS 262-443 2DG D6 ENG.1 LT EXPANSION TANK 253-413 2DG D6 ENG. 2 AUX. DESK PANEL 2DG D6 ENG. 2 HT EXPANSION TANK 253-404 2DG D6 ENG. 2 HT/LT RADIATORS 262 444 2DG D6 ENG. 2 LT EXPANSION TANK 253-414 2DG  ! D6 ENGINE 1 RADIATOR FAN 1 D6 ENG 1 FAN 1 2DG D6 ENGINE 1 RADIATOR FAN 2 D6 ENG 1 FAN 2 2DG D6 ENGINE 2 RADIATOR FAN 1 D6 ENG 2 FAN 2 2DG l D6 ENGINE 2 RADIATOR FAN 2 D6 ENG 2 FAN 2 2DG  ; D6 FO DAY TANK 6012 2DG D6 FUEL OIL DAY TANK LEVEL INDICATOR 2DG D6 FUEL OlL TRANSFER FILTERS 2DG D6 INTAKE LOUVERS 2DG D6 START AIR RECEIVERS 1 A/18 2DG D6 START AIR RECEIVERS 2A/2B 2DG D6 TEMP CONTROLLER 1 2THL-6041 2DG D6 TEMP CONTROLLER 2 2TSL-6042 2DG D6 TEMP CONTROLLER 3 2TE-6558 2DG D6 TEMP CONTROLLER 4 2TE-6040 2DG TB 2209 - RELAY ROOM AUX RELAY CABINET TB 2209 2ED 21 FUEL OIL STORAGE TANK 21 FO STG. TANK 2FO 21 FUEL OIL TRANSFER PUMP 245-881 2FO 22 FUEL Olt STORAGE TANK 22 FO STG. TANK 2FO 22 FUEL OIL TRANSFER PUMP 245-882 2FO 23 FUEL OIL STORAGE TANK 23 FO STG. TANK 2FO 23 FUEL OIL TRANSFER PUMP 245-883 2FO 24 FUEL OIL STORAGE TANK 24 FO STG. TANK 2FO 24 FUEL OIL TRANSFER PUMP 245 884 2FO CHECK VALVE AT OUTLET OF 21 FOTP 21 OUTLET CV 2FO CHECK VALVE AT OUTLET OF 22 FOTP 22 OUTLET CV 2FO CHECK VALVE AT OUTLET OF 23 FOTP 23 OUTLET CV 2FO CHECK VALVE AT OUTLET OF 24 FOTP 24 OUTLET CV 2FO CV-31102 - 21 SG PORV CV-31102 2MS A-40

Table A.2.3-1, continued Seismically Rugged Components O CV-31107 - 22 SG PORV COMPONENT CV-31116 - 21 SG MAIN STEAM ISOLATION VALVE CV-31107 CV-31116 IDNO SYSTEM 2MS 2MS CV 31117 - 22 SG MAIN STEAM ISOLATION VALVE CV-31117 2MS MN STM FR 21 STM GEN CHNNL i RED F XMTR 2FT-464 2MS MN STM FR 21 STM GEN CHNNL ll WHITE F XMTR 2FT-465 2MS MN STM FR 22 STM GEN CHNNL lil BLUE F XMTR 2FT-474 2MS MN STM FR 22 STM GEN CHNNL IV YEL F XMTR 2FT-475 2MS 21 SI ACCUMULATOR 201-031 2RC CV-31233 - 2 PZR PORV B CONTROL VALVE CV 31233 2RC  ; CV-31234 - 2 PZR PORV A CONTROL VALVE CV-31234 2RC MV-32197 - 2 PZR PORV A BLOCK VALVE MV 32197 2RC MV 32198 -- 2 PZR PORV B BLOCK VALVE MV 32198 2RC TRAIN B HOT SHUTDOWN PANEL 51500 2RC 21 RHR HT EXCHANGER 21 RHR HX 2RH 21 RHR PUMP 21 RHR PUMP 2RH 22 RHR HT EXCHANGER 22 RHR HX 2RH 22 RHR PUMP 22 RHR PUMP 2RH CHECK VALVE 2RH-3 22 RHR PUMP SUCTION LINE 2RH-3-1 2RH CHECK VALVE 2RH-3 21 RHR PUMP SUCTION LINE 2RH-3-2 2RH CHECK VALVE 2RH-3 3 -- 22 RHR PUMP DISCHARGE LINE 2RH 3-3 2RH CHECK VALVE 2RH-3 4 - 21 RHR PUMP DISCHARGE LINE 2RH 3-4 2RH CV 31238 - 21 RHR HEAT EXCHANGER OUTLET CV CV-31238 2RH CV-31239 - 22 RHR HEAT EXCHANGER OUTLET CV CV-31239 2RH MV-32167 -- 2 RHR TRN A TO RX VESSEL MV 32167 2RH MV-32168 - 2 RHR TRN B TO RX VESSEL MV-32168 2RH MV-32169 -- 2 RHR RETURN TO LOOP B COLD LEG (SDC) MV-32169 2RH MV-32187 - 2 RWST TO 21 RHR PUMP MV-32187 2RH MV 32188 - 2 RWST TO 22 RHR PUMP MV-32188 2RH MV-32192 -- 2 LOOP A HOT LEG TO RHR TRN A MV-32192 2RH MV-32193 -- 2 LOOP A HOT LEG TO RHR TRN B MV-32193 2RH MV-32232 -- 2 LOOP B HOT LEG TO RHR TRN A MV-32232 2RH MV-32233 - 2 LOOP B HOT LEG TO RHR TRN B MV 32233 2RH PRESSURE TRANSMITTER 2PT-419 2PT-419 2RH PRESSURE TRANSMITTER 2PT-420 2PT-420 2RH 21PLP 21 PLP 2S signal 2ARP2 2ARP2 2S signal 2ARP3 2ARP3 2S signal 2ARP4 2ARP4 25 signal 2ASG1 2ASG1 2S signal 2ASG2 2ASG2 2S signal 2BRP1 2BRP1 2S signal 2BRP2 2BRP2 2S signal 2BRP3 2BRP3 2S signal 2BRP4 2BRP4 2S signal 2BSG1 2BSG1 2S signal 2BSG2 2BSG2 2S signal 2PT-429 - PRESSURIZER PRESSURE TRANSMITTER 2PT-429 2S signal 2PT-430 - PRESSURIZER PRESSURE TRANSMITTER 2PT-430 2S signal 2PT-431 -- PRESSURIZER PRESSURE TRANSMITTER 2 PT-431 2S signal 2PT-449 - PRESSURIZER PRESSURE TRANSMITTER 2PT-449 2S signal A-41

I 1 i Tabl2 A.2.3-1, continued  ; Seismically Rugged Components COMPONENT IDNO SYSTEM 2PT-946 - CONTAINMENT PRESSURE TRANSMITTER 2PT-946 2S signal  ! 2PT-947 - CONTAINMENT PRESSURE TRANSMITTER 2PT 947 2S signal 2PT 948 - CONTAINMENT PRESSURE TRANSMITTER 2PT 948 2S signal 2PT-949 - CONTAINMENT PRESSURE TRANSMITTER 2PT-949 2S signal l 2PT-950 - CONTAINMENT PRESSURE TRANSMITTER 2PT-950 2S signal ' 2 RWST 253-081 2SI 21 St PUMP 245-071 2SI 22 St ACCUMULATOR 201 032 2SI 22 St PUMP 245-072 2SI 2LT 920 - 2 RWST LEVEL TRANSMITTER A 2LT-920 2SI . 2LT-921 - 2 RWST LEVEL TRANSMITTER B  ! l 2LT 921 2SI CHECK VALVE 2SI-10 21 St PUMP DISCHARGE 2SI-10-1 2SI , CHECK VALVE 2SI 10 22 51 PUMP DISCHARGE 2SI-10 2 2SI f CHECK VALVE 2SI-16 21 St PUMP DISCHARGE TO TEST 2SI-6-1 2SI CHECK VALVE 2SI-16 22 St PUMP DISCHARGE TO TEST 2SI-6-2 2St CHECK VALVE 251-16 COLD LEG INJ LINE TO LOOP B COLD LEG 2SI-16-4 2Si l CHECK VALVE 2S1-16 COLD LEG INJ LINE TO LOOP A COLD LEG 2SI-16-5 2SI l CHECK VALVE 2SI-6 22 ACCUMULATOR TO LOOP A CL 2SI-61 2SI ( CHECK VALVE 2SI-6 22 ACCUM TO LOOP A CL DWNSTM OF 2SI-6-1 2SI-6-2 2S1  ; CHECK VALVE 2SI-6 21 ACCUMULATOR TO LOOP A CL 251-6 3 2SI CHECK VALVE 251-6-4 -- 21 ACCUM TO LOOP A CL DWNSTM OF 2SI-6-3 251-6-4 2SI ' l CHECK VALVE 2SI-7 2 RWST TO 21 RHR PUMP 2SI 71 2S1 CHECT VALVE 2SI-7 2 - 2 RWST TO 22 RHR PUMP 2S1-7 2 2 51 , l CHECK VALVE 2SI COLD LEG INJ LINE TO LOOP B COLD LEG 2SI-9 1 2SI l l CHECK VALVE 2S1-9-2 -- COLD LEG INJ LINE TO LOOP A COLD LEG 251-9 2 2SI l l CHECK VALVE 2S1-9-3 -- LOW HEAD S1 TO TRN B RV NOZZLE ' 2SI-9-3 2SI CHECK VALVE 2SI-9 4 - LOW HEAD Si TO TRN A RV NOZZLE 2SI-9-4 2SI CHECK VALVE 2SI-9 5 - Hl/LO HEAD St TO B RV NOZZLE 2SI-9 5 2St CHECK VALVE 2SI-9 Hl/LO HEAD Si TO A RV NOZZLE 251-9-6 2SI MV 32170 - 2 Si TO RX VESSEL TRN B MV-32170 2SI MV 32172 - 2 Si TO RX VESSEL TRN A MV-32172 2SI MV 32174 - 21 ACCUM TO LOOP A COLD LEG MV-32174 2St MV 32175 - 22 ACCUM TO LOOP B COLD LEG MV 32175 2SI MV-32178 - SUMP B TO 21 RHR PUMP MV 32178 2SI MV-32179 - SUMP B TO 22 RHR PUMP MV 32179 2SI MV-32180 - SUMP B TO 21 RHR PUMP MV-32180 2SI MV 32181 -- SUMP B TO 22 RHR PUMP MV 32181 2SI MV-32182 - 2 RWST TO Si PUMPS TRN A MV-32182 2SI MV 32183 - 2 RWST TO St PUMPS TRN B MV 32183 2SI MV-32184 - 2 BAST TO S1 PUMPS MV A MV-32184 2SI MV-32185 - 2 BAST TO Si PUMPS MV B MV-32185 2SI MV-32186 - 2 BAST TO St PUMPS MV C MV-32186 2SI MV 32190 - 21 S1 PUMP SUCTION MV-32190 2S1 I MV-32191 - 22 St PUMP SUCTION MV 32191 2SI MV-32204 - 2 St TEST LINE TO RWST TRN A MV 32204 2SI l MV-32205 - 2 St TEST LINE TO RWST TRN B MV-32205 2 51 MV-32208 - 21 RHR TO 21 St PUMP MV-32208 2SI MV-32209 - 22 RHR TO 22 St PUMP MV-32209 2SI , RELIEF VALVE 2S1-25-1 2St-25-1 2SI l RELIEF VALVE 2S1-25-2 2SI-25-2 2SI l A-42 l l

1 Table A.2.3-1, continu:d Seismically Rugged Components ) ( COMPONENT IDNO SYSTEM k 21 BAST 253 041 2VC 21 CHARGING PUMP 245 041 2VC J 21 CHARGING PUMP Hl/LO PRESS. SWITCH 2PSC-428A/B 2VC j 21 CHARGING PUMP MANUAL LOADER 2HSC-428E 2VC 21 CHARGING PUMP SPEED t/P CONVERTER 2LMS-428A 2VC 21 CHARGING PUMP SPEED RING EXP. XMTR 2SPT-428A 2VC 1 21 CHARGING PUMP SPEED TRANSMITTER 2ST-428A 2VC 21 CHG PMP SPEED CONTROL LOC SV SV-33836 2VC i 21 SEAL WATER INJECTION FILTER 269 031 2VC , 21 SEAL WATER RETURN FILTER 269-061 2VC 1 21 VOLUME CONTROL TANK 253-021 2VC 22 CHARGING PUMP 245-042 2VC 22 CHARGING PUMP Hl/LO PRESS. SWITCH 2PSC-428C/D 2VC 22 CHARGING PUMP MANUAL LOADER 2HSC-428D 2VC

22 CHARGING PUMP SPEED t/P CONVERTER 2LMS-428B 2VC 22 CHARGING PUMP SPEED RING EXP. XMTR 2SPT-4288 2VC 22 CHARGING PUMP SPEED TRANSMITTER 2ST-428B 2'.*C 22 CHG PMP SPEED CONTROL LOC SV SV-33837 2VC l

22 SEAL WATER INJECTION FILTER 269 032 2VC f 22 SEAL WATER RETURN FILTER 269-062 2VC 2AMR1 2AMR1 2VC 2LT-106 - 21 BAST LEVEL TRANSMITTER IV (Y) 2LT-106 2VC q 2LT-172 - 21 BAST LEVEL TRANSMITTER 11(W) 2LT 172 2VC ! 2LT 190 -- 21 BAST LEVEL TRANSMITTER I (R) 2LT-190 2VC ] . 2LT-? 96 - 21 BAST LEVEL TRANSMITTER ll1 (B) 2LT-196 2VC CHEC< W.VE 2VC-10 21 CHG PUMP DISCHARGE 2VC-10-1 2VC ) $ CHECbALVE 2VC 10 2 - 22 CHG PUMP DISCHARGE 2VC-10-2 2VC j CHECK VALVE 2VC 10-3 -- 23 CHG PUMP DISCHARGE 2VC-10-3 2VC I i CHECK VALVE 2VC 13 BA FILTER TO BA BLENDER 2VC-13 3 2VC 1 CHECK VALVE 2VC-2 21 VCT OUTLET 2VC-2-1 2VC l CHECK VALVE 2VC-2 2 RWST TO CHG PUMP SUCTION 2VC-2 2 2VC  ! l CHECK VALVE 2VC 815 - BA FILTER TO EMERG BORATION 2VC-815 2VC j CHECK VALVE 2VC-8 4 - 22 RCP SEAL INJECTION 2VC-8-4 2VC CHECK VALVE 2VC-8 21 RCP SEAL INJECTION 2VC-8-5 2VC j CHECK VALVE 2VC-8 22 RCP SEAL INJECTION 2VC-B-6 2VC CHECK VALVE 2VC-8 7 - 21 RCP SEAL INJECTION 2VC-8-7 2VC

CV 31211 -- CHARGING LINE TO 21 REGEN HX CV-31211 2VC CV-31212 - BA TO 21 BA BLENDER CONTROL VALVE CV 31212 2VC CV-31213 - 21 BA BLENDER TO CHG PUMPS SUCTION HEADER CV-31213 2VC a CV-31426 - 21 RCP SEAL WTR OUTLET ISOL CV CV 31426 2VC CV 31427 - 22 RCP SEAL WTR OUTLET ISOL CV CV 31427 2VC LEVEL TRANSMITTER 2LT-112 2LT-112 2VC LEVEL TRANSMITTER 2LT 141 2LT-141 2VC f MV-32062 - 2 RWST TO CHARGING PUMP SUCTION MV-32062 2VC MV-32189 - 2 EMERGENCY BORATION TO CHG PUMP SUCTION MV 32189 2VC

) MV-32194 - 2 RCP SEAL RTN/ EXCESS LETDOWN ISOL TRN A MV-32194 2VC MV 32199 - 1 RCP SEAL RTN/ EXCESS LETDOWN ISOL TRN B MV-32199 2VC l MV-32210 - 2 RCP SEAL RTN/ EXCESS LETDOWN ISOL TRN B MV-32210 2VC 1 21 CONTAINMENT FAN COIL UNIT 274 011 22C 22 CONTAINMENT FAN COfL UNIT 274-012 22C I I A-43

i Table A.2.3-1, continued Seismically Rugged Components COMPONENT IDNO SYSTEM 23 CONTAINMENT FAN COIL UNIT 274-013 2ZC 24 CONTAINMENT FAN COIL UNIT 274-014 22C DAMPER CD-34080 -- 21 FCU DISCH TO CNTMT DOME CD CD-34080 22C DAMPER CD-34081 - 21 FCU NORM DISCH TO GAP & STRUCT CD CD-34081 2ZC DAMPER CD-34082 - 22 FCU DISCH TO CNTMT DOME CD-34082 2ZC DAMPER CD-34083 - 22 FCU DISCH TO GAP & STRUCT CD CD-34083 2ZC DAMPER CD-34084 - 23 FCU DISCH TO CNTMT DOME CD-34084 2ZC DAMPER CD 34085 - 23 FCU DISCH TO GAP & STRUCT CD CD-34085 2ZC DAMPER CD-34086- 24 FCU DISCH TO CNTMT DOME CD 34086 2ZC DAMPER CD-34087 - 24 FCU DISCH TO GAP & STRUCT CD CD-34087 2ZC CV-31247 CV-31247 CV-31248 CV-31248 CV-31252 - CC FROM LETDOWN HX ISOLATION VALVE, PENETRATION 40 CV-31252 CV-31253 - CC FROM LETDOWN HX ISOLATION VALVE, PENETRATION 40 CV 31253 CV-31321 - REACTOR MAKEUP TO PRT ISOLATION VALVI, PENETRATION 45 CV-31321 CV-31325 - LETDOWN LINE ISOLATION VALVE, PENETRATION 11 CV 31325 CV-31326 - LETDOWN LINE ISOLATION VALVE, PENETRATION 11 CV-31326 CV 31327 -- LETDOWN LINE ISOLATION VALVE, PENETRATION 11 CV 31327 CV 31339 - LETDOWN LINE ISOLATION VALVE, PENETRATION 11 CV-31339 CV-31342 - REACTOR MAKEUP TO PRT ISOLATION VALVE, PENETRATION 45 CV-31342 CV-31347 - LETDOWN LINE ISOLATION VALVE, PENETRATION 11 CV-31347 CV-31348 - LETDOWN LINE ISOLATION VALVE, PENETRATION 11 CV-31348 CV-31349 - LETDOWN LINE ISOLATION VALVE, PENETRATION 11 CV-31349 CV 31430 - LETDOWN LINE ISOLATION VALVE, PENETRATION 11 CV-31430 CV 31436 - RCDT PUMP DISCHARGE ISOLATION VALVE, PENETRATION 5 CV-31436 CV 31437 - RCDT PUMP DISCHARGE ISOLATION VALVE, PENETRATION 5 CV-31437 CV-31438 - CONTAINMENT SUMP A ISOLATION VALVE, PENETRATION 26 CV-31438 CV-31439 - CONTAINMENT SUMP A ISOLATION VALVE, PENETRATION 26 CV 31439 CV-31619 - CON TAINMENT SUMP C ISOLATION VALVE, PENETRATION 26 CV-31619 CV-31620 - CONTAINMENT SUMP C ISOLATION VALVE, PENETRATION 26 CV-31620 CV 31621 - VACUUM BREAKER ISOLATION VALVE, PENETRATION 41 A CV-31621 CV 31622 - VACUUM BREAKER ISOLATION VALVE, PENETRATION 41B CV-31622 I CV 31625 - VACUUM BREAKER ISOLATION VALVE, PENETRATION 41 A CV-31625 { CV-31626 - VACUUM BREAKER ISOLATION VALVE, PENETRATION 41B CV-31626 l CV-31627 - VACUUM BREAKER ISOLATION VALVE, PENETRATION 41 A CV 31627 , CV 31628 - VACUUM BREAKER ISOLATION VALVE, PENETRATION 41B CV-31627 CV 31630 - VACUUM BREAKER ISOLATION VALVE, PENETRATION 41 A CV-31630 l. CV 31631 - VACUUM BREAKER ISOLATION VALVE, PENETRATION 41B CV 31631 CV-31735 - RCDT PUMP DISCHARGE ISOLATION VALVE, PENETRATION 5 CV-31735 CV-31736 - RCDT PUMP DISCHARGE ISOLATION VALVE, PENETRATION 5 CV 31736 CV 31740 --INSTRUMENT AIR ISOLATION VALVE, PENETRATION 20 CV-31740 CV-31741 -INSTRUMENT AIR ISOLATION VALVE, PENETRATION 20 CV 31741 CV-31742 -INSTRUMENT AIR ISOLATION VALVE, PENETRATION 20 CV 31742 CV 31743 -INSTRUMENT AIR ISOLATION VALVE, PENETRATION 20 CV-31743 CV-31920 - SUPPLY AIR VENT ISOLATION VALVE, PENETRATION 42A CV 31920 CV 31923 - SUPPLY AIR VENT ISOLATION VALVE, PENETRATION 50 CV-31923 CV-31925 - SUPPLY AIR VENT ISOLATION VALVE, PENETRATION 50 CV 31925 CV 31926 - SUPPLY AIR VENT ISOLATION VALVE, PENETRATION 42A CV-31926 f CV-31927 - SUPPLY AIR VENT ISOLATION VALVE, PENETRATION 42A CV-31927 CV 31928 - SUPPLY AIR VENT ISOLATION VALVE, PENETRATION 50 CV-31928 i l A-44

i Teble A.2.3-1, entinu:d Seismically Rugged Components COMPONENT IDNO SYSTEM CV 31929 - SUPPLY AIR VENT ISOLATION VALVE, PENETRATION 42A CV 31929 4 CV 31930 - SUPPLY AIR VENT ISOLATION VALVE, PENETRATION 50 CV 31930 MV 32023 - FEEDWATER ISOLATION VALVE, PENETRATION 7A MV-32023 MV 32024 - FEEDWATER ISOLATION VALVE, PENETRATION 78 MV-32024 MV-32028 - FEEDWATER tSOLATION VALVE, PENETRATION 7C MV-32028 MV-32031, CL ISOLATION VALVE MV-32031 l

MV 32033, CC ISOLATION VALVE MV-32120 MV-32040 - STEAM GENERATOR BLOWDOWN ISOLATION VALVE, PENETRATION 8A MV-32040 j MV-32043 - STEAM GENERATOR BLOWDOWN ISOLATION VALVE, PENETRATION 8A MV 32043 MV 32044 - STEAM GENERATOR BLOWDOWN ISOLATION VALVE, PENETRATION 8B MV-32044 f

MV 32048 - STEAM GENERATOR BLOWDOWN ISOLATION VALVE, PENETRATION 8C MV 32048 MV 32049 - STEAM GENERATOR BLOWDOWN ISOLATION VALVE, PENETRATION BD MV 32049

MV-32051 - STEAM GENERATOR BLOWDOWN ISOLATION VALVE, PENETRATION 8C MV-32051 l MV-32058 - STEAM GENERATOR BLOWDOWN ISOLATION VALVE, PENETRATION BB MV-32058 MV-32059 - STEAM GENERATOR BLOWDOWN ISOLATION VALVE, PENETRATION BD MV 32059 MV-32089 -- CC TO RCP 11 ISOLATION VALVE, PENETRATION 32A MV-32089 i MV-32090- CC FROM RCP 11 ISOLATION VALVE, PENETRATION 33A MV-32090 3

MV-32091 - CC TO RCP 12 ISOLATION VALVE, PENETRATION 328 MV-32091 [ MV 32092 - CC FROM RCP 12 ISOLATION VALVE, PENETRATION 33B MV-32092 MV 32095 - CC TO EXCESS LETDOWN HX, PENETRATION 39 MV 32095 i MV 32115, CC ISOLATION VALVE MV 32115 MV 32120, CC ISOLATION VALVE MV-32120 MV-32121, CC ISOLATION VALVE MV-32121 , MV 32122, CC ISOLATION VALVE MV-32122 MV 32123, CC ISOLATION VALVE MV 32123 l MV-32124 - CC TO RCP 21 ISOLATION VALVE, PENETRATION 32A MV-32124 ' l MV 32125 - CC FROM RCP 21 ISOLATION VALVE, PENETRATION 33A MV 32125 I MV 32126 - CC TO RCP 22 ISOLATION VALVE, PENETRATION 32B MV 32126 MV 32127 - CC FROM RCP 22 ISOLATION VALVE, PENETRATION 33B MV-32127

MV-32130 - CC TO EXCESS LETDOWN HX, PENETRATION 39 MV 32130 MV 32176 - COLD LEG SAFETY INJECTION ISOLATION VALVE, PENETRATION 28B MV-32176 MV-32177 - REACTOR VESSEL SAFETY INJECTION ISOLATION VALVE, MV-32177 PENETRATION 28A MV 32234 -- LETDOWN LINE ISOLATION VALVE, PENETRATION 11 MV-32234 MV 32235 -- LETDOWN LINE ISOLATION VALVE, PENETRATION 11 MV 32235 MV-32242 - AUXILIARY FEEDWATER ISOLATION VALVE, PENETRATION 46B MV 32242 MV-32243 - AUXILIARY FEEDWATER ISOLATION VALVE, PENETRATION 46A MV-32243 MV-32248 -- AUXILIARY FEEDWATER ISOLATION VALVE, PENETRATION 46D MV-32248 MV-32249 - AUXILIARY FEEDWATER ISOLATION VALVE, PENETRATION 46C MV-32249 MV 32271 - SUPPLY AIR VENT ISOLATION VALVE, PENETRATION 50 MV-32271 MV-32273 - SUPPLY AIR VENT ISOLATION VALVE, PENETRATION 42A MV-32273 MV 32274 - POST LOCA H2 CONTROL AIR ISOLATION VALVE, PENETRATION 50 MV-32274 MV-32276 -- POST LOCA H2 CONTROL AIR ISOLATION VALVE, PENETRATION 42A MV-32276 3 MV-32290 - SUPPLY AIR VENT ISOLATION VALVE, PENETRATION 42 A MV 32290 MV-32292 - SUPPLY AIR VENT ISOLATION VALVE, PENETRATION 42A MV 32292 j MV 32293 - POST LOCA H2 CONTROL AIR ISOLATION VALVE, PENETRATION 42a MV-32293 i MV 32295 - POST LOCA H2 CONTROL AIR ISOLATION VALVE, PENETRATION 50 MV-32295 f NSSS COMPONENTS AND PIPING 1 CATEGORY 1 STRUCTURES CATEGORY 2 STRUCTURES CONCRETE BLOCK WALLS i

A-45

1 Tcble A.2.3-1, continued ]i Seismically Rugged Coinpanents i COMPONENT IDNO SYSTEM j

          \  HVAC DUCTING                                                                                                                             i 1          CABLE TRAYS & CONDUlf                                                                                                                     j l

l PIPING ) U1 CONTAINMENT PENETRATIONS l U2 CONTAINMENT PENETRATIONS I 1 ll

 )

W I a i I a 3 1 i a b l !O i 3  ! I i i 1 4 'I Y k I a

 )

i 4 l 1 A-46 i 5

__ _ - . . = . - . . _ - . _ - . . - _ -- __

Tchie A.2.3-2 Reisys Outside the SQUG Progr:m Sc:pe Relay Equipment Manu./ Description ID Affected Model No.

71A1 11 BAST Lo Level West. BFD-11S Relays control valve opening signal to MV-32079 and MV-32080 that effects alignment of SI suction source to the RWST.

!  1-71AIX     11 BAST Lo Level        West. BFD-44S 1

1-7 A2X \ l 71B1 11 BAST Lo Level West. BFD-11S

7181X 11 BAST Lo Level West. BFD-44S

! 7182 11 BAST Lo Level West. BFD-11S i

71B2X 11 BAST Lo Level West. BFD-44S 4

1-LC106C-XA BAST /RWST West. BF-42F Relays are tied to level-sensing circuit Auto-Transfer on BAST that effect auto-transfer of SI suction source from BAST to RWST. 1-LC106C-XB BAST /RWST West. BF-42F

Auto-Transfer i 1-LC172C-XA BAST /RWST West. BF-42F

Auto-Transfer

1-LC172C-XB BAST /RWST West. BF-42F Auto-Transfer

! 1-LC190C-XA BAST /RWST West. BF-42F 1 Auto-Transfer  ! l 1-LC190C-XB BAST /RWST West. BF-42F I l Auto-Transfer ! 1-LC196C-XA BAST /RWST West. BF-22F Auto-Transfer h 1-LC196C-XB BAST /RWST West. BF-22F l Auto-Transfer 1-PC628XB MV-32207 j West. BF-42F Relays effect opening of the SI suction i supply from RHR on SI High Head  ; j Recire. l 1-PC629XA MV-32206 1 l i

!O 4

A--47

_ --_s .. .._.-_.._ _ __._. ._ _. . . . _ - .__ . _ . . ___ _ . _ _ _ .. . . . . . _ _ i i Tcbl2 A.2.3-2, cutinu:d i Relays Outside the SQUG Program Scope  !

    ^

b Relay Equipment Manu./ Description j ID Affected Model No.

62/16-1 12 AF Pump Agastat Relays trip pumps off-line on failure of i Trips 7012PD CST supply to avoid pump damage.

After operator action to realign to  ! alternate cooling water supply, pumps ~ are manually restarted.

62/2 22 AF Pump Agastat i Trips 7012PC

] 62/2 11 AF Pump Agastat

Trips 7012PC .

] SI-11X 11 SI Pump West. BFD-84S Pump control circuit j t i SI-13X MV-32081 Valve control circuit (suction path to

BAST)  ;

i 3 i O i ) 4 i i l\ i O A-48

O V A2.4 Results Components that were not screened from further review out by the walkdowns (Section A.2.2) or the screening evaluations are listed in Table A.2.4-1. Most of these will be addressed by the SQUG program or their failures were shown by systems analysis to be of no consequence. The remaining components are outliers which require resolution. These outlier components consist of electrical equipment with potential seismic interactions which could cause impact-induced relay chatter. , A.2.4.1 Disposition of Components Needing Additional Evaluation After Supplement 5 to Generic Letter 88-20 was issued, NSP elected to complete the seismic IPEEE for Prairie Island with an evaluation equivalent to a reduced scope seismic margins assessment with an additional focus on certain key components. Following the guidance of NUREG-1407 (14], outliers for reduced scope plants should be evaluated by the provisions of the Generic Implementation Procedures (GIP) [15] if the plant is also in the SQUG program. The Prairie Island SQUG program has submitted their evaluation  ; and conclusions {20], which have been considered in the discussion below. Structures and components outside of the SQUG program scope that could not be screened following the GIP should be evaluated following the requirements of the plant USAR. The following two sections provide a summary of the SQUG outliers that pertain to the IPEEE scope, and the items addressed through systems analysis. No unscreened components or structures were identified that required evaluation to USAR requirements. The disposition of the components in Table A.2.4-1 using these reduced scope seismic margin assessment criteria is discussed here. A.2.4.1.1 Disposition Based on SQUG Program Results Containment Fan Coil Unit Cooline Water Control Valves CV-39401 and CV-39409: A potentially adverse interaction between the control valves and nearby conduit was identified during the IPEEE walkdown in the Auxiliary Building. This potential interaction was also noted by SQUG. SQUG has designated these valves as outliers so i that resolution of the potential interaction will be resolved through the closure of USI A-46 at Prairie Island. Containment Fan Coil Unit 13: SQUG has flagged this FCU as an outlier because the floor response spectra (demand) at the location of this equipment exceeds the allowable capacity. The IPEEE walkdown also identified a potential anchorage issue for this FCU. IPEEE will credit resolution of this issue in the closure of the A-46 Program. I Batteries 11 and 21: Issues regarding the ruggedness of the batteries and their anchorage p J were raised by both IPEEE and SQUG. SQUG has identified these batteries as outliers, A--49

p requiring them to be addressed as part of the closure to the A-46 program at Prairie d Island. Batteries 12 and 22: Both the IPEEE and SQUG walkdowns identified missing spacers in the battery restraint configuration. SQUG has designated the batteries as outliers. Ensuring adequate support of the battery will be addressed as part of the closure of the Prairie Island A-46 Program. , Battery Charcer 11.12. and 22: Anchorage issues were raised by both IPEEE and SQUG related to the cabinet bases. SQUG has also raised a question about a potentially adverse seismic interaction for Battery Charger 22. These Battery Chargers have been added to the list of A-46 Program outliers and will be addressed through the closure of the SQUG effort. Gace Panels for D1 and D2: These panels are located on the diesel skids. The issue , raised by both IPEEE and SQUG has to do with the vibration isolators used at the base of the panels. These isolators were described by SQUG as " flexible (wobbly) steel springs." ' Both Gage Panels have been flagged as outliers by SQUG and will be addressed by the actions to close the A-46 Program. 125VDC Panels 11.12. and 22: The distribution panels are mounted to the floor. The walkdown identified that the lord bearing point at the panel base is elevated above the floor level, giving rise to potentially unacceptable bending stresses. SQUG identified this configuration as potentially unacceptable and has designated these panels as outliers that must be addressed by the actions to close the A-46 Program. I 1. 21 Screenhouse Roof Exhaust Fans: SQUG determined that the seismic demand on the Exhaust Fan anchorage potentially exceeds the seismic capacity. The IPEEE identified similar concerns during the walkdown. Anchorage details for the fan will be reviewed and confirmed to be adequate or corrected as part of the closure of the A-46 Program. Diesel-Driven Cooline Water Pumps 12 and 22 Jacket Heat Exchancers: The horizontally-oriented heat exchangers were identified as having questionable attachment capacity by both SQUG and IPEEE. These items were designated as outliers by SQUG l because the heat exchangers are "not secured to the pedestals (mounting cradles are secured to the pedestals but heat exchanger is not attached to the cradles. Further, both cradles have slotted mounting holes)." These components will be addressed through resolution of outliers in the closure of the Prairie Island A-46 Program. Diesel-Driven Cooline Water Pumns 12 and 22: SQUG and IPEEE have raised issues with both the anchorage and the shaft length for these pumps. SQUG has identified these pumps as outliers requiring resolution under the closure of the A-46 Program. l l l A-50 l

'p Motor Control Centers (MCCs) I Kl. I L2. 2K2.1 ABl .1 AB2. 2LA2.1TA1. and ITA2: d These MCCs have issues involving anchorage inadequacies or adverse seismic-induced interactions raised by both SQUG and IPEEE. Those MCCs having anchorage issues involve the cabinet being supported off the floor by inverted base channels which are then bolted to the floor by anchors which pass through these base channels, creating potentially unacceptable bending stresses. Issues of potential interaction involve possible , contact with nearby equipment during the seismic event. SQUG has flagged these MCCs as outliers that must be addressed as part of the closure of the A-46 Program.

     .Ck(121 and 122) and DG (121 and 123) Oil Storace Tanks: SQUG has identified these tanks as outliers because the flexibility of associated buried piping could not be determined from available documentation. The IPEEE, faced with the same concern, will credit the resolution of this issue in the closure of the A-46 Program.

I Pressurizer Relief Valves 1RC-10-1 and 2. 2RC-10-1 and 2: These valves were not

evaluated for seismic adequacy within the IPEEE because their function is not credited.

j These valves have been identified as outliers with the A-46 Program and will be addressed further as part of the closure of that program. North (121.122) and South (121.122) Unit Coolers: These have been identified within the Prairie Island A-46 Program as being SQUG outliers and, therefore, were not I [j evaluated further in the IPEEE seismic effort. The IPEEE will credit resolution of the s' SQUG issues established with the closure of that program. Control Roon) Water Chillers (121.122): These have been identified within the Prairie Island A-46 Program as being SQUG outliers and, therefore, were not evaluated further in the IPEEE seismic evaluation effort. The IPEEE will credit resolution of the SQUG issues established with the closure of that program. I Control Room Ceiline: Aluminum diffusers rest on T-bar runners, above which the ceiling lights are located. Walkdowns by IPEEE and SQUG noted the potential for the diffusers to fall as a result of a seismic event, thereby creating a personnel hazard, in addition to adverse interactions with control room panels and racks. SQUG has listed the control room ceiling as an outlier issue. The adequacy of the diffuser support design will be resolved as part of the closure of the A-46 Program at Prairie Island. A.2.4.1.2 Disposition Based on Systems Analysis Eauipment in Sunnort of Room Cooline Functions: Seismic walkdowns performed under the IPEEE have identified various components with questionable anchorage or ruggedness which may not withstand a seismic event. Instead of performing seismic analyses of these components, credit has been taken for analyses previously performed by Q NSP that considered whether ti.e room cooling functions supported by these components (V are critical. The affected equipmeet is discussed below: A-51 1

I q Panels 132 and 133: Failure of these panels affects room cooling to the Unit 1 V 4kV safegard bus rooms. Conservative room heat-up analyses have been performed that conclude the room cooling function is not critical. The analysis for the 4kV bus rooms [26] shows that the only affected components in these rooms are the load sequencers. However, the seismic event is postulated to cause a loss  ; of offsite power, which in turn will require starting the emergency diesels. This will require the functioning of the load sequencers almost immediately. Therefore, by the time the rooms heat up to the temperature at which the operability of the sequencers become questionable, their function will have already been completed. RHR Pit Cooling (11,12,21, and 22 Unit Coolers): Analysis performed by NSP [28] shows that long term post-LOCA RHR pit temperatures reach only 140 F with both trains of RHR in recirculation and no ventilation available. This is well within the range needed for pump operability during the required mission time. The unit coolers are required for Technical Specification operability of the pumps only to preserve the EQ margin for operation up to one year following a j postulated accident. SWGR / Bus Rooms ( 15,16) Unit Coolers: See discussion above for Panels 132 and 133 and how it applies to the 4kV SWGR/ bus rooms. D5/D6 480V Aux. Air Handlers (21/22) and 480V SWGR Room Aux. 1

Condensing Units (21/22): These components provide normal air circulation / conditioning. These components are not needed to respond to, or mitigate, accident conditions. Loss of any or all of these components would not lead to adverse environmental conditions affecting critical components.

Containment Snray Pumns (11.12. 21,22h No credit was taken for the containment environment control function provided by the Containment Spray system. Containment Spray is not required to limit containment pressure following a small LOCA. Rather, its principal purpose in the IPEEE would be for long term decay heat removal. However, i containment air cooling can be provided through the Fan Coil Units (FCUs). There are four FCUs in each containment, with a design capacity that requires only 2 cf 4 to be operable to ensure sufficient cooling occurs. Accordingly, the Containment Spray pumps l 4 were excluded from further consideration in the seismic ruggedness evaluation within the IPEEE. Steam Generator Level Locic Relays and Bistables: The IPEEE walkdown identified potential anchorage concerns with the panels containing these components. The purpose of these components in the Steam Generator Level Logic circuitry is to trigger initiation of the Auxiliary Feedwater (AFW) pumps when normal makeup becomes inadequate. > pd The components in question include the following: A-52

l 11 Steam Generator Logic Relay 1LC-463C-XA V 11 Steam Generator Logic Relay 1LC-461B-XA i 11 Steam Generator Logic Relay ILC-462A-XA 12 Steam Generator Logic Relay 1LC-473C-XA 12 Steam Generator Logic Relay 1LC-473C-XB 21 Steam Generator Logic Relay 2LC-463C-XA 21 Steam Generator Logic Relay 2LC-461B-XA 21 Steam Generator Logic Relay 2LC-462A-XA 22 Steam Generator Logic Relay 2LC-473C-XA 22 Steam Generator Logic Relay 2LC-473C-XB 11 Steam Generator Bistable 1LC-461B-XA/XB 11 Steam Generator Bistable 1LC-462A-XA/XB 11 Steam Generator Bistable 1LC-463C-XA/XB 12 Steam Generator Bistable 1LC-472A-XA/XB 12 Steam Generator Bistable ILC-473C-XA/XB 21 Steam Generator Bistable 2LC-461B-XA/XB 21 Steam Generator Bistable 2LC-462A-XA/XB , 21 Steam Generator Bistable 2LC-463C-XA/XB 22 Steam Generator Bistable 2LC-472A-XA/XB 22 Steam Generator Bistable 2LC-473C-XA/XB In the postulated seismic event, a loss of offsite power (LOOP) occurs which causes a l loss of normal feedwater (Main Feedwater pump trip). The loss of power is sensed by  ; plant equipment (e.g., undervoltage relays) which then auto-initiates the turbine driven AFW pump. The relays and bistables are not needed, therefore, in response to the LOOP. Turbine-Driven AFW Pumn Trin and Throttle Valves (CV-31059 and CV-31060h The IPEEE walkdown identified a seismic stability concern for these valves. The concern is whether a seismic event would cause the valves to trip closed, thereby disabling their respective turbine-driven AFW pumps. The seismic concern does not involve a failure of the valve itself, rather of the trip mechanism for the valve. An operator action is defined in existing procedures to restore the trip and throttle valve in the event the valve trips for any reason. However, the operator action involves going to the Auxiliary Feedwater pump room, where the valve is located, and performing the restoration locally. The IPEEE seismic walkdown traced the path from the control room to the valve location and concluded that there are no potential obstructions that could occur due to the earthquake that would prevent the operators from reaching the valve and completing the restoration activity. Based on this, credit is taken for the availability of these valves and the turbine-driven AFW pumps in both units. A-53 i

I n Air Comoressors for Diesel Cooline Water Pumns (12 and 22): The air compressors are Q needed to charge the air receivers on the Emergency Diesel Generators for starting. As a result of the seismic event,it is assumed that these compressors are unavailable. This is

                                                                                                  ]

of no consequence since the air receivers have sufficient capacity to support starting the diesels upon demand. Diesel Generator Fuel Oil Storace Tanks (122 and 124): The IPEEE seismic walkdown i raised a concern about these tanks regarding the flexibility of buried pipe. However, Tanks 121 and 123 have been determined by SQUG to be acceptable to SSE levels. In addition to the 1-2 hour fuel supply available in the day tanks, fuel from the  ; interconnected storage tanks can supply any single diesel for up to two weeks. Therefore, the capacity within Tanks 121 and 123 is considered sufficient to meet the needs for the postulated post-eanhquake plant conditions assuming the tanks have been dispositioned i by SQUG. Tanks 122 and 124 are not credited and no further seismic evaluation is I required. Steam Generator (11.12. 21. 22) PORV Accumulator: Anchorage concerns were raised for these components during the IPEEE walkdowns. The accumulators provide a source of pressurized air that enable operation of the relief valves on the steam generators. The relief valves provide a means to depressurize the steam generator to perform secondary g side cooldown. The PORVs fail closed on loss ofinstrument air. Since instrument air is v; assumed to be lost due to the seismic event, no credit is taken for the PORVs, although they would have a limited number of cycles available with the charge stored in the accumulators. Boric Acid Transfer Pumns (11.12. 21. 22): The IPEEE seismic walkdown identified potential anchorage concerns associated with these pumps. The pumps supply boric acid from the batch processing tanks to the three Boric Acid Storage Tanks. One of these boric acid tanks provides supply for SI injection in the event of a loss of primary coolant. A sufficient supply of borated water is already available from the Boric Acid Storage Tank (BAST) and the Refueling Water Storage tank (RWST) without having to rely on the backup supply capabilities using the Boric Acid Transfer Pumps. Charcing Pumns (13. 23): Anchorage concerns related to these pumps were raised by the IPEEE during the seismic walkdowns. There are three charging pumps that take suction from the Volume Control Tank, with the RWST providing a backup supply, to provide reactor coolant makeup and reactor coolant pump seal water injection cooling. In the seismic-induced accident scenario postulated here, makeup is provided by SI through injection and then recirculation. Seal injection cooling is critical to prevent a small LOCA occurring through failed reactor coolant pump seals. One charging pump is needed for this function; two have been determined through the USI A-46 effort to be seismically rugged (Pumps 11 and 12 in unit 1; Pumps 21 and 22 in Unit 2). The third [OD A-54

l 1 l i i

-  pump in each unit was not looked at by SQUG. Because of the redundancy already           l available through the two charging pumps, not to mention the alternate cooling path      !

available through Component Cooling Water to the RCP thermal barrier, the third , charging pump is considered unnecessary and requires no further evaluation under the  ! seismic IPEEE. Buses 11.12.13. and 14: The IPEEE seismic walkdown noted these bus panels as j potentially having inadequate anchorage. These buses support Main Feedwater, RCPs i and Condensate, which are lost as a result of the loss of offsite power. Since emergency l buses do not support these components, they require no further evaluation under the ' l seismic IPEEE. MCCs 1 M1.1 M 2.1 MA1.1 MA2: Anchorage issues were raised for these MCCs during i the IPEEE walkdown. These MCCs support Auxiliary Building Ventilation. This function is not modeled in the PRA, nor are these components included in the database of PRA basic events. Cooling for critical components is provided through room cooling

                                                                                            ]

systems which are powered by different MCCs. l Inverters 14 and 24: The 1PEEE walkdown identified these components as potentially having inadequate anchorage. These inverters supply Panels 114 and 214, respectively. These panels provide power to the Steam Generator PORV hand controllers, so their unavailability would disable manual operation of the PORVs. However, the PORVs are {V} not required to mitigate the consequences of the seismic event; i.e., they support no critical functions during aloss of offsite power or small LOCA. Panel 117: Potential anchorage issues caused this panel to b: noced during the IPEEE walkdown. This panel provides an alternate power supply to 120V AC Panels 111,112, 113 and 114. The normal power supply for these panels is from their associated inverters or batteries. Since Panel 117 is a backup supply, it is not required to mitigate the consequences of a seismic accident Therefore, failure of the panel can be tolerated.

                                                                                            ]

Panel 217: The IPEEE walkdown noted this panel as having shimmed anchors and, l therefore, requiring further review. This panel provides an alternate power supply to l Panel 1EMB, which is normally powered through 18 Inverter. Since Panel 217 is an alternate supply, it is not required to mitigate the consequences of a seismic event. Therefore, failure of this panel can be tolerated. Panels 313 and 3133: A concern was raised during the IPEEE seismic walkdown related to the proximity of these panels to possible non-safety masonry walls. These panels are not represented in the PRA model. A review of cable data base information indicated these panels suppon Condensate and Feedwater systems only, which are lost as a result of the LOOP. Therefore, no further seismic evaluation is required for these components. A O A-55

Panel 153: This panel was identified during the IPEEE seismic walkdown as having questionable anchorage. Panel 153 was also noted as having a potentially adverse seismic interaction. Panel 153 supports the Unit 1 Auxiliary Spray function, which is not credited in responding to the loss of offsite power /small LOCA plant condition caused by the seismic event. Based on these considerations, no further seismic evaluation is required for this panel. Cooline Water Pumn 121: SQUG and IPEEE identified anchorage and shaft stability issues for each of the diesel -driven Cooling Water pumps resulting in their being c:assified by SQUG as outliers. The IPEEE walkdown identified the same issues associated with the third Cooling Water pump (121). All three cooling water pumps are available to respond to a loss of offsite power /small LOCA scenario following a seismic event. The USAR states that the cooling needs for the two units can be met by one diesel driven cooling water pump when responding to a loss of offsite power. Therefore, the unavailability of 121 pump would not threaten cooling water capacity since the two diesel driven pumps both provide sufficient redundancy. CV-31421: This valve opens to allow Auxiliary Spray flow to the 21 Pressurizer. The IPEEE walkdown identified a potentiall adverse seismic interaction involving this valve. I Auxiliary spray is not credited following a seismic event as it depends on instrument air. Therefore, loss of the ability to open this valve to allow Auxiliary Spray to the Unit 2 f3 (g pressurizer can be tolerated. CV-39411: This is the 11/13 Containment FCU cooling water return valve. The IPEEE walkdown identified a potential adverse interaction involving the valve's limit switch. The interaction could cause the limit switch to become damaged and fail. The position of the valve varies depending on the time of the year and the seasonal temperature loading on the containment. To support the accident response, the preferred position of the valve is open. Should the valve be closed at the time of the seismic event, and if the limit l switch should become damaged and fail due to interaction, the valve will open (the  ! valve's fail-safe position). Based on this, no further seismic evaluation is required. MV-32068: This normally opened valve enables SI Cold Leg injection into the Loop B Cold Leg. The IPEEE walkdown identified a potential adverse seismic interaction with the valve. Ilowever, because the valve is already in its preferred position for accident / event response, and since it is not considered credible that the seismic interaction would cause the normaily open valve to change positions, no further seismic evaluation is called for. MV-32086: This normally closed valve provides a flow path for emergency boration supply to the charging pump suction via the boric acid transfer pumps. The seismic p IPEEE walkdown identified a potential adverse seismic interaction involving the valve. d No credit was taken for this emergency boration function, sothe seismic interaction with A-56

g) ( this valve would have no consequence. Therefore, no further seismic evaluation is required. MV-32117: This valve provides isolation to the Spent Fuel Pit Heat Exchanger from , Unit 2 CC and is normally in a closed position. The seismic IPEEE walkdown identified a potential adverse seismic interaction involving the valve. Following a seismic event, assuming the occurrence of a loss of offsite power and a small LOCA, there is no need for the valve to change position. In fact, it is preferred that the valve remain closed. It is not considered credible that the seismic event would cause the normally closed valve to change to the open position. Therefore, no further seismic evaluation is required for this component. MV-32267: This is the Train B Component Cooling Water Supply valve to the 11/12 Reactor Coolant pumps. This normally open valve is required to remain open. The seismic IPEEE walkdown identified a potential adverse seismic interaction involving the d valve. It is not considered credible that the seismic interaction would cause the normally open valve to change positions and become closed. Therefore, no further seismic evaluation is called for. , MV-32386: This is the cooling water supply valve to the 21 Containment FCU. This valve is normally open and is required to remain open to support the response to the post seismic event conditions postulated here. It is not considered credible that the seismic 4 interaction would cause the normally open valve to change positions and become closed. Therefore, no further seismic evaluation is called for. Condensate Storace Tanks (l l . 21. 22): The seismic ruggedness of these tanks was called into question during the IPEEE walkdown. However, cooling water supplies from alternate sources (e.g., Cooling Water) are available such that loss of the tanks can be accommodated. Realignment to of the AFW pump suction to the alternate cooling water supply can be accomplished by the operator from the control room. i Boric Acid Filters (11. 21): The IPEEE seismic walkdown noted anchorage and support

concerns related to these components. These filters remove particulates from the flow

, supply from the boric acid transfer pumps to charging pump suction in the emergency boration mode of operation. The emergency boration mode of operation is not credited in response to the seismic event. Therefore, the integrity of the filters during and following a seismic event is not critical to bring the plant to a safe shutdown condition. Bus 22 Undervoltace Relays (2-27A/B22-XA and 2-27B/B22XA): The IPEEE seismic walkdown noted that the panels containing these relays have shimmed anchors and required further review. Bus 22 carries loads for the Unit 2 Reactor Coolant Pumps and the Main Feedwater pumps. In the event of a loss of offsite power, power to the Bus is ( lost. These relays sense the effect of an undervoltage situation during normal plant A-57

E operations and send a signal to initiate a reactor coolant pump trip which causes a reactor d trip. Since the equipment supponed by Bus 22 is not credited following a seismic event and a reactor trip will be accomplished from other signals, no further evaluation is required for these components. i 11.12. 21. and 22 Component Cooline Water Pumn Discharce Pressure Switches (16262. 16263.16264. and 16265): These mercoid switches are not explicitly modeled in the PRA. The IPEEE walkdown raised as a concern the functioning of these switches during a seismic event. The pressure switches are part of the CC Pump Autostart logic. The pressure switches sense low pressure in the associated pump discharge header (due to loss of one or both of the normally operating CC pumps) and stans the CC pumps. The i pumps have two autostart signals: one is the pressure switch / sensor, the other is by ESF signal. There is also a manual start option. Following the seismic event, an ESF signal y will cause the CC pumps to receive a stan signal. The signal from these pressure switches is, therefore, not critical. No further seismic evaluation is required for these components. Containment Pressure Transmitters (1PT-948 and 2PT-945): The IPEEE seismic J walkdown identified a potentially adverse interaction for each of the racks on which these , transmitters are mounted. Also, the anchorage for the rack containing 2PT-948 was noted as being questionable and needing further review. These transmitters represent a bank of 4 six in each unit that sense rising containment pressure. At the appropriate set point and with sufficient coincidence from the other transmitters, a "P" signal is generated which, in turn, causes initiation of the Containment Spray system. No credit has been taken for Containment Spray in responding to the seismic event and the ensuing plant condition.

Instead, cooling is provided by the containment Fan Coil Units (FCUs) which are sized to more than adequately handle the decay heat load. Therefore, these transmitters are not critical to the plant response to the earthquake, and they require no further evaluation.

Low Header Pressure Switches (PS-16002.16009.16259): These mercoid switches are not explicitly modeled in the PRA. The IPEEE walkdown raised as a concern the j functioning of these switches during a seismic event. The switches are part of the start logic for the diesel-driven Cooling Water pumps (12 and 22) and the motor-driven pump i (121). Similar to the logic for the pressure switches in the Component Cooling Water system, these switches detect low pump discharge header pressure and send a start signal to the associated pump-start circuit. Since the auto-start logic also accepts an ESF signal to initiate pump start, the reliability of these pressure switches during/following a seismic event is not critical. No further seismic evaluation is required for these items. A.2.4.1.3 Outliers Potentially Addressed by Maintenance Procedures e Bus 25: A wall-hung ladder behind the bus cabinet was noted in the walkdowns. Earthquake motion could cause the ladder to slide off of the wall hooks and strike the bus A-58

q cabinet. Damage affecting the structural integrity is unlikely, but impact could cause Q relay chatter. Restraining the ladders to the wall hooks by chaining or an alternate means will mitigate the potential for impact. Alternatively, the ladder could be relocated sufficiently far from the bus such that impact would be unlikely. D2 Diesel Generator Control Panel: Wall hung scaffolding is located in close proximity behind the panel. Earthquake motion could cause the scaffolding to slide off of the wall hooks, impact the panel, and potentially induce relay chatter. Restraining the scaffolding l by chaining or an alternate means will mitigate the potential for impact. Altematively, the scaffolding could be relocated sufficiently far from the panel such that impact would be unlikely. A general maintenance provision to restrain all wall hung ladders or remove them from the proximity of essential equipment can be used to address the potential seismic interaction. This will mitigate the potential for impact induced relay chatter. A general maintenance provision is recommended since the locations of the ladders were transient. A.2.4.2 Safe Shutdown Functions Following a Seismic Event All the functions that are needed to ensure adequate core cooling and containment  ; pressure control following an earthquake have multiple and,in some cases, diverse trains of equipment, each one of which is capable of performing that function. Each train of equipment for both units has been shown to be seismically rugged to the SSE level. As a result, it is concluded that the Prairie Island plant has no vulnerability to seismic events. Reactivity Control All systems, structures, and components (SSCs) that support reactivity control were found to be seismically rugged and would be available following an earthquake. Given the loss of offsite power or small LOCA that is assumed to follow an earthquake, several independent signals would be expected to induce a reactor trip, such as Loss of Offsite Power and Turbine Trip. The principal means of reactor shutdown would be the Reactor Protection System effecting control rod insertion. Generic Letter 88-20, Supplement 5 [2] eliminated reactor internals from the scope of the IPEEE investigation. Therefore, no further consideration ha:: been made as to the insertion capability of control rods when issued a scram signal. Reactor Coolant Pump Seal Cooling All the SSCs credited to provide Reactor Coolant Pump Seal Cooling were found to be seismically rugged to the SSE or are being evaluated for adequacy under the closure of the Prairie Island USI A-46 Program.  ! A-59

c Two redundant and diverse means are available to provide seal cooling and prevent a potential small LOCA through failed seals. Charging pumps (two in each Unit) are available to provide seal injection cooling. Two trains of the Component Cooling Water system are also available to supply CC to maintain the RCP Thermal Barrier. Secondary Heat Removal All the SSCs credited to provide Secondary Heat Removal were found to be seismically rugged to the SSE, can be recovered by operator action, or are being evaluated for adequacy under the closure of the Prairie Island USI A-46 Program. Normal secondary cooling is provided through the Main Feedwater system which is lost due to the loss of offsite power. AFW provides this cooling function by a pump backed by the Emergency Diesel Generators, or by a pump powered by a steam turbine. The turbine-driven pump trip and throttle valves were identified as potentially susceptible to tripping closed due to the seismic event. An operator action is defined in existing procedures to restore these valves so that both trains of AFW remain available. AFW would normally be aligned to take suction from the Condensate Storage Tanks. Since these are not credited (they are not seismically designed tanks), cooling water supply is provided by the Cooling Water system which takes suction from the Mississippi ' River. ("T Short Term Inventory Control (Injection) All SSCs credited to provide Short Term Inventory Control were found to be seismically rugged. Both trains of Safety Injection are available to provide Short Term Inventory Control i through supplies of borated water from the BAST, then from the RWST. Auto-transfer l l logic and valves to effect the realignment from BAST (when empty) to the RWST have been determined to be capable of surviving the seismic event. Long Term Inventory Control (Recirculation) All SSCs credited to provide Long Term Inventory Control were determined to be seismically rugged to the SSE level and are available to perform their intended functions. No credit has been taken for the RCS Cooldown and Depressurization function, which involves systems such as Auxiliary Spray, RHR Shutdown Cooling, and Secondary Depressurization. Long Term Inventory Cooling Control is supported by Safety Injection in its recirculation mode of operation. After the inventory in the RWST is depleted, SI is aligned to take suction from the RHR pumps which are, in turn, taking suction from the containment sump. The sump contains the inventory spilled through the postulated small LOCA, including primary system coolant and the contents of both the B AST and RWST.

 ']

A-60

q Containment Pressure Control V

All SSCs associated with Containment Pressure Control were found to be seismically rugged to the SSE, or are being evaluated for adequacy under the closure of the Prairie Island USI A-46 Program.

Prairie Island has two diverse systems to provide Containment Pressure Control. The Containment Spray system has not been credited in the seismic IPEEE. Cooling of the decay heat load in the containment is provided by the Containment Air Cooling system. Four FCUs, two in each independent train, remove heat via the Cooling Water system. Each train of FCUs is sufficient to provide decay heat removal. AC Power All SSCs associated with AC Power system were found to be seismically rugged to the SSE, or are being evaluated for adequacy under the closure of the Prairie Island USI A-46 Program.

                                                                                                 )

l Both trains of Emergency Diesel Generators and associated electrical supply / distribution i equipment are available in both Units following the earthquake. Therefore, no  !

;   consideration has been made for the ability to cross-tie units to compensate for an          )

unexpected loss of equipment, which represents additional margin not accounted for in this investigation. Due to the loss of offsite power, the diesels come on-line immediately and provide AC power to enable plant response throughout the event and subsequent I recovery actions. s DC Power All SSCs associated with DC Power were found to be seismically rugged to the SSE, or are being evaluated for adequacy under the closure of the Prairie Island USI A-46 Program. Two trains in each unit are available to support vital loads such as instrumentation, reactor protection, fire protection and EDG control power. Cooling Water The normal water supply for the CL system is from the circulating water pump bays in the screenhouse. The three vertical safeguards pumps take a suction on an emergency bay and discharge to the common CL header. The emergency bay receives water normally from the circulating water bays through two normally open sluice gates, but also has a separate emergency supply intake pipe (36" diameter) which supplies water directly from the Mississippi River. The emergency intake line supplies water from a channel in the river at a point that assures submergence of the intake line if Lock and V Dam fi3 downstream of the plant were lost. The emergency intake pipe would be required A-61

C' s become blocked or if Lock and Dam #3 fails. If either et these scenarios were postulated to occurr, the cooling water supply would be limited to the inventory in the intake cana'

plus the flow through the 36" safeguards pipe. As the flow required for two-pump operation exceeds the capacity of the safeguards pipe, operator action to reduce cooling water loads is required. These actions include isolating turbine building loads and containment fan coil units. Given the size of the intake canal, more than four hours are available to reduce and manage Cooling Water loads under these conditions. This leads to the conclusion that sufficient cooling water is available following a seismic event to enable the safe shutdown of both units as the SSCs of the Cooling Water system that are nessary to do this have been found to be seismically rugged to the SSE, or are being evaluated under the closure of the Prairie Island USI A-46 program.

Conclusions and Recommendations As shown, all the functions for both units that are needed to ensure adequate core cooling and containment pressure control following the earthquake and the postulated events caused by the earthquake have multiple and, in some cases, diverse trains of equipment available. As a result, it is concluded that the Prairie Island plant has no vulnerabilitier to seismic events, b 1 l l O A-62

f O Tcble A.2.4-1 9 Disposition cf Ccmponts Ntt Meeting RedIced Scope Scree:irg O Compoent System Potential Failure Mode Conclusion CV-39401 and CV-39409 CL damage due to seismic- to be addressed by SQUG induced impact with outlier resolution adjacent conduit Containment Fan Coil Unit ZC demand exceeds capacity to be addressed by SQUG 13 outlier resolution 11 and 21 Batteries DC did not meet screening to be addressed by SQUG caveats program outlier resolution 12 and 22 Batteries DC missing spacers noted in to be addressed by SQUG the walkdowns program outlier resolution 11,12, and 22 Baticy DC anchorage to be addressed by SQUG Chargers program outlier resolution D1 and D2 Diesel Generator DG panels are supported by to be addressed by SQUG Gage Panels very flexible, outlier resolution unrestrained vibration isolators DC Panels 11,12, and 22 DC scismic-induced bending to be addressed by SQUG stresses in the anchorage outlier resolution 11,21 Screenhouse Roof CL anchorage to be addressed by SQUG Exhaust Fans outlier resolution A-63

Tchie A.2. c:ntined Disposition of Components Not Meeting Reduced Scope Screening Component System Potential Failure Mode Conclusion i 12 and 22 Jacket Heat DG vessel sliding due to lack to be addressed by SQUG j Exchangers for12 and 22 of structural connection outlier resolution Diesel Engines between vessel and saddle supports . 12 and 22 Diesel Driven CL anchor bolts do not to be addressed by SQUG Cooling Water Pumps satisfy minimum edge outlier resolution distance requirements and the vertical shaft i length exceeds component caveats , MCC I AB1 and 1 AB2 AC 480 inadequate anchorage to be addressed by SQUG outlier resolution MCC1K1 AC 480 relay chatter due to to be addressed by SQUG i seismic-induced impact outlier resolution from wall-mounted RHR

Lifting Block Fixtures MCC 1L2 AC 480 relay chatter due to to be addressed by SQUG seismic-induced impact outlier resolution from rod-hung piping MCC 2K2 2AC 480 relay chatter due to to be addressed by SQUG seismic-induced impact outlier resolution from rod-hung pipe A-64

    /~ s b                                                                                                                   Tcble A.2. , continted s .

Disposition of Components Not Meeting Reduced Scope Screening Component System Potential Failure Mode Conclusion MCC ITA1 and 1TA2 AC 480 components are to be addressed by SQUG supported shirns outlier resolution producing seismic-inducing anchor bolt bending MCC 2LA2 2AC 480 welded anchorage is very to be addressed by SQUG , minimal outlier resolution  ! 121 and 122 Cooling Water FO undetermined flexibility to be addressed by SQUG Pump Fuel OilStorage of buried pipe outlier resolution i Tank 121 and 123 Diesel FO undetermined flexibility to be addressed by SQUG Generator Fuel Oil Storage of buried pipe outlier resolution Tank Pressurizer Relief Valves RC Floor response demand to be addressed by SQUG 1RC-10-1 and 2,2RC-10-1 may exceed capacity outlier resolution ,. and 2 Relay Room North (121, ZH anchorage to be addressed by SQUG 122) and South (121,122) outlier resolution Unit Coolers 121 and 122 Control Room ZH unrestrained vibration to be addressed by SQUG Chillers isolators outlier resolution i Control Room Ceiling falling ceiling diffusers to be addressed by SQUG outlier resolution A-65

Tcble A.2. c:ntined Disposition of Components Not Meeting Reduced Scope Screening Component System Potential Failure Mode Conclusion Panels 132 and 133 AC Seismic interaction support of bus room cooling function determined to be unnecessary 11,12,21 and 22 RHR Unit ZC Structural integrity support of room cooling Coolers uncertain function determined to be unnecessary Switchgear/ Bus Room Unit ZH Anchorage support of bus room Coolers (for buses 111,112, cooling function 121,122,15 and 16) determined to be unnecessary D5/D6480V Aux. Air DG Anchorage support of bus room Handlers (21/22) and 480V cooling function Switchgear Room Aux. determined to be Condensing Units (21/22) unnecessary 11,12,21 and 22 CS Anchorage not credited, redundent Containment Spray Pumps to containment FCUs 11,12,21 and 22 SG Level S signal Anchorage and S signal source Logic Relays and Bistables interaction considered redundent CV-31059 and CV-31060 AFW seismic-induced trip of Valve can be reset the valve trip device through operator actions A-66

r' (.)\ Tcble A.2.4-1, c:ntirued

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Disposition of Components Not Meeting Reduced Scope Screening Component System Potential Failure Mode Conclusion Air Compressors for 12 and CL Anchorage Air receivers contain 22 Diesel Cooling Water enough air for diesel Pumps starting 122 and 124 Diesel FO undetermined flexibility not credited, capacity and Generator Fuel Oil Storage of buried pipe cross-connection of tanks Tank 121 and 123 is sufficient 11,12,21 and 22 SG PORV MS Anchorage Not credited in seismic Accumulator IPEEE evaluation 11,12,21 and 22 Boric Acid VC Anchorage Not credited in seismic Transfer Pumps IPEEE evaluation 13 and 23 Charging Pumps VC Anchorage Not credited due to sufficient charging capacity by pumps 11/12 and 21/22 Buses 11,12,13 and 14 AC Anchorage Do not support equipment credited to respond to plant conditions MCCs IM1,1M2, IMA1 AC Anchorage Do not support and IMA2 equipment credited to respond to plant conditions A-67

V Tcble A.2.4 , c:ntined Disposition of Components Not Meeting Reduced Scope Screening Component System Potential Failure Mode Conclusion 14 and 24 Inverters AC Anchorage Do not support equipment credited to respond to plant conditions Panel 117 AC Anchorage Does not support equipment credited to respond to plant conditions Panel 217 AC Shimmed Anchors Does not support equipment credited to respond to plant conditions Panels 313 and 3133 AC Interaction Do not support equipment credited to respond to plant conditions Panel 153 DC Interaction and shimmed Does not support anchors equipment credited to respond to plant conditions 1 A-68 i

Tchle A.2. e:ntirued Disposition of Components Not Meeting Reduced Scope Screening < Component System Potential Failure Mode Conclusion 121 Cooling Water Pump CL anchor bolts do not not credited, redundant satisfy minimum edge to 12 and 22 Diesel distance requirements Driven Cooling Water and the vertical shaft Pumps length exceeds component caveats CV-31421 VC Interaction Does not support  ! equipment credited to respond to plant conditions , CV-39411 CL damage to limit switch valve fails safe, damage due to seismic-induced to limit switch will also ' impact with adjacent cause valve to fail safe < valve MV-32068 SI Interaction valve already in required position and is not required to change positions, interaction not i expected to cause change of position MV-32086 VC Interaction valve normally closed and function not required, interaction not expected to cause change of position i I A-69  ;

          - - - - - - - - - , _ _ _ _ . - - - - - - - - - , - - _ . . - - - - - - - - - - - - - - - _ - - _ _                          -           - - - , - - - - - - _ +             _  a - -    _     u.- a           x- .c-           --e---- e-n    -- m ~ . -+r    ~   ~ --w, , -

h Tcble A.2.4T, c= tin ed Disposition of Components Not Meeting Reduced Scope Screening Component System Potential Failure Mode Conclusion MV-32117 CC Interaction valve normally closed and function not required, interaction not expected to cause change of position MV-32267 CC Interaction valve already in required position and is not required to change positions, interaction not expected to cause change of position MV-32386 CL Interaction valve already in required position and is not required to change positions, interaction not expected to cause change of position 11,12, and 22 Condensate AF inadequate anchorage not credited Storage Tanks 11 and 21 Boric Acid Filters VC Anchorage not credited Bus 22 UV Relays 2- RP Signal Shimmed anchors and Unnecessary due to 27A/B22-XA and 2- interaction redundancy in RP signal 27B/B22-XA sources A-70

O O Tchie A.2.4-1, crntined O Disposition of Components Not Meeting Reduced Scope Screening , Component System Potential Failure Mode Conclusion CC Pump Discharge CC Mercoid switch Auto-start function Pressure Switches (PS-16262 redundant to other signal thru 16265) sources Containment Pressure S signal Interaction Function not credited Transmitters (1FT-948,2PT-  ; 945) . CL Pump Low Header CL Mercoid Switches Auto-start function Pressure Switches (PS- redundant to other signal 16002,16009,16259) sources D2 Diesel Generator DG relay chatter due to outlier, recommend a Control Panel seismic-induced impact maintenance activity to  ! from wall-mounted restrain or move the scaffolding scaffolding Bus 25 2AC 4160 relay chatter due to outlier, recommend a seismic-induced impact maintenance activity to from wall-hung ladder restrain or move the l ladder

                                                                                                                                                                                                                                                                  +

h A-71

4 i A.2.5 Analysis of Containment Performance As indicated in NUREG-1407, the focus of the containment evaluation is to identify any severe accident issues unique to seismic events that may involve early failure of 1 important containment functions. The containment evaluation for Prairie Island revealed j no such issues. The purpose of this section is to review and discuss the containment l response following a seismic event and to present the details of the containment-related evaluations that were performed for the seismic IPEEE.

A.2.5.1 Basis for the Scope of the Analysis 4

The scope of this containment analysis is based upon a review of the Level 2 analysis in

the internal events PRA [19], as well as the specific issues presented in Section 3.2.6 of I

NUREG-1407. The focus of the evaluation was to identify any potential early 4 containment failure modes unique to seismic events that had not already been evaluated

,           as a part of the internal events PRA. This evaluation was performed assuming disposition j            of components requiring additional evaluation performed according to Section 2.4 had been completed.

i The NUREG-1407 guidance requires an evaluation of any seismically induced l containment failures and other containment performance insights. Particularly,it should . consider vulnerabilities found in the systems and functions which could lead to early containment failure or which may result in high consequences. These include containment isolation, bypass, and integrity, and systems required to prevent early failure. A.2.5.2 Cor tainment Structures and Systems A seismic assessment was performed to identify any vulnerability that could lead to early failure of containment functions. The structures, systems, and components needed to , ensure containment integrity, containment isolation, and prevention of bypass were reviewed.

Containment Structures The containment structures and components were evaluated as described in Section A.2.3. The Unit I and Unit 2 containment vessels were found to be seismically adequate for the reduced scope review. A review of the design basis seismic results (USAR) indicated that the containment vessel and components could be screened from further review based on the USAR requirements.

A general review of the Unit I containment penetrations did not identify any significant seismic vulnerabilities. Detailed walkdown reviews of the Unit 2 containment penetrations and components confirmed similarities to Unit I and also did not identify any seismic vulnerabilities. The equipment hatches, personnel airlocks, and containment (] k./ penetrations do not have inflatable seals or cooling systems. Therefore, it was concluded i A-72

that the containment structures and components have no seismic vulnerabilities that could ( lead to early containment failure. Containment Systems Systems important to maintaining containment integrity after a core damage event were identified in the Prairie Island internal events PRA. A summary of these systems and the functions that they provide follows: Containment Isolation Isolation Valves Debris Cooling (In-vessel and Ex-vessel) High Head SI Low Head SI Containment Spray Containment Pressure Control RHR (aligned for high head or containment spray recirculation) Fan Coil Units Radioactive Release Control Containment Spray Fan Coil Units For components in many of these systems, a screening evaluation was done as part of the plant walkdowns and seismic margins assessment, as discussed in Sections A.2.2, A.2.4, and A.2.5. The functions and systems listed above were reviewed to determine whether all systems which are important to containment performance were evaluated during the seismic margins assessment. In this containment evaluation, any system or component which must be disabled in order to reach core damage was not credited as a means of avoiding containment failure. Table A.2.5-1 summarizes the systems which would be available to provide functions such as debris cooling and con'ainment heat removal. The accident sequence types defined in the internal events PRA are presented below. Each discussion supports the conclusions that (1) the majority of systems important to containment performance under severe accident conditions were considered as a part of the seismic margins assessment, and (2) the containment response to core damage following a seismic event is similar to that analyzed in the internal events PRA. O A-73

l m Containtnent Response Fourteen accident classes or accident sequence types were defined in the internal events PRA. These include: TEH Transients (non-LOCA) in which core damage occurs at high reactor pressure without high head injection , 1 TLH Transients (non-LOCA) in which core damage occurs at high reactor pressure without high head recirculation I BEH Station Blackout events leading to core damage i i SEH LOCAs in which core damage occurs at high reactor pressure j without high head injection SLH LOCAs in which core damage occurs at high reactor pressure l without high head recirculation SEL LOCAs in which core damage occurs at low reactor pressure without low head injection SLL LOCAs in which core damage occurs at low reactor pressure p without low head recirculation V GEH Steam Generator Tube Rupture in which core damage occurs without high head injection GLH Steam Generator Tube Rupture in which core damage occurs after RWST depletion , l FEH Internal flooding leading to core damage without high head injection i l FLH Internal flooding leading to core damage without high head recirculation REP,RLO ATWS leading to core damage The two initiating events which may accompany a seismic event are a loss of offsite power or a small loss of coolant accident. These initiators are associated with the first  ! five of the accident classes given above. For each of the first five accident classes, a comparison between the plant response as analyzed in the internal events PRA and the , response that would be expected if the accident were initiated by an earthquake is i described below. Because of the design capacity of the piping components that lead to ( L eight of the remaining accident classes (medium or large LOCA, steam generator tube rupture, and floods leading to failure of multiple trains of safe shutdown equipment), the A-74

E potential for a seismic event to lead to these accident sequence types is considered to be i Iow. Transient or Small LOCA at High Reactor Pressure without High Head

Injection (Classes TEH andSEH)

{ For these accident classes, core damage is assumed to occur as a rnult of the loss of secondary heat removal and high pressure injection in the bleen and feed mode ] (transient initiators). Small LOCAs are assumed to lead to core damage either as j a result ofloss of Safety Injection or secondary heat removal. If high pressure , injection is not recovered before the core melts through the vessel lower head, then the reactor would depressurize when the lower head is breached. Both high i pressure and low pressure coolant makeup systems would then be able to cool the debris in the reactor cavity. These are the same systems that were considered in i the internal events PRA for debris cooling. The same systems credited in the internal events PRA for long-term decay heat removal would also be available j following an earthquake: RHR and Fan Coil Units. Due to the number of systems available to provide debris cooling and decay heat removal, only a limited fraction of the sequences initiated by transients or LOCAs and having high reactor pressure would be expected to lead to early containment failure. The containment 4 response to core damage events in these accident classes is expected to be the j same regardless of whether the accident is initiated by an earthquake. Transient or Small LOCA at High Reactor Press ee without Recirculation { (Classes TLH andSLH) For these accident classes, secondary heat removal may have been lost but Safety l Injection has provided adequate core cooling. Core dai . age occurs as a result of l the inability to establish high head recirculation. Forinese accident sequences,

the RWST contents have been injected to containment and reactor cavity level is

such that the lower vessel head is submerged. Heat transfer through the lower

head to the water in the reactor cavity is likely to be sufficient to prevent lower

[ head penetration. As long as a containment heat removal system is available, , l such as the Fan Coil Units, the core damage event can be terminated within the  ! vessel. Containment response to seismic events leading to this accident class

results in no early or late containment challenges that were not already identified in the intemal events PRA.

Station Blackout (BEH) i The potential for core damage due to station blackout sequences results primarily from battery depletion. If no AC power source is recovered within the first four to i six hours of the blackout, the uncooled core debris in the vessel could melt A-75

o through the lower head and enter the containment. A part of the core debris b would be entrained in the steam during vessel blowdown and carried in to the upper compartment of containment. The rest would remain in the reactor cavity. l Early challenges to containment for a core damage event resulting from a station l blackout are the same as considered in the internal events PRA. If no means of l cooling the debris or removing decay heat from the containment is recovered, the 1 containment would eventually pressurize; however, this would take place so l slowly that it would take roughly a day or more to reach the containment failure pressure. The timing and response of the containment to severe accident conditions associated with a seismically initiated station blackout are very similar ; to the internal events PRA. Table A.2.5-1 provides a summary of Level 1 to Level 2 dependencies for these accident classes. Containment Isolation Isolation valves are provided on all lines penetrating the containment to assure its integrity under accident conditions. Those isolation valves which must be closed to assure containment integrity immediately after a major accident are automatically controlled. , () Many different types of penetrations were considered during the containment isolation evaluation of the internal events PRA. The following piping and hatch penetration groups were examined:

• Safety Injection lines
• RHR lines
• Containment Spray lines
• Component Cooling lines i l

e Cooling Water lines l l

• Purge and vent imes e Containment sump discharge and suction lines
• Containment vacuum breaker lines
• Equipment hatch, and personnel and maintenance airlocks

        . Fuel transfer tube

• Instrument Air lines
• Instrument and sample lines e Charging and letdown lines e RCP seal cooling lines

[ . Steam generator blowdown lines A-76

q . Feedwater, auxiliary feedwater, and main steam lines O e Fire Protection lines The first two penetrations listed are important when analyzing the potential for containment bypass or interfacing systems LOCAs, because breaks or leaks in such lines could result in releases directly from the reactor vessel into the plant buildings. However, since these piping systems are seismically rugged, they do not contribute significantly to the potential for containment bypass following a seismic event. The remaining penetrations and piping must remain intact or be isolated to prevent flow from the containment atmosphere into the auxiliary building or outdoors. If radionuclides are released into the containment or the containment becomes pressurized as a result of an accident, isolating the containment minimizes any releases to the outside atmosphere and avoids potential adverse impacts on accident mitigating systems in the auxiliary building. The following considerations were used to help focus the review of penetrations and piping in these groups:

  . Penetrations of open containment or reactor systems: If the system is not connected to the containment atmosphere or the reactor coolant system, the probability of simultaneous failure of the isolation valve (s) in the system and a pipe break is negligibly small.

(D V e Pipes with diameters greater than 2 inches: These pipes are considered to contribute most significantly to the magnitude of release following containment isolation failure. Furthermore, aerosol plugging is likely to reduce the amount ofleakage that could occur from smaller penetrations.

  . Hatches and airlocks: These items are closed during operations as part of tecimical specification requirements.
  . Normally closed lines: Lines containing normally locked closed valves, or lines containing closed valves that would not be expected to open during the course of an      j accident do not contribute significantly to containment isolation failure.
                                                                                               )

Table A.2.5-2 shows the containment penetrations that remain for further consideration j using the criteria given above. The table shows the configuration of the containment isolation valves, their normal positions, the signals required to close the valves, and the j dependencies of the valves on support systems for motive and control power.

                                                                                               ]

The isolation valves in this table are the same as those considered in the internal events PRA. It should be noted that many of these isolation valves are either normally closed or they fail closed on the loss of air or control power. These valves are designed such that the potential for containment isolation following a seismic event is high and can be p/ C considered similar to that evaluated for the internal events PRA. A-77

Tcbie A.2.5-1 Prairie Isla eval 1 t2 Levci 2 Debad:neies V 1 Accident Secondary Heat Debris Cooling Containment Class Removal Control Injection Recirculation AFW MFWI SC,Z St PZRZ C9 SI RHR C9 RHR FCU C9 PORV PORV Rectre Recire Recire  !

TEli - #6 v6 / / /

BEH / #4 /4 #4 #4 #4 SEli /5 v6 <6 / / /  ; TLH - 7 - / / / SLH #5 7 - / / / i 1 Assumed not to be available as a result of loss of offsite power 2 Assumed not to be available as a result of not crediting instrument air 3 Not credited in the Seismic IPEEE . 4 On AC power recovery 5 Provided reason for core damage is not secondary heat removal failure 6 Provided reason for core damage is not SI failure  ! 7 Function successfully performed as a part of Level 1

/ Credited in the Level 2 analysis

[; Failed as a part of Levell i I

                                                                                                                                                                                                            -f I

t I A-78  !

(- Tcble A.2.5-2 Ccatribators to Cee.trinment Is:l: tion Fcillres Description Penetraton Size Configuraten Positen Signals Ibwer/ Air Number istdown hne 11 2* 1 NC MOV in parallel with 4 NO Containment Isolation AOVs fad closed on loss of air AOVs: 1 NO in series with 3 in or DC parallel (1 NO and 2 NC) Chargmg line 12 2" 2 CV.1 AOV NO None AOV f ails closed on loss of air or DC RCP seal water supply 13A 2" 2CV in senes NO None None RCP seal water supply 13B 2" 2 CV in serns NO None None Instrument air 20 2" 2 AOVsin senes NO 1 mop A MSL isolation, hi- AOVs fait closed on loss of air hicontainment pressure orDC Containment sump A dtscharge 26 3* 2 AOVs in wries NO Containment Isolaton AOVs fait closed on loss of air or DC Containment vacuum breaker 41A 18" 1 AOV and 1 air-assist CV in NO Containment isolation AOVs tail open on loss of air series or DC Containment vacuum breaker 41B 18" 1 AOV and 1 airessist CV in NO Containment Isolaton AOVs tail open on loss of air series or DC l'ost-LOCA !!2 control air 42A 2" 1 MOV and 1 CV in series NC None MOV fails as-is on loss of AC Air vent 42A 2" 1 AOVs and 1 MOV in series NC None AOVs failckeed on loss of air; MOV fails as-is on loss of AC , NC Containment Isolation AOV fails ckwed on kus of air  ! Reactor makeup to PRT 45 2" 1 AOV and 1 CV in senes orDC , Post-LOCA i12 control air 50 2" 1 MOV and i CVin senes NC None MOV fails as-is on loss of AC l Air vent 50 2" 1 AOVs and 1 MOV in series NC None AOVs fait closed on loss of air; l MOV fails as-is on loss of AC [ t i l f i I i L i A-79

                                       .~ _ _ _ - _ _-_ _ _. _ _ _. _ _ . _ . _ -_ _ __ ._ _ .-_._ __. _ __ - _ _ _ _ _                                                                  _  _- __ __

zm A.2.6 Conclusions and Recommendations ! \ V The significant conclusions from the IPEEE seismic evaluation of essential Prairie Island structures and components for both Units 1 and 2 are that:

     . Class I structures were reviewed and were screened from any further seismic analysis based on the adequacy of the design basis USAR criteria. Seismic gaps between structures were considered during the IPEEE seismic walkdowns and were found to be consistent with design specifications.

• Masonry walls were evaluated and found to be seismically adequate to the SSE and were screened from any further review.
• Mechanical and electrical equipment, heat exchangers, and certain tanks are adequate to retain their structural integrity and post-emthquake functionality. Some equipment was identified in the IPEEE investigation as being questionable, but these are either being addressed through the closure of the Prairie Island USI A-46 Program or have been shown to have no significant consequences if they were to fail.
• Distributed systems such as piping, cable trays, conduit, and HVAC ducting were verified to be seismically adequate.

gm . There are no " bad actor" relays unique to the IPEEE equipment and systems credited h for plant response for core cooling and containment pressure control. The majority of equipment included in the scope of the Prairie Island seismic margins assessment are seismically rugged and meet the screening criteria in EPRI NP-6041-SL. The components that were found to be questionable in maintaining structural integrity and functionality were either already identified as " outliers" within the Prairie Island USI A-46 Program, or were shown to have no significant consequence in ensuring adequate core cooling and containment pressure control. A general maintenance provision to restrain all wall-hung ladders or remove them from the proximity of essential equipment can be used to address the potential seismic interaction. This will mitigate the potential for impact-induced relay chatter. A general maintenance provision is recommended since the locations of the ladders were transient. The containment response to a severe accident following a seismic event is expected to be similar to that analyzed for the internal events PRA. No early containment failure modes unique to a seismic event were identified as a part of this analysis. [v A-80

1 I 1 A.2.7 Unresolved Safety Issues and Other Seismie Safety Issues (3 g i

1. USI A-17 [16] systems interactions were considered in the IPEEE seismic walkdowns and seismic margin evaluations. Any significant seismic systems interactions were identified in the IPEEE walkdowns. USI A-17 is concerned with operational dependencies between systems. A qualitative analysis of these dependencies was considered in assessing the availability of plant functions following a seismic event. Insights from the internal events PRA were instrumental in this task.

2. USI A-40 [17] includes the seismic analysis of above-ground tanks. Most tanks important to the operation of the systems credited in the seismic margins assessment were found to have sufficient seismic capacity to meet the screening criteria of EPRI NP-6041-SL. The condensate storage tanks were not credited as a water source in the seismic margins assessment and therefore were not evaluated in the IPEEE.

3. The seismic walkdowns for the IPEEE were conducted following the initial walkdowns for USI A-46, " Verification of Seismic Adequacy of Equipment in Operating Plants [4]." Since l these efforts were conducted in parallel, significant information was shared between the two programs. The walkdown data obtained for the USI A-46 activities was made available for IPEEE.

n 4. USI A-45 [18] addresses the adequacy of the heat removal function at operating plants. U There are four possible methods of decay heat removal at Prairie Island: secondary cooling through the steam generators with Main Feedwater and Auxiliary Feedwater providing steam generator makeup, bleed and feed cooling utilizing the SI pumps and pressurizer PORVs, RCS injection and recirculation as provided by the SI and RHR systems (primarily for medium and large LOCAs), and Shutdown Cooling (SDC) mode of RHR operations after RCS has been cooled down and depressurized to RHR SDC conditions. Heat removal through the steam generators is the primary and preferred method of decay heat removal until the RCS pressure drops to the point where RHR SDC can be placed in service. Under normal conditions, Main Feedwater provides secondary cooling to the steam generators. However, in the event of an earthquake and associated loss of off-site power, Main Feedwater is unavailable. Steam generator makeup is then provided by Auxiliary feedwater. Two trains of Auxiliary Feedwater were evaluated and found to be seismically rugged to SSE levels. The availability of these trains of AFW in each unit ensure adequate steam generator makeup and decay heat removal. Bleed and feed cooling and the Shutdown Cooling mode of RHR are both assumed to be unavailable following the seismic event. Bleed and feed depends on pressurizer PORV operation. However, the PORVs are, in turn, dependent on instrument air to maintain a charge in the accumulators associated with the valves. Instrument air is not seismically designed and has been assumed to have failed due to the earthquake. There is sufficient air in A-81

4 4 1-l f- the PORV accumulators to support a limited number of cycles of PORV operation but not i enough to sustain bleed and feed operation. The Shutdown Cooling mode of RHR is not , credited in the IPEEE due to the unavailability of equipment to effect depressurization of the

RCS and the secondary system. With the primary system pressurized, short and long term cooling is provided by SI in injection and recirculation modes.

i SI is initiated immediately after the earthquake due to the assumption that the loss of off-site

j. power is accompanied by a small LOCA. SI initially operates in the injection mode,

providing primary coolant makeup from first the BAST, then the RWST. Collectively, these

! supplies of borated water are substantial but are expected to be depleted as their inventory is ! injected into the RCS and spilled through the small LOCA breach. As the RWST approaches { depletion, SI and RHR transition to recirculation mode in which the RHR pumps take suction j from the containment sumps and supply the suction to the SI pumps. This establishes a long j term cooling " loop" that removes decay heat from the reactor and releases it through the RHR i heat exchangers to the CC system. 1 Whereas steam generators /AFW and SI/RHR provide for reactor core decay heat removal,

two systems exist to provide containment pressure control to compensate for decay heat j rejected to the containment. Containment Spray, a system that sprays down the internal

, space within containment, was not credited in the IPEEE. Instead, Containment Air Cooling F has been evaluated and found to be seismically rugged to the SSE. Four fan coil units  ; l (FCUs) are configured in two separate trains, each consisting of two FCUs. The FCUs are ' i sized such that each can absorb 50% of the heat load to containment in the design basis l accident. Two functioning FCUs, therefore, ensure adequate containment pressure control. 4

The decay heat removal (DHR) issue was examined as part of the IPE, the details of which i

j are contained in Section 3.4.4 of the IPE submittal. The results of the seismic analysis for j loss of DHR did not differ significantly from the loss of DHR evaluated in the IPE. j Prairie Island's means of dealing with decay heat removal during accidents involving seismic

. events is similar to that described in the internal events IPE and is considered adequate to resolve this generic issue.

5. GI-131 (29] includes the seismic analysis of the moveable incore flux mapping system at l Westinghouse plants. A walkdown was performed together with a seismic margins analysis

of the flux mapping systems for both units. The mounting and the flux mapping system itself q were found to have sufficient seismic capacity to the SSE level of the USAR.

l 6. Charleston Eanhquake Issue: { The NRC states in Generic Letter 88-20, supplement 4, that the Charleston Earthquake Issue i is subsumed in the IPEEE. NSP has performed a seismic margins assessment for the Prairie Island IPEEE and therefore has fulfilled the requirements for this issue. ] i i A-82 }

n A.2.8 References V) 1. U.S. Nuclear Regulatory Commission, " Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities," Generic Letter 88-20, Supplement 4, June 1991.

2. U.S. Nuclear Regulatory Commission, " Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities," Generic Letter 88-20, Supplement 5, September 8,1995.

3. Jack R. Benjamin and Associates, et al, "A Methodology for Assessment of Nuclear Power Plant Seismic Margin (Revision 1)," prepared for the Electric Power Research Institute, EPRI NP-6041-SL, August 1991.

4. U.S. Nuclear Regulatory Commission, " Verification of Seismic Adequacy of Mechanical and Electrical Equipment in Operating Reactors, Unresolved Safety Issue (USI) A-46," Generic Letter 87-02, February 19,1987.

5. U.S. Nuclear Regulatory Commission, " Standard Review Plan," NUREG-0800, August 1989.

6. U.S. Nuclear Regulatory Commission, " Design Response Spectra for Seismic Design of Nuclear Power Plants," Regulatory Guide 1.60, Revision 1, December 1973.

O 7. Seed, H.B. and I.M. Idriss, " Soil Moduli and Damping Factors for Dynamic Response Analyses,' EERC 70-10, Earthquake Engineering Research Center, University of California, Berkeley, December 1972.

8. Schnabel, P.B., J. Lysmer, and H.B. Seed, " SHAKE - A Computer Program for Earthquake Response Analysis of Horizontally Layered Sites," EERC 72-12, Earthquake Engineering Research Center, University of California, Berkeley, December 1972.

9. Lysmer, J. et al, "SASSI - A System for Analysis of Soil-Structures Interaction,"

UCB/GT/81-02, University of California, Berkeley,1981.

10. Wong, H.L. and J.E. Luco, " Soil-Structure Interaction: A Linear Continuum Mechanics Approach (CLASS I)," Report CE, Department of Civil Engineering, University of Southern California,1980.

I1. Newmark, N.M. and W.J. Hall, " Development of Criteria for Seismic Review of Selected Nuclear Power Plants," prepared for the U.S. Nuclear Regulatory Commission, NUREG/CR-0098,1977.

12. American Concrete Institute and American Society of Civil Engineers, " Building Code p Requirements for Masonry Structures (ACI 530-88/ASCE 5-88) and Specifications for C Masonry Structures (ACI 530.1-88/ASCE 6-88)," ACI 530-88/ASCE 5-88,1988.

1 A-83

13. MPR Associates, " Procedure for Evaluating Nuclear Power Plant Relay Seismic Functionality," prepared for Electric Power Research Institute, EPRI NP-7148-SL, December 1990.

14. U.S. Nuclear Regulatory Commission, " Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities," NUREG-1407, May 1991.

15. Seismic Qualification Utility Group, " Generic Implementation Procedure (GIP) for Seismic Verification of Nuclear Power Plant Equipment," Revision 2, Corrected, February 14,1992.

16. U.S. Nuclear Regulatory Commission, " Unresolved Safety Issue (USI) A-17, System Interactions in Nuclear Power Plants." i

17. U.S. Nuclear Regulatory Commission, " Unresolved Safety Issue (USI) A-40, Seismic Design Criteria."

18. U.S. Nuclear Regulatory Commission, " Unresolved Safety Issue (USI) A-45, Shutdown Decay iIcat Removal (DHR) Requirements."

19. Northern States Power Company, " Prairie Island Nuclear Generating Plant Individual Plant Examination (IPE)," NSPLMI-94001, Revision 0, February 1994. I

20. SQUG program submittal; (from section A.2.5.1)

21. Jack R. Benjamin and Associates, et al,"A Methodology for Assessment of Nuclear Power Plant Seismic Margin (Revision 1," prepared for the Electric Power Research Institute, EPRI NP-6041-SL, August,1991.

22. Seismic Qualification Utility Group, " Generic Implementation Procedure (GIP) for Seismic Verification of Nuclear Power Plant Equipment," Revision 2, Corrected February 14,1992.

23. John A. Blume & Associates," Prairie Island Nuclear Generating Plant Earthquake Analysis:

Reactor-Auxiliary-Turbine Building," Report No. JAB-PS-02, prepared for Pioneer Service

     & Engineering Co., January 22,1971.

24. John A. Blume & Associates,"Piairie Island Nuclear Generating Plant, Earthquake Analysis:

Reactor-Auxiliary-Turbine Building Response Acceleration Spectra," Report No. JAB-PS-04, prepared for Pioneer Service & Engineering Co., February 16,1971.

25. Stevenson & Associates, "USNRC USI A-46 Resolution Seismic Evaluation Report,

" November 1995, Northern States Power Company, Prairie Island Nuclear Generating Plant, Units 1 & 2.

26. PINGP Engineering Calculation ENG-ME-185.

A-84 l l

1 1

27. PINGP Engineering Calculation ENG-ME-186.

i j 28. PINGP Engineering Calculation ENG-ME-177. ! 29. U.S. Nuclear Regulatory Commission, Generic Safety Issue (GSI) 131, " Potential Seismic i Interaction involving the Movable In-core Flux Mapping System Used in Westinghouse Plants". i l 4 i 4 l l 1 l i i l l A-85  :

O Prairie Island Individual Plant Examination of External Events (IPEEE) NSPLMI-96001 O Appendix B Revision 1 Internal Fires Analysis O B-1 I i

                                                                                                                                                                                                          ?

1 G Table of Contents  : b B.I INTRODUCT10N __ . _ B-4 B.I.1 BACKGROUND- . -_

                                                                                                                                                                                                    -B-4 B. I .2  PLANT FAM!UARIZATION . ... . .. ..                            .        .                                                                                            _ B-4   !

B.I.3 OVERALLMETHODOIDGY. . . . _ . . . . . . . . . . . . . . . . B-4 B.I.4

SUMMARY

OF MAJOR FINDINGS . B-5 B.2 INTERNAL F1RE ANALYS1S. . . .. . .. . . . B.IO s B.2.1 FIRE ANALYSIS METilODOLOGY. .

                                                                                                                                                                                                  . B-10   1 B.2.2 MODELING ASSUMPTlONS ..                          . . . . . . . . .                                                              . . . . . . . . - - -             .. B-!8      !

B.2.3 REVIEW OF PLANT INFORMATION AND SOURCES.. . . .,. . _ B-18  ; B.2.4 PLANT WALKDOWN-- . . . _B-19 B.2.4.1 Objectives ofPlant Walkdown., . . .. B-20 B.2.4.2 Walkdown Process.. . B-20 B.2.4.3 Findingsfrom Plant Walkdown.. . .. . B-20 > B.2.5 IDENTIFICATION OF IMPORTANT FIRE AREAS . B-21 B.2.S. I Reactor Building.. .. .. B-21 B.2.3.2 Auxiliary Building.. . . ..B-22 l B.2.5.3 Turbine Building . . .. B-22 B.2.5.4 Diesel Generator Building,. . . . ..B-23 B.2.3.S Screenhouse.. . ..

                                                                                                                                                                                                .. B-23 B.2.6 FIRE IGNITION DATA._                                                                   .                                                                            _- B-24 B.2.7 FIRE AREA INITIAL SCREENING-                                                                                                                   ..              .. B-34 B.2.8 FIRE DETECTION AND SUPPRESSION -                                                                                                                                     :B.34 B.2.8.1 Detection ..                                                            .                                                                                        . B-34 B.2.8.2 AutomaticSuppression.                      .

B-34 B.2.8.3 AfanualSuppression.. ...

                                                                                                                                                           .                                       B.40 B.2.9 FIRE GROWTil AND PROPAGATION--                                                                                                                                         B-45 B.2.10 FIRE EVENT TREES :                                                                                                                                                  . _ B-45 B.2.10.1 Fire Event Tree Top Event Definitions..                                                                    ..                   .                 .           ..B-46

B.2.10.2 Event Tree For Fire in blain ControlRoom and Relay Room.. ;B-48 l B.2.10 3 Fire in AFW Pump Room.. . . . . . . .. B-49 .

B.2.10.4 Accident Sequence Classification... ..B-49 l B.2.11 ANALYSIS OF FIRE SEQUENCES AND PLANT RESPONSE . . - . .

                                                                                                                                                                                                .. B-54 B.2.11.1 Important Accident Classes..                                                   .                                                                              .- B-54 B.2.11.2 Important Fire Areas / Rooms..                                                            .                                                                   - B-58 B.2.11.3 Unit 2 Considerations .          .        .                                                                       .                                            ..B-66

' B.2.12 ANALYSIS OF CONTAINMENT PERFORMANCE _ B-69 B.2.12.1 ContainmentStructures andSystems.. . .. B.69 B.2.12.2 ContainmentSystems - . ..B-71 ' B.2.13 TREATMENT OF FIRE RISK SCOPING STUDY ISSUES - ..B-75 l l B.2.13.1 Seismic / Fire Interactions.. . . ..B-76 B.2.13.2 Fire Barrier Efectiveness - . -,B-79 B.2.13.3 Efectiveness ofAfanualFire Fighting.. ..B-79 B.2.13.4 Total Environment Equipment Surviva!.. . ..B-80 B.2.13.5 ControlSystems Interactions.. . . ..B-8i B.2.14 USI B-45 AND OTIIER SAFETY ISSUES . . -B-81 j B.2.15 RESULTS AND CONCLUSIONS x . ...B-83 B.2.15.1 Summary ofResults.. . ..B-83 B.2.15.2 Conclusions andRecommendations.. ..B-83 j p B.2.16 REFERENCES B-84 V

                                                      ..           .                     .                        =

ATTACHMENT I . . .. . . . . . B-85 I ! B-2 l l

l. _. -

i l l List of Tables Table B.2.1.1 Prairie Island Appendix R Fire Areas..... . . :B-13 Table B.2.6.1 Weighting Factors for Adjusting Generic Location Fire Frequencies for Application to Plant . . Specific Locations (taken from FIVE methodology) - - B-26 i l Table B.2.6.2 Fire Ignition Sources and Frequencies by Plant Location : .. B-27 ! Table B.2.6.3 Prairie Island Ignition Source Frequencies by IPEEE Fire Area - - B-29 Table B.2.7.1 Summary of Prairie Island IPEEE Area Screening-- B-36 i Table B.2.8.1 Fire Detection and Suppression . . . . . . - - - . . . . . . . . . . . . . B-42 Table B.2.11.1 Prairie Island Plant Response to Area-Specific Fires - . B-64  ! Table B.2.12-1 Prairie Island Fire IPEEE Level I to Level 2 Dependencies . B-75 l i List of Figures ' Figure B.I.4.1 Core Damage by Accident Class. . .. ..B-8 i Figure B.I.4.2 Core Damage by Fire Area: . -B-9 l Figure B.2.1.1 Fire PRA Flow Chart . . B-17  ; Figure B.2.10.1 Fire-Induced Transient Event Tree.. . B-51 Figure B.2.10.2 Fire-Induced RCP Seal LOCA Event Tree-- D-52 Figure B.2.10.3 Fire-Induced Transient Event Tree, Control Room & Relay Room Areas- . . B-53

                                                                                                                                            }

r U  ! 1 l l

                                                                                                                                               \

B-3

i i l 1 ,o B.1 INTRODUCTION b D.I.1 Backeround The assessment that is described in this appendix addresses the internal fircs requirements of l Supplement 4 to Generic Letter (GL) 88-20, " Individual Plant Examination of External Events l l (IPEEE) for Severe Accident Vulnerabilities" [1], for the Prairie Island Nuclear Generating Plant. The fire analysis performed for the IPEEE began in 1992 and reflects plant changes made since the IndWidual Plant Examination was submitted in February,1994 [2]. This internal fire I assessrt at combines the probsbilistic risk assessment approach used in the IPE with the deterministic evaluation techr.iques of the Electric Power Research Institute's Fire Induced Vulnerabilities Evaluation (FIVE) methodology [4]. l B.1.2 Plant Familiarization Units 1 and 2 of the Prairie Island Nuclear Generatinr, Plants are 2-loop PWRs with large dry containments. Westinghouse Electric Corporation deaigned and supplied the nuclear steam l supply system and the turbine-generator units. Pioneer Service and Engineering (now Fluor Power Services, Inc.) was the plant's architect-engineer. Northern States Power constructed the plant. Each reactor core produces 1650 MWt with an electrical output of 560 Mwe, using 121 fuel assemblies. The plant is located within the city limits of Red Wing, Minnesota. p Construction started on June 26,1968 and full commercial operation began on December 16, ( 1973 for Unit 1 and December 21,1974 for Unit 2. Implementation of the requirements of 10 CFR 50, Appendix R, contributed significantly to the low overall risk due to fires at the Prairie Island facility. These requirements addressed issues such as fire barriers and penetration seals, administrative control of combustibles, fire brigade training and equipment, and protection of safe shutdown equipment. Fulfillment of these requirements resulted in physical modifications to the plant, including installation of Remote Shutdown Panels, re-routing of safe shutdown cables, and upgrading of fire barriers. The Nuclear Regulatory Commission's (NRC) Inspection Report, dated August 19,1988, documented the satisfactory resolution of the sections of 10 CFR 50, Arpendix R, applicable to Prairie Island. B.I.3 Overall Methodolony The Prairie Island fire study uses an approach that combines the deterministic evaluation techniques from the FIVE methodology with classical PRA techniques. The FIVE methodology provides a means of establishing fire boundaries as well as methods to evaluate the probability and the timing of damage to components located in a compartment involved in a fire. PRA techniques allow determination of compartment-specific core damage frequencies associated with fires within the various fire areas of the plant. For the Prairie Island Fire IPEEE, (3 compartments were identified and evaluated, then quantified using the fault trees and event trees 'd from the updated internal events PRA. B-4

l q The transient and small LOCA event trees from the internal events PRA and related fault trees C) were used to perform the quantification. These events were used because of evaluations which indicate that postulated fires at Prairie Island could result in these types of events. The resulting accident sequences were binned into three accident classes and subclasses, a subset of those used in the internal events PRA. These accident classes and their relative contributions are shown in Figure B.I.4-1. The contribution of specific areas to the core damage frequency is shown in Figure B.I.4-2. B.1.4 Summary of Maior Findines The principal finding of fnis analysis is that there is no credible single fire in the plant that would lead directly to the inability to cool the core. Without additional random equipment failures unrelated to damage caused by the fire, core damage will not occur. As a result, this study concludes that there are no major vulnerabilities due .o fire es ents at the Prairie Island Nuclear Generating Plant. The core damage frequency resulting from fires is estimated to be approximately 6.3E-5/ year. The total CDF for fire-induced core damage sequences is on the same order of magnitude as the core damage frequency for the internal events PRA. While this is consistent with the results of internal fire analyses at other sites, it should be noted that these results include a number of conservative assumptions. For example, automatic or manual fire suppression was not credited O V except in the Control Room, Relay Room, and AFW pump rooms. Fires were also assumed to completely engulf an area once ignited, unless suppression occurs. l l From Figure B.1.4.1, the core damage frequency is spread across three accident classes: early i core melt with the reactor at high pressure (TEH), late core melt at high pressure (TLH), and i early core melt at high pressure in conjunction with a small LOCA (SEH). Together these three classes account for nearly 100% of the core damage associated with internal fires. Accident class TEH is comprised of transient (i.e., fire) initiated events with loss of secondary heat removal (loss of MFW and AFW) and failure of bleed and feed. Reactor pressure is high at the time of core damage. Core damage occurs within approximately 2 hours of the loss of heat removal. Accident class TLH is characterized by transient initiated events with loss of secondary heat removal, successful bleed and feed but failure of recirculation. Reactor pressure is high at the time of core damage, which occurs on the order of 10 hours after the loss of secondary cooling. The SEH accident class for the IPEEE consists of RCP seal LOCA initiated events in which high head safety injection is not capable of preventing core damage. Reactor pressure is high at the time of core damage, which occurs relatively early (see TEH). p As shown in Figt.re B.I.4-2,95% of the plant risk associated with internal fires can be traced to () nine fire areas / burn areas. These rooms / burn areas are:

1. Auxiliary Building Ground Floor Unit 1 (FA 58),

B-5

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2. 480V Safeguards Switchgear Room-Bus 121 (FA 22),

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3. Turbine Building Ground & Mezz Floor Unit 1 (FA 05,08,14,21,27,57,69,94),

4. Relay (cable spreading) Room (FA 18),

t

5. 4KV Safeguards Switchgear Room-Bus 15 (FA 81),

j 6. 480V Safeguards Switchgear Room-Bus 111 (FA 80), } 7. Train "B" Hot Shutdown Panel and Air Compressor /AFW Room (FA 32),

8. Control Room (FA13), and

9. Train "A" Hot Shutdown Panel and Air Compressor /AFW Room (FA 31).

4 Auxiliary Building Ground Floor Unit 1 (FA 58)-44.0% of TotalInternal Fire CDF l A fire in this area could lead to failure of many components necessary for safe shutdown of the j plant. Both trains of Safety Injection, RHR and Component Cooling as well as all three charging j pumps are located in this area. This is an extremely large area with significant distance between sets of components. Fire wrapping of critical power and control cables provides protection for Train "B" equipment. A train of component cooling is available to prevent an RCP seal LOCA. 480V Safeguards Switchgear Room-Bus 121 (FA 22)-14.1% of TotalInternal CDF i Bus 121 powers a number of the Train B 480V components. Equipment affected by a fire in this ,

area includes the #11/13 Charging pumps, #12/22 AFW pumps, #122 Instrument Air I l

) compressor, #12,14,18 and 28 inverters, and #21 cooling water pump. Due to the electrical , equipment located in this area, electrical fires are the most significant ignition sources. The #11  ; ) AFW pump and main feedwater are available to provide secondary cooling. I 7hrbine Building Ground & Mezzanine Floor Unit 1 (FA 05, 08,14, 21, 27, 57, 69, 94)- 10.2% of TotalInternal Fire CDF i Fires in this combined area are relatively frequent and severe (compared to other areas) due to the $ higher potential for turbine oil and gas fires. A fire in this area has the potential to fail all of main feedwater and a train of AFW. Both feedwater pumps and all three condensate pumps are physically located in this area. Other key components located in this area are the main power  : cables between safeguards 480V AC Bus 121 and auxiliary building MCCs IK2 and 1KA2, , ) which supply power to two of the three charging pumps, component cooling water valve MV-32094, cooling water valve MV-32146 as well as Train B safety injection valves. Control Room, Relay Room (FA 13, FA 18)-3.1%, 6.2% of TotalInternal Fire CDF If not suppressed by automatic or manual equipment, a fire in the Control Room or Relay Room is assumed to cause loss of all equipment not controlled from the hot shutdown panels (HSDPs). The HSDPs assure the ability to shut down the plant in the event of a fire in either of these areas. i Successful fire suppression in the Control Room or Relay Room limits the damage to a single - B-6

(' cabinet in either area, where it is assumed the fire started. The single cabinet (one in each area) ( contains cables for both MFW and AFW, and is considered to be the worst case fire location within either space. Equipment available following successful suppression includes all other equipment normally controlled from the Control Room. Key systems available at the HSDPs include AFW and Charging. The availability of these systems from the HSDPs limits the risk significance of fires in the Control Room and Relay Room areas. 4KV Safeguards Switchgear Room-Bus 15 (FA 81)-5.8% of Total Internal Fire CDF A fire in the Bus 15 switchgear results in damage or loss of Train A components. The affected equipment consists of the #11 Si pump, #11 RHR pump, #11 Component Cooling pump, and power to Buses 111 and 112. Control cables for Feedwater and Condensate pumps also transit this space. Systems available for S/G makeup include #11 and #12 AFW trains. Electrical equipment comprises the majority of the ignition sources. 480V Safeguards Switchgear Room-Bus 111 (FA 80)-4.7% of TotalInternal Fire CDF A fire in the 111 bus room can result in damage or loss of a number of components. This equipment includes the #12 Charging Pump,121 Instrument air compressor, component cooling water valve MV-32093 (CC to 11 RHR heat exchanger), and Train A safety injection valves. Also, power for RWST to charging system make-up valve MV-32060 is obtained from Bus 111. p Electrical equipment comprises the majority of the ignition sources. Unit 1 AFW operation is V not affected by fires in this area.

          "B" Train Hot S/D Panel & Air Comp /AFW Room (FA32)-3.6% of Total Internal Fire CDF The #11/21 AFW pumps, instrument air compressors 121 and 122, MCCs l Al and 1 A2, and the "B" Hot S/D panel are located in this area. In addition to the equipment physically located ir the area, power to MCC 1K1 and various other Train A components are routed through this area.

Since the manual valve used to crosstie the Service Air system to Instrument Air is located in this area, it was not credited during fires in this space. Automatic wet pipe suppression is available and was credited in this area. l "A" Train Hot S/D Panel & Air Comp /AFW Room (FA 31)-2.9% of Total Internal Fire CDF Similar to FA 32, the #12/22 AFW pumps, instrument air compressor 123, MCCs 2Al and 2A2, and the "A" Hot S/D panel are located in this area. In addition to the equipment physically located in the area, and various other Train B components are routed through this area. Crosstie to the Service Air system is available following the failure of the Instrument Air system. . Automatic wet pipe suppression is available and was credited in this area. B-7

O O O 1 Figure B.1.4.1 - Prairie Island Fire PRA Core Damage Frequency by Accident Class e I-F22 l-869 SEH 1-F18 59%

                                                                                                                                                                                                                                                                                         '#8' TEH                                                                                                                                                                   -

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                                                                                                                                                                                                                                                                            - others lCDF=6.3E-05/yr l                                                                     l-ess /                        -

1-F18 l-F13 TLH , 5% NOTE: Arrows indicate fraction of accident class CDF due to most significant fire areas in each accident class Figure B.1.4.1 Core Damage by Accidem Class B-8

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B.2 INTERNAL FIRE ANALYSIS V B.2.1 Fire Analysis Methodolony This fire analysis combines the deterministic evaluation techniques of the FIVE methodology with PRA methods. The flow chart in Figure B.2.1.1 illustrates the process used to quantify accident sequences for the Prairie Island fire IPEEE. Phase I is a deterministic evaluation of fire spread and ignition source frequencies. Phase 11 is a probabilistic evaluation of core damage using PRA techniques. If conditional core damage frequencies are unacceptable following completion of Phase I, Phase Il continues with a deterministic evaluation of the effects of fire suppression and fire propagation. The FIVE methodology is used to establish fire boundaries and to evaluate the probability and the timing of damage to components located in a compartment involved in a fire. PRA techniques are used to determine compartment-specific core damage frequencies for fires within specific fire areas. Fire areas: The Appendix R fire areas for Prairie Island are defined in Table B.2.1.1. For this IPEEE fire analysis, those areas outside the main reactor / turbine building complex which meet both of the following criteria were screened from further consideration:

1. The area contains no system credited in the internal events PRA; cables supporting those systems are also not present in the area.

2. A fire in the area would cause no demand for safe shutdown functions because the operating crew can maintain normal plant operations.

In applying this criteria only fire areas outside the auxiliary / turbine building complex were screened from further evaluation. Spread of fires across boundaries: The spread of fires across fire area boundaries is addressed in the FIVE methodology. The following criteria are used in the FIVE methodology to identify boundaries which can be considered to prevent the spread of a fire:

1. Boundaries between two zones, neither of which contains safe shutdown components nor components whose failure could result in the initiation of a plant trip, on the basis that a fire involving both zones would have no adverse effect on safe shutdown capability.

2. Boundaries that consist of a 2-hour or 3-hour rated fire barrier, on the basis of fire barrier effectiveness.

3. Boundaries that consist of a 1-hour rated fire barrier with a combustible loading in the exposing zone (the zone containing the initiating fire) ofless than 80,000 Btu /ft2 , on the basis of fire barrier effectiveness and low combustible loading.

4. Boundaries where the exposing zone has very low combustible loading (<20,000 Btu /ft2 ), on the basis that manual suppression will prevent fire spread to the adjacent zone.

l l B-10

q 5. Boundaries where both the exposing zone and exposed zone (the zone threatened by the - O exposing fire) have a very low combustible loading (<20,000 Btu /ft2), on the basis that a significant fire cannot develop in either zone.

6. Boundaries where automatic fire suppression is installed over combustibles in the exposing zone, on the basis that this will prevent fire spread to the adjacent zone.

3 The first criterion was not credited in the Prairie Island fire IPEEE. That is, the potential for a fire to spread was evaluated whether or not there was safe shutdown equipment or the potential 4 for a plant trip in a given area. This is based on the conservative assumption that any fire will ) result in at least a manually initiated plant shutdown. If any one of criteria 2,3 or 5 were met, the potential for fire spread through or across the common boundary was assumed to be negligible. These three criteria credit fire boundary ratings and combustible loading. Criteria 4 and 6, in which fire suppression is credited, were not initially applied, to allow future evaluation of the impact of suppression and because the probability of automatic fire suppression systems failing to actuate is non-negligible. If any of the compartment fire events led to dominant core damage sequences without consideration of suppression, the effect of fire suppression was then evaluated in a probabilistic manner. This approach allowed identification (~T of fire suppression systems that have the greatest impact on fire-induced core damage. V The groupings of fire compartments due to fire spread potential are presented in section B.2.5 and shown in Table B.2.6.3. 1 Systems credited: Before fire sequence quantification could be performed,it was necessary to identify the functions and systems to be included in the fire IPEEE. The associated equipment l and cables and respective locations were then identified using plant documents (see section 1 B.2.3) in conjunction with the Prairie Island internal events PRA and a plant walkdown. As a result of this assessment, all systems credited in the IPE analysis were also credited in the fire IPEEE analysis. Accident sequence evaluation: The next phase of the analysis was a multi-step, progressive probabilistic evaluation that considered the sequence of events that must occur to create the loss of safe shutdown / risk-significant functions. Figure B.2.1.1 shows the flow path and the major steps in the process. These steps consist of determining ignition source frequencies and quantifying specific fire scenarios. Following accident sequence quantification, the impact of fire suppression and the potential for the fire to propagate to identified targets was considered for risk significant areas. The potential impact on containment performance and isolation was evaluated following the core damage assessment. 7q The first step of the accident sequence quantification was to identify and tally the ignition source V frequencies in each compartment. These sources were identified during the first walkdown and a B-11

"N compartment-specific ignition frequency was calculated in accordance with the methods det%1 (b  in FIVE. Section B.2.6 details the actual methodology used in these calculations.

The next step, quantifying specific fire scenarios, was performed using the ignition source information in conjunction with the fire spread and fire effects information developed in Phase I. All the basic events in the logic models of the internal events PRA related to cables or components in the burning location were assumed to be failed. At this point in the evaluation, it I was assumed that all equipment and cabling within the affected fire area or sub-area was destroyed. The core damage frequency for each of the fire areas and burn sequences was then quantified using the internal events PRA fault tree and event tree models. Fires in the Control Room and Relay Room included additional actions and assumptions that were incorporated into event trees developed explicitly for these rooms. The quantification yielded a core damage l frequency (CDF) for each area by incorporating the area-specific ignition frequencies and crediting the unaffected systems or trains included in the internal events PRA. The final step was to evaluate the impact of the fires on the containment structure and function. l Containment structural evaluations included factors such as combustible loading in and around the containment. The potential for containment isolation or bypass was also investigated. Most containment isolation valves fail in a safe (closed) position. Multiple failures are required to bypass the containment. Because of these and other factors, containment integrity is expected to o be maintained following any postulated fire. A more detailed description of these analyses is h contained in Section B.2.12. Uncertainties: Most of the uncertainty in the results is centered around assumptions made in the accident sequence quantification. These assumptions include those regarding credit for various systems and operator actions that may occur in response to a fire as well as those implicit in the l deterministic evaluation of plant response to a fire such as that contained in the FIVE methodology or experimental studies. As examples,' automatic and manual fire suppression were not credited except in the Control l Room, Relay Room, and AFW pump rooms. Fires were assumed to completely engulf the area in which they started. If deterministic methods had been applied to show the limit of the fire spread, core damage may have been reduced. Wherever possible, assumptions such as these were made in a conservative manner to bound uncertainties. Assumptions incorporated into risk-specific areas within the plant include the likelihood of fire propagation along horizontal cable trays (fire areas 58/73) and fires that are successfully suppressed in the Relay Room and Control Room. While there may be uncertainties associated with these assumptions, their application is supported by deterministic or experimental evidence under specific conditions. Further, the overall conclusions of the fire IPEEE can be shown to be insensitive to these particular uncertainties. That is, there is no one area in the Prairie Island plant in which a fire could start that does not require additional failures unrelated to the fire % before inadequate core cooling would result. B-12

_ _ . - _.. _ _ ._ . _._._ . _ . ~ _ - - _ - - -- -_ . _ . _ _ . _ _ _. l l I I Table B.2.1.1 PrairieIsland Appendix R Fire Areas FIRE  ! AREA AREA AREA TOTAL LOADING l NUMBER DESCRIPTION SQ.FT. BTU (106) BTU /FT2 j 1 Containment Unit i 8,660 659.1 76109 2 Ventilation Fan Floor, Unit I 9,570 263.6 27,544 1 3 Water Chiller Room, Unit I (121) 1000 42.4 42450 4N Fuel Handling Area 4,670 121.8 26,082 SN Old Admin BMg (Elev. 715') 3,522 60.7 17,235 6N Old Admin Building, HVAC Area (Elev.750') 1,540 6.24 4,052 7N Old Admin Building Office Area (Elev. 735') 7,532 64.0 8,497 i 8N Turbine Deck (Units 1 & 2) 54,870 8.9 162 9N Maintenance Shops 6,550 7.92 1209 10 Train "A" Event Monitoring Equipment Room 530 14.0 26,430 1I Unit i Normal Swgr. & Control Rod Drive Room 2,250 29.2 13000 12 OSC Room 1,000 31.2 31,180 13 Control Room 4,160 262.2 63,029 14N Working Materials Storage & Lunch Room 6,550 3A5 527 15 Access Control 3,060 85.8 28,039 , 16 Train "B" Event Monitoring Equipment Room 520 24.1 46,352 , 17 Unit 2 Normal Swgr. & Control Rod Drive Room 2,250 28.7 12,764  ; 18 Relay and Cable Spreading Rm., Unit I & Unit 2 4,160 1,684.1 404,829 + 19N Computer Room 980 9.8 10,000 20 Unit 14KV Safeguards Swgr. (Bus 16) 760 78.8 103,734 21N Unit 14KV Normal Swgr. (Bus 13,14) 1,690 15.3 9053 22 480V Safeguards Swgr. (Bus 121) 770 62.9 81,805 23N Unit 2 4KV Normal Swgr. (Bus 23,24) 1,690 25.5 15,089 24N Oil Storage Area 1,350 2,934 2.17x100 25 Diesel Gen #1 Room 1,460 159.2 109,04) 26 Diesel Gen #2 Room 1,350 157.2 116,444 27N Water Conditioning Equipment Area 3,800 16.4 4,316 28aN Transformer IGT (2) 2,526 N/A 28bN Transformer 2GT (2) 2,526 N/A 28cN Transformer IR (2) 1,132 N/A 28dN Transformer 1M (2) 678 N/A 28eN Transformer 2M (2) 678 N/A l 281N Transformer 2RX & Y (2) 746 N/A 29 Admin Building Electrical & Piping Room #1 1,100 44.1 40,091 30 Admin Building Electrical & Piping Room #2 1,100 42.8 38,955 l 31 "A" Train Hot S/D Panel & Air Compressor /AFW Room 1,180' 130.2 36,780 2,360' 32 "B" Train Hot S/D Panet & Air Compressor /AFW Room 1,180' 124.1 35,064 2,360' B-13

d Table B.2.1.I(continued) Prairie Island Appendix R Fire Areas FIRE  ! i k AREA AREA AREA TOTAL LOADING  ! 1 NUMBER DESCRIPTION SQ.FT. BTU (106) BTU /FT2 , 33 Battery Room iI 590 11.7 19,966 34 Battery Room 12 590 16.4 27,864 35 Battery Room 21 590 11.9 20,305 36 Battery Room 22 590 16.3 27,746 37 Unit i 480V Normal Swgr. (Bus 150,160) 1,030 44.4 43,172 38 Unit 2 480V Nomial Swgr. (Bus 250,260) 1,100 42.6 38,788 , 39N Radiation Waste Building 2,990 29.3 9,799 ) 40N Cooling Towers 121,122,123,124 (2) (2) ] 41A Screenhouse (DDCWP Room) 1,840 199.2 108,283 . 41B Screenhouse Basement 4,220 134.1 31,770 f

• 41N Screenhouse(General Area) (2) (2) i 42N Cooling Tower Pump House 3,670 67.8 18,474 43N Unit 2 Transformer Oil Sump (2) (2) (2) l 44N Unit 1 Transformer Oil Sump (2) (2) (2)

45N Fuel Oil and Transfer House 100 (2) (2)

! 46N Cooling Tower Equipment House & Transformers 1,620 68.7 42,407 4 47N Cooling Tower Transfomier Oil Sump (2) (2) (2) 48N Dl, D2 Diesel Fuel Oil Storage Tanks N/A (2) 11,260 N/A (2) 49N Heating Boiler Fuel Oil Storage Tanks N/A (2) 10,110 N/A (2) L SON Cooling Tower Control House 121 & 122 990 (2) (2) SIN Neutralizer Tank Pump House / Warehouse #2 212.5 (2) (2) 52N Parking Lot (2) (2) (2) 53N Receiving Warehouse, NPD Office & NPD Annex (2) (2) (2) 54N Cooling Tower Control Hose 123 & 124 990 (2) (2) 55N Warehouse #1 and Fab Shop (2) (2) (2) 56N Drum Storage Area (2) (2) (2) 57N Gas House 650 7.57 11,646-58 Aux Building Ground Floor Unit i 14,560 473.8 32,541 59 Aux Building Mezzanine Floor Unit i 10,700 829.9 77,570 60 Aux Building Operating Floor Unit 1 6,880 101.7 14,776 61 Aux Bldg Anti"C" Clothing (El. 735') 6,330 99.6 15,731 61A Aux Bldg Hatch Area (El 755') 12,440 100.9 8,114 3 . 62N Spent Fuel Pool Area 4,180 (2) (2) ! 63N Filter Room 2,430 (2) (2) 64N Aux Building Low Level Decay Area, Unit 1 830 2.6 3,133

65N Spent Fuel Pool HX & Pumps 1,090 (2) (2) 66 Storage Room D3 Room 1,470 (2) (2) i 67N Resin Disposal Building 2,680 68.84 25,687 s 68 Containment Annulus Unit i 1,710 25.5 14,906 69 Turbine Building Ground & Mezz Floor Unit I 21,680 3,262.5 150,484 70 Turbine Building Ground & Mezz Floor Unit 2 21,680 3,103.1 143,132 B-14

Table B.2.1.1(continued) Prairie Island Appendix R Fire Areas FIRE y AREA AREA AREA TOTAL LOADING NUMBER DESCRIPTION SQ.FT. BTU (106 ) BTU /FT2 71 Containment Unit 2 8,660 722.1 83,383 72 Containment Annulus Unit 2 1,710 25.6 14,965 73 Aux Building Ground Floor Unit 2 13,420 478.7 35,671 74 Aux Building Mezz Floor Unit 2 10,700 836.9 78,215 75 Aux Building Operating Floor Unit 2 6,880 103.6 15,055 76 Vent and Fan Room Unit 2 9,570 296.0 30,930 77N Aux Building Low Level Decay Area, Unit 2 830 (2) (2) 78N Waste Gas Compressor Area 1,510 0.3 199 79 480V Safeguards Swgr Room (Bus 112) 400 11.3 28,363 80 480V Safeguards Swgr Roorn (Bus 111) 870 39.02 44,853 81 4KV Safeguards Swgr Room (Bus 15) 860 38.7 45,005 82 480V Safeguards Swgr Room (Bus 122) 380 9.63 25,339 83N Inst. Lab Area, Operator's Lounge Area 1,490 2.1 1,409 84N Counting Room & Labs 6,680 2.3 344 85N Holdup Tank / Demineralizer Area 4,880 (2) (2) 86N Intake Screenhouse, Envir Lab, Rad Monitor Station & De- (2) (2) (2) Icing Pump House 87N Deepwell Pump House #1 110 (2) (2) O 88N Deepwell Pump House #2 110 (2) (2) V 89N Guardhouse 3,074 (2) (2) 3,140 (Note 3) 90N Emergency Generator Building Security Diesel 570 72.5 127,193 91N Diesel Fuel Pump & Decay Cooling Water Pump Oil N/A 6,205 N/A , Storage Tanks i l 92 Water Chiller Room Unit 2 (122) 1,000 44.45 44,450 i 93N Drum Storage / Low Level Radwaste Warehouse 12,400 (2) (2) 94N Service Building / Computer Area (2) (2) (2) 95N D5 Diesel Fuel Oil Stora;. Ianks N/A (2) 4,862 N/A (2) 96N D6 Diesel Fuel Oil Storage Tanks N/A (2) 4,862 N/A (2) 97 D5 Basement (El. 687') 2,100 185.6 97,000 98 D6 Basement (El. 687) 2,330 185.6 97,000 99N Stairwells (El. 695',707' & 7 I 8') N/A (2) N/A (2) N/A (2) j 100N #21 D5/D6 Fuel Oil Receiving Tank 429 2,098 4.9x106 l 101 D5 Diesel Generator Room 1,980 154.5 86,000 102 D6 Diesel Generator Room 1,980 153.7 86,000 103 D5 Emergency Diesel Generator Control Room 550 10.3 21,000 104 D6 Emergency Diesel Generator Control Room 550 10.1 20,000 105N D5 Battery Room 550 4.9 9,400 ( 106N 107 D6 Battery Room D5 inverter Room 550 460 4.5 1.3 9,100 3,000 B-15

Table B.2.1.1(continued) Prairie Island Appendix R Fire Areas O AREA NUMBER AREA DESCRIPTION AREA SQ. FT. TOTAL BTU (106) FlhE LOADING BTU /F T2 108 D6 inverter Room 460 2.0 4,300 109 D5 Normal MCC & Cable Tray Area 1,450 74 55,000 110 D6 Normal MCC & Cable Tray Area 1,600 70 48,000 til D5 Building- Mezzanine Floor Elev. 718' 440 13 32,000 112 D6 Building - Mezzanine Floor Elev. 718' 440 13 33,000 - 113 #21 D5 Fuel Oil Day Tank Room 125 88 700,000 114 #22 D6 Fuel Oil Day Tank Room 215 88 700,000 115 #21 D5 Lube Oil M-U Tank Room 90 123 1.4x100 116 #22 D6 Lube Oil M-U Tank Room 90 123 1.4x100 117 4KV Bus 25; MCC-2 TAI 1,480 68 51,000 118 4KV Bus 26; MCC-2TA2 1,400 53 42,000 119 #21 D5 Ht/Lt M-U Tank Pump Room $10 4.2 9,300 120 #22 D6 Ht/Lt M-V Tank Pump Room 510 4.2 9,300 121N Stairwell (El. 735') 402 N/A (2) N/A (2) 122 480V Bus 221/222 Room 1,650 23 15,400 123 D5 Radiator Room 1,280 9.2 8,200 124 D6 Radiator Room 1,280 9.6 8,500 125 D5 Fan Room 1,280 N/A (2) N/A (2) 126 D6 Fan Room 1,280 N/A (2) N/A (2) (/ 127 480V Bus 211/212 Room 1,480 24 17,600 128N 4KV Bus 27 Room 224 * (2) *(2) 129N D5 Radiator Exhaust (Roof) 1,280 N/A (2) N/A (2) 130N D6 Radiator Exhaust (Roof) 1,280 N/A (2) N/A (2) 131N New Admin Building (2) (2) (2) I 1 Loading based on 1180 sq. ft. for oil,2360 sq. ft. for cable; total BTU value based on /otal sq. ft. for fire area. 2 Entries in columns are taken directly from Prairie Island Fire Hazards Analysis (F.5, App. 5), Table 6-2. Blanks, "N/A" or "*" are as found in that table, and indicate that the FHA concluded that a fire in the area has not effect on plant shutdown; no safe shutdown equipment is located in that area. 3 First entry is ground level, second is basement level. O b B-16

k 1, ' T

     )

Phase I: Define Fire Areas i i I I I Separation Low Fire Loading Fire Barriers Low Loading & Barriers l I I I 4 FMEA of each area: W in eres Petermal are spread m es, ment

                                                                                              -type ofine rhno event o

Qualitettve ranking of Fire Areas based on irwhator, remommg emipment, etc d initiating Event

                                                                                                                           =

Frequency 1 Phase 11: sequence _ Quantification & Ranking i YES g c Acos noe went Are. Low? No Choose Method i I Fire gg Manuel M Suppresson N Anstrie supprnson i I l Redefine Fire Areas l l fy FMEA l

  )

Figure B.2.1.1 Fire PRA Flow Chart B-17

O B.2.2 wooeii iss m tio s The following key assumptions were made in this analysis: l

1. Loss of offsite power initiating event was found to be unlikely for a fire in any area.

f

2. The impact of fires on plant risk was quantified using the internal events PRA general

{ transient event trees. Fires that lead to a loss of Reactor Coolant Pump (RCP) seal coohng  : are assumed to lead to a RCP seal LOCA. These fire sequences transfer from the transient f event tree to the internal events small LOCA event tree model. These event trees were selected because they most closely represent the plant response given the systems being  ! modeled. l

3. ATWS events are not modeled due to the extremely low probability of an event involving a j fire coincident with a failure of the reactor protection system to function.  ;

4. Large LOCAs (LLOCAs), medium LOCAs (MLOCAs), and steam generator tube ruptures  !

(SGTRs) are not expected to be induced by a fire; simultaneous occurrence of these events l during a fire is probabilistically insignificant. }

5. Reference 10 indicates that the likelihood of significant fire spread in horizontal cable trays located in cable tunnels or corridors is negligible. If the only combustible material located in j O a fire area is a cabie insuiatie . a fire i itiatins in that aree is eet iiteir te spread. Therefere.

fires in horizontal cable trays are normally self-extinguishing. For those cable fires that did i not immediately self-extinguish during the tests supporting Reference 10, the maximum  ! propagation length was approximately seven feet. It was therefore assumed that fires would  ! not propagate in the cable trays across the fire area boundary separating fire areas 58 and 73 prior to extinguishing themselves or being suppressed.

6. Fires are assumed to spread until they engulf the entire sub-area in which they start unless the fire is suppressed. For this evaluation, no credit was taken for suppression except in the Control, Relay, and AFW pump rooms.

7. Hot shorts were not considered for the fire IPEEE evaluation. The occurrence of hot shorts was considered to be probabilistically insignificant. This is consistent with similar .

assumptions made in other fire analyses. B.2.3 Review of Plant Information and Sources Several sources ofinformation were reviewed and used in support of the Prairie Island fire IPEEE. The information sources most often consulted were the Prairie Island Individual Plant Examination (IPE] [2], the Prairie Island Fire Hazards Analysis [7], the Prairie Island Fire B-18

8 l i i hqtection Safe Shutdown Analysis Eneineerine Report [3], and the Fire-Induced Vulnerability Evaluation (FIVE) Report [4]. A complete list of the references used in support of this project is contained in Section B.2.16. , The IPE was used to identify important systems and functions and provided the base fault trees .j and event trees used to quantify the fire-related plant risk. The IPE also provided detailed l information on support systems for the important front-line systems. The Fire Hazards Analysis provided information on combustible loading, detection and suppression capabilities, and fire barrier ratings for fire areas within the plant. This document . also provided floor plans showing each fire barrier and identified adjacent and adjoining fire j areas. The fire area interaction analysis used the information contained in this document. The l floor plans contained in the Fire Hazards Analysis which were useful in the IPEEE are included - ) in this appendix as Attachment 1. j Prairie Island system functional block diagrams and existing 10CFR50 Appendix R data were l reviewed to determine the cables necessary for operation of the components included in the j models. These documents were the primary sources used to identify the cables that required l tracking. The Prairie Island cable tracking database from the plant information computer (CHAMPS) was then used to identify each of the cable trays and conduits containing these cables. The cable trays and conduits were then related to specific fire areas using the " Cable Node System" drawings. The result of this research was a database that contained information about cable and component locations and linked this information to basic events contained in the Prairie Island ) IPE. This information was then used to develop a spatial database to aid in identifying, for example, all equipment impacted by a fire in a given area, or all cables and components associated with a particular event failure. Key information contained within these records include: Equipment / cable ID # Related IPE event (relates equipment / cable to basic or developed event) Equipment location (for actual components) Cable location (fire area) System designator Cable raceway designator Comments B.2.4 Plant Walkdown j A series of walkdowns of the plants were performed in support of the IPEEE analyses. At a O minimum, a senior reactor operator and a fire IPEEE analyst participated in all walkdowns. Fire B-19

1 I l protection and electrical system engineers were called upon as issues and questions arose, O principally during the final walkdown, to confirm key assumptions used in the IPEEE. B.2.4.1 Objectives of Plant Walkdown i The primary objectives of the walkdown were to gather data, confirm information and j assumptions, and complete the NUREG/CR-5088 " Fire Risk Scoping Study" evaluation [11]. l The walkdown was used to determine whether the assumptions and calculations, particularly fire l barrier effectiveness assumptions, can actually be supported by the physical conditions that exist. This included verifying and validating (1) the combustible loading estimates in the fire hazards analysis, (2) the existence of fire protection systems, (3) fire barrier status, (4) interaction of fire areas, and (5) verification ofignition sources. The cable tracking database, used to identify cable

                                                                                                                ]

routing and locations, was also checked to ensure that it was up-to-date. B.2.4.2 Walkdown Precess During the walkdown, a pre-printed data sheet for each compartment was completed. This data sheet contained estimates, based on equipment layout drawings, of the number and type of ignition sources located in each compartment. The sheets also contained general comment sections where the analyst noted any unique or unexpected features (combustible loading, smoke paths, fire barrier status, etc.) that could impact the analysis. ' Q Important areas of the plant, as determined by the results of the fire IPEEE quantification, and l V areas of the plant that required validation of assumptions made during the analysis were inspected during the walkdown. Potential fire spread paths, equipment orientation, and fire barriers were also inspected. B.2.4.3 Findings from Plant Walkdown Several general findings were made during the walkdown. Boundary ratings were found to be generally conservative since there was a lack of combustible loading in close proximity to the barriers. The general condition of the plant was clean and well kept. If a compartment presented a significant ALARA concern and the area could not be inspected from the outside, the l compartment was not inspected. Instead, plant documents and operator knowledge formed the l basis for analysis of these spaces. These spaces and general information, other than ignition sources, are identified and documented in a walkdown summary. Specific findings which were generated during the plant walkdown are described below. To address the NUREG/CR-5088 " Fire Risk Scoping Study" issues, as required for the external j events fire analysis, inadvertent operation of a fire suppression system that could disable both trains of a system was investigated. The investigation was focused on areas where sprinkler heads or deluge systems might inadvertently operate. I From the Fire Hazards Analysis the areas containing automatic fire suppression systems was determined. This information was combined with walkdown observations to isolate any areas where multiple trains of a system might be impacted by inadvertent operation of the suppression B-20 i

1 1 i l J A system. Due to equipment separation, only Fire Areas 31 and 32 were identified in which b multiple trains could beimpacted. Fire Areas 31 and 32 each contain an AFW pump for each unit. In addition, Area 31 contains one instrument air compressor and two air compressors are located in Area 32. Due to the l physical arrangement of the equipment in these areas, it is unlikely that operation of a single sprinkler head would adversely affect both AFW pumps and air compressors. Therefore, l multiple sprinklers must actuate for these components to be threatened. Due to the reasons described, inadvertent fire suppression system operation is not considered to be a credible mechanism for disabling systems at Prairie Island. A single fire that disables all offsite power sources could have a significant impact on plant risk. For this reason, a walkdown of the turbine building 4KV areas was performed to determine i whether this scenario was possible. It was noted that power feeds from all sources (1R,2R, CT-11 and CT-12 transformers) are not routed together in the same fire area anywhere in the turbine building. The turbine building contains all the buses fed by these sources. Fires in the bus rooms i are prevented from propagating to fail all sources by fire barriers. This anangement ensures a l single fire will not damage all offsite power feeds. A review was performed to assure the reliability of the database that was used in cable identification. Administrative cable and raceway controls are in effect that provide a systematic (V~] way of tracking and entering all cable modifications and data changes occurring in the plant. It was determined that these as well as other supporting procedures provide the controls and record-keeping necessary to ensure that the database is accurate and up-to-date.  ; 1 H.2.5 Identification ofImportant Fire Areas The Appendix R fire areas provide the starting point for this analysis. In accordance with Appendix R requirements and the Prairie Island Fire llazards Analysis, a fire area is defined as a portion of a building that is separated from other areas by boundary fire barriers. Only a single train of safety equipment is allowed within a given fire area unless the redundant train is protected by additional separation requirements detailed in Appendix R of 10CFR50. The FIVE boundary evaluation criteria used to define burn sequences are similar to those originally used for defining Appendix R fire areas. These criteria include spatial separation of components and cables, combustible loading, and/or construction barriers. The boundary criteria are found in the FIVE methodology and are discussed in Section B.2.1. Fire areas for Unit I and common Unit 1/ Unit 2 areas are described below. B.2.5.1 Reactor Building The Appendix R analysis divides the Unit 1 Reactor building into two fire areas: the containment /O (fire area 1) and the containment annulus (fire area 68). These fire areas were so divided to facilitate detailed evaluation of the effects of fire within this structure. The fire area boundaries and interfaces are described below. B-21

The containment is a cylindrical concrete and steel structure that houses reactor coolant system V components and the steam generators. The containment is completely enclosed by a secondary structure: the shield building. The containment annulus abuts the auxiliary building to the north and west between the 695' and 755' elevations. This interface consists of a three-hour fire rated reinforced concrete barrier. Exterior walls are located along the south. A significant fire in the containment is not likely given its combustible loading and physical configuration. Much of the combustible material located in the containment is lube oil for the reactor coolant pumps. An oil collecting system that collects the oil in the event of a spill is installed. The remaining combustible material, electrical cable, located in these areas is fire retardant (IEEE-383 rated). Because of these factors, a significant fire within the containment is not expected to occur. The FIVE methodology recognizes the unlikely occurrence of a containment fire and does not provide an ignition source frequency for this area. H.2.5.2 Auxiliary Building The auxiliary building is located between the reactor buildir.g to the south and the turbine building to the north, sharing a common interface with each building. The Unit I and Unit 2 auxiliary buildings share a common boundary and are essentially mirror images of each other. This common boundary runs in a north / south line and is a combination of hard walls and some open spaces. () V The Appendix R analysis divides the Unit 1 auxiliary building into eleven fire areas (2,3,10,11, 12,15,58,59,60,64,79) unique to Unit I and nine fire areas (4,13,18,19,61,62,63,84,85) shared by both units. The auxiliary building is separated from the turbine building by 18" thick reinforced concrete walls. The auxiliary building is also separated from the diesel renerator and maintenance work areas to the east by 18" reinforced concrete walls. The floors and ceilings in the auxiliary building are concrete and 12" or greater in thickness. All of these boundaries are rated as three-I hour fire boundaries or equivalent. Much of the equipment shown to be significant in the PRA is located in the lower level of the auxiliary building (695'). This level of the auxiliary building is approximately 165' by 100' in size. The space contains component coolirp pumps and heat exchangers, all three charging pumps, both safety injection and containment spray pumps, as well as the RHR pumps and heat exchangers. H.2.5.3 Turbine Building The turbine building shares a common wall with, and is located due north of, the auxiliary building. This structure contains seventeen Appendix R fire areas divided between the two units.

 ,- Battery and switchgear rooms are located along the common wall separating the two units on the 695' and 715' levels. This common separating wall is an 18" thick reinforced concrete wall with an opening protected by automatic close (gravity assist) fire doors. The turbine deck (735' level)

B-22

is a single fire area shared by both units. The fire area boundaries and interfaces are described O beiew. The ground level of the turbine building is at the 695' elevation. This level contains ten fire areas, eight of which are battery and switchgear rooms located along both sides of the common wall separating the two units. The rooms and corridors along the north and east perimeter are included in fire area 9 with the remaining rooms contained in fire area 10. The south wall, a three-hour rated concrete wall, forms a common boundary with the lower level of the auxiliary building. With the exception of the Train A switchgear room, the same fire areas continue upward to the next level. The second level of the turbine building,715', is comprised of eight fire areas (20,21,22,23,69, 70,80,81) with the majority of the level included in fire areas 69 and 70. Similar to the lower level, electrical switchgear rooms are located along the boundary separating the two units. The auxiliary building abuts the major portion of the south wall. The new diesel generator building also shares a common wall along the southwest corner of the structure. Reinforced concrete or masonry block fire walls separate the two units from each other and from adjoining structures. The highest level (turbine deck - 735') is encompassed by a single fire area, fire area 8. This area shares a common wall with the auxiliary building to the south and with the old administration building along a short portion of the north wall. Separating the turbine building and the auxiliary building are a 31/2" insulated metal panel and an 18" thick reinforced concrete {

 ' wall.

B.2.5.4 Diesel Generator Building Annendix R Fire Areas 97-130: These fire areas contain emergency diesel generators D5 and D6, their respective fuel oil day tanks and other support equipment. The north half of the building houses D5 and the south half of the building houses D6. These areas are attached to the southwest corner of the turbine building. The interface between the DG building and the turbine building is a 20" concrete wall with an equivalent fire rating of three hours. l Because a fire in any of these rooms will not spread into the spaces containing equipment necessary for operation of the other DG, this building was partitioned into two burn sequences (B101 and B102). B101 consists of spaces containing D5 and its support equipment and B102 includes spaces containing D6 and its support equipment. Contribution to core damage due to a fire in these areas is included in the cumulative results. B.2.5.5 Screenhouse The plant screenhouse is divided into three fire areas,41N,41A and 41B. Fire area 41N is

 \  the general area on the 695' elevation. Fire area 41 A is the safeguards area on the 695'

, B-23 1 l

elevation. It contains the two diesel cooling water pumps and their auxiliaries, the 121 vertical J motor-driven cooling water pump, MCCs 1AB1 and 1AB2,230V AC panels 136 and 137, and the cooling water strainers. Area 41B represents the 670' elevation, which contains the fire pumps, the two non-safeguards motor-driven cooling water pumps, and the circulating water pumps. With respect to the fire PRA, the critical components located in these areas that are lost are the electrical MCCs and panels, the cooling water pumps and the fire pumps (however, only very limited credit was given for fire suppression, see Section B.2.8). A fire in any one of the sub-areas does not spread to the other areas due to spatial separation and three-hour fire barriers. Also, because of its remote location, a fire in the screenhouse does not spread to any other fire areas. B.2.6 Fire Innition Data It is necessary to calculate ignition source frequencies for each area to allow quantification of the impact of a fire in each sub-area. These individual impacts can be summed to yield the impact to the plant from all fires. The EPRI " Fire Event Database for U.S. Nuclear Power Plants" [8] was used to estimate fire ignition source frequencies for all rooms in the plant. This database contains a total of 800 events during a period from 1965-1988. These events were compiled from 114 BWR and PWR units across the United States, representing a total sample of approximately 1300 reactor years of operation. The data includes fire incidents caused by both fixed and transient sources due to normal operations and maintenance activities. FIVE incorporated this information into a procedure to develop ignition source frequencies for individual fire areas and sub-areas. This process was used to evaluate the ignition frequencies (F 1) for each fire compartment. An ignition source data sheet was completed for each room or fire compartment that was contained within the fire sub-areas defined in Phase I. The four-step process identified in the FIVE methodology was used to develop the ignition source data sheet. The first step requires that the location which corresponds best to the fire compartment in question be selected. Some locations may be specific Appendix R fire areas, such as the Control Room and Relay Room, while other locations may be general, such as turbine building fire area 69. The second step requires that a location weighting factor (WFL) be determined from this classification. The weighting factor is used to translate the generic fire frequencies for a location, compiled in FIVE (Table B.2.6.1), to specific, single-unit fire frequencies. The location weighting factors are designed to account for the relative amount ofignition sources in the plant in question compared to the average plant. These factors are easily calculated using the simple formulas found in Table B.2.6.1. h The third step requires that weighting factors for each type ofignition source (WFLS) be determined. The potential ignition sources in each room were obtained from the Appendix R fire analysis, equipment drawings, and a walkdown of each compartment. The amount of cabling B-24

____.__-_..m. and electrical cabinet contribution for each fire compartment was also obtained from the

V Appendix R fire analysis. Some ignition sources, such as cables and transformers, are best i apportioned on a plant-wide basis. Once the number of plant-wide ignition sources was i identified, the WFLS was determined by dividing the number of components in the room by the total number of similar components in the building or generic location being considered.

The fourth step requires that the fire compartment fire frequency (F1) be calculated for each fire compartment. Table B.2.6.2 lists the fire frequency for each ignition source (Fr) by location. F1 is the sum of the ignition source frequencies for each ignition source (Fi r) located within the given fire compartment. This value was obtained for each fire compartment by multiplying:

1. The fire frequency for each ignition source (Fr)(Table B.2.6.2),

2. The weighting factor for the location (WFL)(Table B.2.6.1), and

3. The weighting factor for each ignition source (WFLS)(Table B.2.6.2).  !

F r = Fr

• WFLS
• WFL This calculation was repeated for each ignition source in the compartment and the total fire frequency for the specific fire compartment (Fg) was calculated as:

F1 = E F r. O The resultant ignition frequencies for each compartment are provided in Table B.2.6.3. U i O B-25

4 Table B.2.6.1 Weighting Factors for Adjusting Generic Location Fire Frequencies for i . Application to Plant-Specific Locations (taken from FIVE methodology)

PLANT LOCATION WElGHTING FACTORSI(WFL)

Auxiliary Building (PWR) The number of units per site divided by the number of buildings.

l Diesel Generator Room The number of diesels divided by the number of rooms per site. Switchgear Room The number of units per site divided by the number of rooms per , site. Battery Room The number of units per site divided by the number of rooms per j site. Control Room The number of units per site divided by the number of rooms per site. 4 l Cable Spreading Room The number of units per site divided by the number of rooms per site. i l Intake Structure lhe number of units per site divided by the number of intake structures. Turbine Building The number of units per site divided by the number of buildings. Radwaste Area The number of units per site divided by the number of radwaste areas. l Transformer Yard The number of units per site divided by the number of switchyards.  ; Plant-Wide Components (Cables, The number of units per site. transformers, elevator motors, hydrogen recombiner/ analyzer) l l

1. The analyst must identify the number oflike locations w hen determining the nurr.ber of baildings, e.g., a 480-l volt load center is "like" a switchgear room.

4 i O B-26

Table B.2.6.2 Fire Ignition Sources and Frequencies by Plant Location Ignition Source Plant Location Fire Ignition /Fue! Source Weighting Fire Frequencyl ,2 Factor (Fr) (WFL) Auxiliary Building Electrical cabinets B 1.9 X 10-2 Pumps B 1.9 X 10-2 Diesel Generator Room Diesel generators A 2.6 X 10-2 Electrical cabinets A 2.4 X 10-3 Switchgcar P.oom Electrical cabinets A 1.5 X 10-2 Battery Room Batteries A 3.2 X 10-J Control Room Electrical cabinets A 9.5 X 10-J Relay Room Electrical cabinets A 3.2 X 10-3 Screenhouse Electrical cabinets A 2.4 X 10-J Fire Pumps A 4.0 X 10-3 Others A 3.2 X 10-3 Turbine Building T/G Excitor B 4.0 X 10-J T/G Oil B 1.3 X 10-2 T/G llydrogen B 5.5 X 10-3 Electrical cabinets B 1.3 X 10-2 Other pumps B 6.3 X 10-3 Main feedwater pumps A 4.0 X 10-3 Boiler B 1.6 X 10-3 Radwaste Area Miscellaneous components A 8.7 X 10-J [~ \ Transformer Yard Yard xTmers (spread to TB) A 4.0 X 10-3 Yard xfmers(LOOP) A 1.6 X 10-3 Yard transformers (Others) F 1.5 X 10-2 Plant-Wide Components Fire protection panels F 2.4 X 10-J RPS MG sets F 5.5 X 10-3 Non-qualified cable run E 6.3 X 10-3 Junction in non-qualified cable E 1.6 X 10-3 Junction box in qualified cable E 1.6 X 10-3 Transformers F 7.9 X 10-3 Battery chargers F 4.0 X 10-3 Ilydrogen Tanks G 3.2 X 10-3 Misc. hydrogen fires C 3.2 X 10-3 Gas turbines G 3.1 X 10-2 (Note 4) Air compressors F 4.7 X 10-3 Ventilation subsystems F 9.5 X 10-3 i Elevator motors F 6.3 X 10-3 Dryers F 8.7 X 10-3 Transients D 1.3 X 10-3 (Note 3) Cable fires caused by welding C 5.1 X 10-2 (Note 3) Transient fires due to welding / cutting C 3.1 X 10-2 (Note 3)

1. Frequencies are per reactor year unless otherwise noted.

2. Fire frequencies are per fraction ofignition sources per year.

3. Fire frequency represents one event. The thirteen transient events which occurred during power operation are considered by the ucighting factor.

4. Fire frequency represents an estimated 130 gas-turbine-operating years.

B-27

Table B.2.6.2 (continued) Fire Ignition Sources and Frequencies by Plant Location Notes for Ignition Source Weighting Factor Method: I Zone specific ignition sources were determined during the initial walkdown. Normally, ignition source frequencies are  ; estimat.:d using methods other than direct counting, including engineering judgement. These estimates are then verified j durir4g the walkdown. Estimates should be within 25% of actual values. I L A. No ignition source weighting factor is necessary. { B. Obtain the ignition source weighting factor by dividing the number ofignition sources in the fire compartment by the number in the selected location.  ! t C. Obtain the ignition source weighting factor by calculating the inverse of the number of compartments in i the locations. Exclude any areas contained in locations other than in this table.

                                                                                                                       ?

D. Obtain the ignition source weighting factor by summing the factors for ignition sources which are allowed j in the zone and divide by the number of zones in the locations in this table. For example, if cigarette smoking is prohibited do not include the cigarette smoking factor in the calculation. The factors are: [

• Cigarette Smoking 2  ;

e Extension Cord 4 l e lleater 3 l e Candle 1 i e Overheating 2 [

• Ilot Pipe 1 Overheating addresses errors while heating potential combustibles, e.g., battery terminal grease.

E. Obtain the ignition source weighting factor by dividing the weight (or BTUs) of cable insulation in the area by the total weight (or BTUs) of cable insulation in Appendix R fire areas, not including the fire areas in either the radwaste area or the containment. Cable insu!ation weights (or BTUs) are provided in Appendix R combustible loadings. (Junction boxes and splices are assumed to be distributed in proportion to the amount of cable.) l F. Obtain the ignition source weighting factor by dividing the number ofignition sources in the fire area by the total number in all the locations in this table. G. Obtain the ignition source weighting factor by dividing the number ofignition sources in the fire area by the total number in all plant locations, include locations that were not specified in this table. i

                                                                                                                        ]

B-28

_ . _ _ _ _ _ _ _ _ _ _ . _ . . _ . _ _ _ . . . _ . _ _ _ _ . . _._m Table B,2.6.3 Prairie Island Ignition Source Frequencies by IPEEE Fire Area FIRE IGNITION  : AREA AREA AREA LOADING SOURCE NUMBER DESCRIPTION SQ.FT. BTU /FT2 FREQ. (per/yr)  ! Fi 1 Containment Unit 1 8,660 76,109 Note 3 2B2 Ventilation Fan Floor, Unit 1 9,570 27,544 [5.88E-3] (=5.88E-03)I 3 Water Chiller Room, Unit 1 1,000 42,450 1.08E-3 4NB67 Fuelliandling Area 4,670 26,082 [1.18E-2] , (6.08E-3)3 i 5NB69 Old Admin Bldg (715') 3,522 17,235 [1.9E-3] (1.71E-3)I y 6N Old Admin Building,liVAC Area (750') 1,540 4,052 1.03E-4  ! 7NB70 Old Admin Building Office Area (735') 7,532 8,497 [2.35E-2]  ! (1.00E-4)I , 8NB69,B70 Turbine Deck (Units 1 & 2) 54,870 162 9.71 E-31 9N Maintenance Shops 6,550 1,209 1.28E-3 10 Train "A" Event Monitoring Equipment Room 530 26,430 1.41 E-3 11 Unit 1 Normal Swgr. & Control Rod Drive 2,250 13,000 2.52E-3 Room 12 OSC Room 1,000 31,180 3.20E-4 13 Control Room 4.160 63,029 2.07E-2 14NB69 Working Materials Storage & Lunch Room 6.550 527 1.23 E-31 15 Access Control 3,060 28.039 1.59E-3 16 Train *B" Event Monitoring Equipment Room 520 46,352 1.31 E-3 17 Unit 2 Normal Swgr. & Control Rod Drive 2,250 12,764 2.52E-3 Room 18Bl3 Relay and Cable Spreading Rm., Unit 1 & Unit 4,160 404,829 [2.07E-2] 2 (1.93E-2)I 19NB18 Computer Room 980 10,000 1.42E-33 20 Unit 14KV Safeguards Swgr. (Bus 16) 760 103,734 2.04E-3 21NB69 Unit 14KV Normal Swgr. (Bus 13,14) 1,690 9,053 2.04 E-31 22 480V Safeguards Swgr. (Bus 121) 770 81,805 2.09E-3 23NB70 Unit 2 4KV Normal Swgr. (Bus 23,24) 1,690 15,089 2.03E-3I 24N Oil Storage Area 1,350 2.17x106 2.96E-3 25 Diesel Gen #1 Room 1,460 109,041 6.49E-3 26 Diesel Gen #2 Room 1,350 116,444 6.49E-3 27NB69 Water Conditioning Equipment Area 3,800 4,316 8.80E-43 28aN Transformer IGT Note 2 2,526 Note 3 28bN Transformer 2GT Note 2 2.526 Note 3 28cN Transfonner 1R Note 2 1,132 Note 3 28dN Transformer 1M Note 2 678 Note 3 28eN Transformer 2M Note 2 678 Note 3 B-29 l

Table B,2.6.3 (continued) Prairie Island Ignition Source Frequencies by IPEEE Fire Area 1 FIRE IGNITION AREA AREA AREA LOADING SOURCE l NUMBER DESCRIPTION SQ.FT. BTU /FT2 FREQ. (per/yr)

;                                                                                                                                Fi                   ,

28fN Transformer 2RX & Y Note 2 746 Note 3 1 1,100 40,091 29 Admin Building Electrical & Piping Room #1 1.90E-4 i 30 Admin Building Electrical & Piping Room #2 1,100 38,955 1.90E-4

31 "A" Train llot S/D Panel & Air 1,180 36,780 1.52E-3 i Compressor /AFW Room 2,360 i

} (Note 4) 2 32 "B" Train 110t S/D Panel & Air 1,180 35,064 1.61 E-3 Compressor /AFW Room 2,360 ) (Note 4) < 33 Battery Room 11 590 19,966 1.26E-3

34 Battery Room 12 $90 27,864 1.18E-3 35 Battery Room 21 590 20,305 1.22E-3

! 36 Battery Room 22 590 27,746 1.3 E-3 1 37 Unit 1480V Normal Swgr. (Bus 150,160) 1,030 43,172 2.10E-3 38 Unit 2 480V Normal Swgr. (Bus 250,260) 1,100 38,788 2.10E-3 39NB67 Radiation Waste Building 2.990 9,799 inct w/ FA043 40N Cooling Towers 121,122,123 & 124 Note 2 Note 2 Note 3 ! p 41A Screenhouse (DDCWP Room) 1,840 108,283 2.20E-2 41B Screenhouse Basement 4,220 31,770 1.14E-2

41N Screenhouse(General Area) Note 2 Note 2 3.60E-3 2

42N Cooling Tower Pump House 3,670 67.8 Note 3 43N Unit 2 Transformer Oil Sump Note 2 Note 2 Note 3 44N Unit 1 Transformer Oil Sump Note 2 Note 2 Note 3 45N Fuel Oil and Transferllouse 100 Note 2 Note 2 46N Cooling Tower Equipment House & I,620 42,407 Note 3 Transformers 47N Cooling Tower Transformer Oil Sump Note 2 Note 2 Note 3 48N Dl, D2 Diesel Fuel Oil Storage Tanks Note 2 N/A Note 3 49N lleating Boiler Fuel Oil Storage Tanks Note 2 10,110 Note 3 50N Cooling Tower Control House 121 & 122 990 Note 2 Note 3  ;

                  $1N      Neutralizer Tank Pump ilouse/ Warehouse #2                    212.5         No'e 2                  Note 3                 i

, 52N Parking Lot Note 2 Note 2 Note 3 53N Receiving Warehouse, NPD Office & NPD Note 2 Note 2 Note 3 Annex 54N Cooling Tower Controlllose 123 & 124 990 Note 2 Note 3 55N Warehouse #1 and Fab Shop Note 2 Note 2 Note 3 56N Drum Storage Area Note 2 Note 2 Note 3 57NB69 Gas ilouse 650 11,646 3.8E-41 i 58 Aux Building Ground Floor Unit i 14,560 32,541 [2.93E-2] l s (1.03E-2)I 59B59 Aux Building Mezzanine Floor Unit 1 10,700 77,570 [9.41E-3] (8.86E-3)I . B-30

i Table B.2.6.3 (continued) Prairie Island Ignition Source Frequencies by IPEEE Fire Area i l j /

             }                             AREA                                         AREA                                     AREA FIRE LOADING IGNITION SOURCE l                                       NUMBER                                       DESCRIPTION                                SQ.FT,      BTU /FT2                     FREQ. (per/yr)

I Fi 60 Aux Building Operating Floor Unit i 6,880 14,776 2.32E-3 611174 Aux Bldg Anti"C" Clothing (El. 735') 6,330 15,731 [7.97E-3] j (5.7E-4)I 61A Aux Bldg Hatch Area (El. 755') 12,440 8,114 4.80E-4 { 62NB67 Spent Fuel Pool Area 4,180 Note 2 4.20E-41 2 63N Filter Room 2,430 Note 2 Note 3 i ~ 64NB67 Aux Building Low Level Decay Area Unit 1 830 3,133 3.20E-41  !

65NB67 Spent Fuel PoolllX & Pumps 1,090 Note 2 2.00E-41

! 66 Storage Room 1,470 Note 2 4.00E-4 , 67NB67 Resin Disposal Building 2,680 25,687 inct w/FA41 , 1,710 I l 68 Containment Annulus Unit 1 14,906 Note 3 69 Turbine Building Ground & Mezz Floor Unit 1 21,680 150,484 1.94E-2  ! l ' i 70B70 Turbine Building Ground & Mezz Floor Unit 1 21,680 143,132 in:1 w/FA7I l 71 Containment Unit 2 8,660 83,383 Note 3 l 72 Containment Annulus Unit 2 1,710 14,965 Note 3  ! l j 73 Aux Building Ground Floor Unit 2 13,420 35,671 2.54E-2  ! l 74B74 Aux Building Mezz Floor Unit 2 10,700 78,215 inct w/ FA611 75 Aux Building Operating Floor Unit 2 6,880 15,055 2.39E-3 1 l 76B2 Vent and Fan Room Unit 2 9,570 30,930 inct w/ FA2I l l 77NB67 Aux Building Low Level Decay Area, Unit 2 830 Note 2 2.00E-41  ; ! 78NB67 Waste Gas Compressor Area 1,510 199 1.86E-33 l 79 480V Safeguards Swgr Room (Bus 112) 400 28,363 2.05E-3 l i 80 480V Safeguards Swgr Room (Bus 111) 870 44,853 2.09E-3 l 81 4KV Safeguards Swgr Room (Bus 15) 860 45,005 2.03 E-3 l

82 480V Safeguards Swgr Room (Bus 122) 380 25,339 2.05 E-3 83N Inst. Lab Area 1,490 1,409 4.00E-4 84NB59,B74 Counting Room & Labs 6,680 344 5.50E-4I 85N Holdup Tank / Demineralizer Area 4,880 Note 2 3.50E-4 j 86N Intake Screenhouse, Envir Lab, Rad Monitor Note 2 Note 2 2.21 E-2 l

3 Station & De-Icing Pump 11ouse  ; 87N Deepwell Pump 11ouse #1 110 Note 2 Note 3 88N Deepwell Pump Ilouse #2 110 Note 2 Note 3 89N Guardhouse 3,074 Note 2 Note 3 q 3,140 , Note 5 90NB70 Emergency Generator Building 570 127,193 6.94 E-31 91N Diesel Fuel Pump & Decay Cooling Water Note 2 N/A Note 3 Pump Oil Storage Tanks 92 Water Chiller Room Unit 2 1,000 44,450 1.09E-3 93NB67 Drum Storage / Low Level Radwaste Warehouse 12,400 Note 2 7.00E-SI 94NB69 Service Building / Computer Area Note 2 Note 2 4.15E-3I B-31

                                                                             -----.m                      p.vg                           w                  --nv

Table B.2.6.3 (continued) Prairie Island Ignition Source Freyt:encies by IPEEE Fire Area FIRE IGNITION (\ AREA AREA AREA LOADING SOURCE NUMBER DESCRIPTION SQ.FT. BTU /FT2 FREQ. (per/yr) Fi 95N DS Diesel Fuel Oil Storage Tanks N/A N/A Note 3 Note 2 Note 2 96N D6 Diesel Fuel Oil Storage Tanks N/A N/A Note 3 Note 2 Note 2 97B101 DS Basement (El. 687') 2,100 97,000 [1.53E-2] (2.50E-4)I 98B102 D6 Basement (El. 687') 2,330 97,000 [1.52E-2] l (2.50E-4)I 99N Stairwells (El. 695',707' & 718') N/A N/A 1.00E-4 Note 2 Note 2 100N #21 DS/D6 Fuel Oil Receiving Tank 429 4.9x106 1.00E-4 101B101 DS Diesel Generator Room 1,980 86,000 1.13 E-23 102B102 D6 Diesel Generator Room 1,980 86,000 1.13 E-23 103B101 D5 Emergency DG Control Room 550 21,000 4.30E-43

1048102 D6 Emergency DG Control Room 550 20,000 4.30E-4I 10$NB101 D5 Battery Room 550 9,400 1.60E-41 l

106NB102 D6 Battery Room 550 9,100 1.60E-43 I 107B101 DS Inverter Room 460 3,000 2.00E-43 108B102 D6 Inverter Room 460 4,300 2.00E-43 l 109B101 D5 Normal MCC & Cable Tray Area 1,450 56,000 8.30E-4I l 110B102 D6 Normal MCC & Cable Tray Area 1,600 48,000 9.10E-41 111B101 D5 Building - Mezzanine Floor 718' 440 32,000 1.70E-43 11;B102 D6 Building - Mezzanine Floor 718' 440 33,000 1.70E-41 113 #21 D5 Fuel Oil Day Tank Room 125 700,000 1.00E-4 114 #22 D6 Fuel Oil Day Tank Room 215 700,000 1.00E-4 115B101 #21 DS Lube Oil M-U Tank Room 90 1.4x106 Note 3 116B102 #22 D6 Lube Oil M-U Tank Room 90 1.4x106 Note 3 117B101 4KV Bus 25; MCC-2 TAI 1,480 51,000 2.03 E-33 118B102 4KV Bus 26; MCC-2TA2 1,400 42,000 2.03E-33 119 #21 D5 lit /Lt M-U Tank Pump Room 510 9.300 2.80E-4 I 120 #22 D6 lit /Lt M-V Tank Pump Room 510 9,300 2.80E-4 121N Stairwell (El. 735') 402 N/A Note 3 122Bl02 480V Bus 221/222 Room 1,650 15,400 2.13 E-3I l 123B101 DS Radiator Room 1,280 8,200 1.70E-41 124B102 D6 Radiator Room 1,280 8,500 1.70E-4  ! 125 D5 Fan Room 1,280 N/A 3.40E-4 Note 2 126 D6 Fan Room 1,280 N/A 3.40E-4 Note 2 127B101 480V Bus 211/212 Room 1,480 17,600 2.13 E-31 128N 4KV Bus 27 Room 224

• 2.07E-4 B-32

e Table B.2.6.3 (continued) Prairie Island Ignition Source Frequencies by IPEEE Fire Area FIRE IGNITION AREA AREA AREA LOADING SOURCE NUMBER DESCRIPTION SQ.FT. BTU /FT2 FREQ. (per/yr) Fi 129N DS Radiator Exhaust (Roof) 1,280 N/A 1.00E-4 Note 2 130N D6 Radiator Exhaust (Roof) 1,280 N/A 1.00E-4

                                                                                                                                     )

Note 2 J 131N New Admin Building Note 2 Note 2 Note 3 Notes: 1 For burn sequences, the first area within a sequence shows the sequence frequency in brackets [ ]. Thi area-specific frequency for the first area within a sequence is shown in parenthese ( ). For all other areas within a sequence, th t table shows the frequency of that specific area. The frequencies of all areas within a sequence, when added together, ecual the burn sequence frequency. Note that some area-specific frequencies are negligible (see Note 3), or bundled with anothen area within the sequence. 2 Entires in columns labeled Area Sq. ft. and Fire Loading are taken directly from Prairie Island Fire llazards Analysis (F.5, App. F), Table 6-2. Blanks or "N/A" or "*" in any of these columns are found in that table, and indicate that the Fire llazards Analysis concluded that a fire in the area has no efTect on plant shutdown; no safe shutdown equipment is located in the area. In some cases, the IPEEE has conservatively assigned a fire frequency to the area based upon the FIVE methodology. Ilowever, the analysis indicates that even with this conservatis e assumption the area does not contribute. 3 The frequency for this area is negligible, or has not been estimated because fires will not afTect the ability to shutdown the plant (see also Note 2). 4 Loading based on i 180 sq. fi. for oil,2360 sq. ft. for cable; total BTU value based on total sq. ft. for fire area. 5 F rst entry is ground level, second is basement level. Il2 Burn sequence B2 includes Fire Areas 02 and 76. Ill8 Burn sequence BIS includes Fire Areas 18 and 19. 4 B58 Burn sequence B58 includes Fire Areas 58,73. Ilowever, this burn sequence is qualitatively dismissed (see discussion for l Fire Area 58), and individual analyses are performed for Fire Area 58 and 73 using the fire initiating frequencies provided  ! in this table for those areas. B5913 urn sequence 1359 includes Fire Areas 59 and 84. B67 Burn sequence B67 includes Fire Areas 04,39,62,64,65,67,77,78,85 and 93. B69 Burn sequence 1169 includes Fire Areas 05,08,14,21,27,57 and 94. B70 Burn sequence B70 includes Fire Areas 07,08,23,70 and 90. 1374 Burn sequence B74 includes Fire Areas 61. 74 and 84. 1110lllurn sequence 11101 includes Fire Areas 97,101,103,105,107,109,111,117,123 and 127. B102flurn sequence B102 includes fire Areas 98,102,104,106,108,110,112,118,122 and 124. B-33

J B.2.7 Fire Area Initial Screenine j A fire in the plant involving equipment that may be required to support plant operation was l assumed to result in a plant shutdown. Therefore, only fire areas outside the main reactor / turbine ! building complex were screened from further evaluation in this step. The results of the  ; qualitative screening process are shown in Table B.2.7.1. D.2.8 - Fire Detection and Suppression  ! I This section discusses automatic detection and automatic or manual fire suppression at Prairie

;         Island. The detection and suppression systems available in each fire area are presented in the               ,

I Prairie Island Updated Fire Hazards Analysis [7] and listed in Table B.2.8.1. While detection and suppression capability are discussed for most areas of the plant, it should be  ; noted that the only locations where detection and/or suppression were credited in the accident sequence quantification were the Control Room, Relay Room, and the AFW pump rooms. H.2.8.1 Detection i Several methods ofautomatic fire detection are used at Prairie Island. These methods are ionization detection, thermal detection, smoke and flame detection. Alarms are designed to , sound locally (halon- and cardox-protected areas) and in the Control Room. The detection system will also sound an alarm if there is a failure in the detector system. O In addition to the alarms described above, there are heat-actuated device alarms and/or water flow alarms associated with water suppression systems which alarm in the Control Room. B.2.8.2 Automatic Suppression The automatic suppression systems at Prairie Island consist of water, CO2and Halon based systems. Two 100% redundant,2000 gpm, fire pumps supply water to the Fire Protection . System; one is electrically powered and the other diesel engine powered. A third 2000 gpm  ! pump, also electrically powered and normally used as a screenwash pump, may also be used as a oackup pump for the Fire Protection System. The water delivery portion of the system consists of automatic pre-action, deluge, wet / dry pipe sprinklers and hose stations. Although several locations in the plant are protected by automatic fire suppression systems, the Relay Room and the AFW pump rooms are the only locations in which this analysis takes credit for the automatic suppression of a fire. The Relay Room is protected by a 6-ton carbon dioxide system with alann sirens and a sixty-second delay. A detection system and a thermal actuation system is provided. Ionization detectors provide an early warning alarm to the Control Room. The auto action mode is normally bypassed when the room is occupied; however, the carbon dioxide system may be manually actuated at any time. The room, however, is not routinely occupied and the auto mode is therefore normally on. The carbon dioxide system is backed up O i by manual hose stations and extinguishers. The unavailability of the CO2system used in the B-34

i i ) i ! quantification of this fire scenario is taken from the FIVE methodology. This generic CO2 system unavailability is 4E-2.

The AFW pump rooms (Areas 31 and 32) contain ionizing detection systems and thermal  ;

j actuators. Fire sprinklers are located throughout the areas. Manual hose stations and , 1 extinguishers serve as back-up devices. - 1 i i i i. i i I i l 1 i i 1

                                                                                                                                                                      )

i

   \

B-35 l

I l r Table H.2.7.1 Summary of Prairie Island IPEEE Area Screening l ( ARSA AREA QUALITATIVELY RETAINED FOR N8?P.SER DESCRIPTION SCREENED FURTHER EVALUATION I Containmeni Unit I X* 2 Ven'.ilation Fan Floor, Unit I X 3 WateLChiller Room, Unit I X 4N Fuel 1.'aedling Area X 5N Old Acnn, Bldg (715') X 6N Old Adruin Building,11VAC Area (750') X , 7N Old Admin Building Office Area (735') X { 8N Turbine Deck (Units 1 & 2) X 9N Maintenance Shops X 10 Train "A" Event Monitoring Equipment Room X 1i Unit 1 Normal Swgr. & Control Rod Drive Room X l 12 OSC Room X 13 Control Room X i 14N Working Materials Storage & Lunch Room X I 15 Access Control X 16 Train "B" Event Monitoring Equipment Room X 17 Unit 2 Normal Swgr. & Control Rod Drive Room X l 18 Relay and Cable Spreading Rm., Unit 1 & Unit 2 X l

19N Computer Roori X {

l , 20 Unit 14KV Sr.feguards Swgr. (Bus 16) X l 21N Unit i 4KV Normal Swgr. (Bus 13,14) X i 22 480V Safeguards Swgr. (Bus 121) X l 23N Unit 2 4KV Normal Swgr. (Bus 23,24) X l 24N OilStorage Area X l 25 Diesel Gen #1 Room X  ! 26 Diesel Gen #2 Room X l 27N Water Conditioning Equipment Area X  ! 28aN Transformer IGT X  ! 28bN Transformer 2GT X 28cN Transformer IR X 4 28dN Transformer IM X l 28eN Transformer 2M X  : 28fN Transformer 2RX & Y X 29 Admin Building Electrical & Piping Room #1 X 30 Admin Building Electrical & Piping Room #2 X 31 "A" Train 110t S/D Panel & Air Comp /AFW Rm X 32 "B" Train liot S/D Panel & Air Comp /AFW Rm X l 33 Battery Room i1 X ! 34 Battery Room 12 X 35 Battery Room 21 X 36 Battery Room 22 X  ;

37 Unit 1480V Normal Swgr. (Bus 150,160) X 38 Unit 2 480V Normal Swgr. (Bus 250,260) X 39N Radiation Waste Building X 3

40N Cooling Towers 121,122,123,124 X

     ~                    4IA      Screenhouse (DDCWP Room)                                                        X 4iB     Screenhouse Basement                                                             X l

B-36

                 , -   c         -            --       --                .-                               ,   ,

 .   .---                      .. -~ -- -.--- -. --                                    .-.          ..    . . . _ . ~ - .

8 P Table B.2.7.1 (continued) Summary of Prairie Island IPEEE Area Screening AREA AREA- QUALITATIVELY RETAINED FOR NUMBER DESCRIPTION SCREENED FURTHER EVALUATION L 4IN Screenhouse(General Area) X ' 42N Cooling Tower Pump House X 43N Unit 2 Transformer Oil Sump X 44N Unit i Transformer Oil Sump X  ! 45N Fuel Oil and Transfer House X j 46N Cooling Tower Equipment House & Transformers X 47N Cooling Tower Transformer Oil Sump X , 48N Di, D2 Diesel Fuel Oil Storage Tanks X r 49N Heating Boiler Fuel Oil Storage Tanks X SON Cooling Tower Control House 121 & 122 X j SIN Neutralizer Tank Pump House / Warehouse #2 X 52N Parking Lot X

             $3N     Receiving Warehouse, NPD Office & NPD Annex                 X 54N     Cooling Tower Control Hose 123 & 124                        X 55N     Warehouse #1 and Fab Shop                                   X 56N     Drum Storage Area                                           X 57N     Gar House                                                   X                                        j 58     Aax Building Ground Floor Unit I                                                 X
              $9     Aux Building Mezzanine Floor Unit I                                              X                   !

60 Aux Building Operating Floor Unit I X 61 Aux Bldg Anti "C" Clothing (735') X b 61A Aux Bldg Hatch Area (755')

                                                                                   ~'

X 62N Spent Fuel Pool Area X < 63N Filter Room X  ; 64N Aux Building Low Level Decay Area, Unit I X 65N Spent Fuel Pool HX & Pumps X 66 Storage Room X  ! 67N Resin Disposal Building X  ! 68 Containment Annulus Unit I X*  ; 69 Turbine Building Ground & Mezz Floor Unit I X , 70 Turbine Building Ground & Mezz Floor Unit 2 X l 71 Containment Unit 2 X* l 72 Containment Annulus Unit 2 X*  ; 73 Aux Building Ground Floor Unit 2 X i 74 Aux Building Mezz Floor Unit 2 X [ 75 Aux Building Operating Floor Unit 2 X l 76 Vent and Fan Room Unit 2 X 77N Aux Building Low Level Decay Area, Unit 2 X 78N Waste Gas Compressor Area

• X 79 480V Safeguards Swgr Room (Bus 112) X 80 480V Safeguards Swgr Room (Bus 11I) X 81 4KV Safeguards Swgr Rcom (Bus 15) X 82 480V Safeguards Swgr R >om (Bus 122) X 83N Inst. Lab Area X l 84N Counting Room & Labs X l 85N Holdup Tank / Demineralizer Area X 86N Intake Screenhouse, Envir Lab, Rad Monitor Station X

                     & De-Icing Pump House 87N     Deepwell Pump House #1                                      X                                         i l

B-37

i Table B.2.7.1 (continued) Summary of Prairic Island IPEEE Area Screening ( AREA AREA i QUALITATIVELY RETAINED FOR NUMBER DESCRIPTION SCREENED FURTIIER EVALUATION j 88N Deepwell Pump House #2 X l 89N Guardhouse X 90N Emergency Generator Building X 91N Diesel Fire Pump & Diesel Cooling Water Pump Oil X Storage Tanks 92 Water Chiller Room Unit 2 X 93N Drum Storage / Low Level Radwaste Warehouse X  ! 94N Service Building / Computer Area X 95N D5 Diesel Fuel Oil Storage Tanks X 96N D6 Diesel Fuel Oil Storage Tanks X 97 D3 Basement (687') X 98 D6 Basement (687') X 99N Stairwells (El. 695'.707' & 7I8') X 100N #21 D5/D6 Fuel Oil Receiving Tank X 101 D5 Diesel Generator Room X 102 D6 Diesel Generator Room X 103 D5 Emergency Diesel Generator Control Room X D6 Emergency Diesel Generator Control Room X 104 105N D5 Battery Room X - 106N D6 Battery Room X , 107 D5 inverter Room X 108 D6 inverter Room X 109 D5 Normal MCC & Cable Tray Area X 110 D6 Normal MCC & Cable Tray Area X 11I D5 Building - Mezzanine Floor 718' X l 112 D6 Building - Mezzanine Floor 718' X 113 #21 D5 Fuel Oil Day Tank Room X 114 #22 D6 Fuel Oil Day Tank Room X 115 #21 D5 Lube Oil M-U Tank Room X 116 #22 D6 Lube Oil M-U Tank Room X 117 4KV Bus 25; MCC-2TAl X 118 4KV Bus 26; MCC-2TA2 X 119 #21 D5 Ht/Lt M U Tank Pump Room X 120 #22 D6 Ht/Lt M-V Tank Pump Room X 121N Stairwell (El. 735') X  ; 122 480V Bus 221/222 Room X

                                                                                                                                                      ]

123 D5 Radiator Room X ' 124 D6 Radiator Room X 125 D5 Fan Room X  ! 126 D6 Fan Room X 127 480V Bus 211/212 Room X 128N 4KV Bus 27 Room X 129N D5 Radiator Exhaust (RooO X 130N D6 Radiator Exhaust (RooO X 13lN New Admin Building X

• A significant fire in the containment is not likely given its combustible loading and physical configuration. Much of the combustible material located in the containment is tube oil for the reactor coolant pumps. This oil is normally contained. In addition, an oil collecting system that collects the oil in the event of a spill is also installed. The remaining combustible material, B-38

Table B.2.7.1 (continued) Summary of Prairie Island IPEEE Area Screening electrical cable, located in these areas are fire retardant (IEEE-383 rated). Because of these factors, a significant fire within the containtnent is not expected to occur. The FIVE methodology recognius the unlikely occurrence of a containtnent fire and does not even provide an ignition source frequency for this area. I B-39

1 i g B.2.8.3 Manual Suppression l Each plant is required to maintain a manual fire fighting capability. The fire brigades developed under these requirements are well trained and capable of fighting fires while awaiting support l from professional fire fighting teams, if called. To take credit for brigade or other manually actuated suppression system response in the FIVE methodology, however, the plant must demonstrate that the fire brigade can assemble, fight, and control a fire in the compartment before the fire causes damage to safe shutdown equipment. That is, the time to detect a fire plus i the time to respond to the scene with equipment and control the fire must be less than the time required for fire to damage critical equipment. Detection time is dependent upon the type of detection equipment in a compartment. Ionization detectors should detect a fire during the incipient stages, whereas heat detectors would not be expected to detect a fire until the fire is more fully involved. Fire brigade response time includes time to verify the detection and the time for the team to respond to the scene with equipment. Response time is obviously highly variable and is dependent upon the location of the fire, location of the brigade members at the time of the event and many other factors. The FIVE methodology assigns a probability of successfully suppressing a fire manuallyif and only if the following two criteria can be met:

1. The plant can demonstrate that detection and manual response can occur before damage to safe shutdown equipment, and

2. Fire brigade effectiveness can be demonstrated per the requirements of the NUREG/CR-5088

       " Fire Risk Scoping Study" [11].

The FIVE methodology states that the probability of manually suppressing a fire should not be greater than 0.9. I For the purpose of this analysis, no credit for manual suppression was taken before damage of I safe shutdown equipment is assumed to occur. For example, manual suppression is assumed for Control Room fires, but only after the fire has disabled the safe shutdown equipment. This analysis recognizes that manual suppression effons will be taken to suppress a fire and to ensure that the fire does not propagate outside the fire area boundaries. Manual fire suppression equipment is available throughout the plant in the form of portable fire extinguishers and hose stations. The fire fighting training program in place at Prairie Island ensures that fire brigade members are adequately trained to effectively use this equipment. The limited credit assumed for manual suppression of fires in the Prairie Island fire IPEEE is for accident sequence quantification purposes only, and is very conservative. O B-40

o Following successful suppression in the Control Room or Relay Room, some equipment was assumed to be lost (see Section D.2.10.1). If the fire started in a cabinet or panel, all the circuits in that cabinet / panel was assumed failed by the fire. Since suppression was not credite i except in these limited areas, suppression-induced damage outside of these areas is not an issu . In the Control Room, fire detection can be accomplished in a variety of ways:

                                                                                                         )

The Control Room contains local smoke detectors in the ceiling which would provide an audible alarm should smoke be generated in the Control Room. The Control Room is continuously staffed and a fire should be quickly sensed by smell or by sight by the operators. l l It is assumed that the failure to detect a fire in the control cabinets is negligibly small due to the redundancy and diversity of cues and due to the continuous staffing of the Control Room. It is further assumed that fire suppression efforts would be initiated immediately upon detection of a l fire because of the continuous staffing of the Control Room. The FIVE methodology allows a minimum value of 0.1 for the probability of failing to suppress a fire manually in a given space  ! even if unoccupied. This analysis assumes additional credit in the likelihood of successfully l suppressing a Control Room fire for the following reasons:

  . The Control Room is continuously staffed. In addition, Control Room operators are trained in fire suppression techniques. Therefore, early detection and action to suppress a fire is very

(} likely. i

  . The cabinets contain relatively small amounts of combustible material.

For these reasons, a probability of 0.01 is assigned to failing to manually suppress a fire in the Control Room. I b v B-41

Table B.2.8.1 Fire Detection and Suppression FIRE AREA AREA PROTECTION NUMBER DESCRIPTION DETECFION AU10. MAN. I Contamment Urut i lON None Hose Station. Fire Extg. 2 Ventilation Fan floor. Unit ! ION FWP Hose Station. Fire Extg. 3 Water Chiller Room. Unit i lON None OSRM 4N Fuel Handimg Area lON SWP1 Hose Station. Fire Extg.

           $N    Old Admm Bldg (715')                              lON     % PS-29       Extg.. OSRM 6N     Old Admin Bldg.HVAC Area (750')                   lON       None        Extg.. OSRM 7N    Old Admin Illdg Office Area (735')                ION       None     Extg Hyd..O$RM 8N    Iurbme Deck (Umts I & 2)                          N/A     W PS-30  Extg..DM. Hose Station 9N     Maintenance Shops                                 lON      SW P-6       Extg.. OSRM 10    Tram "A" Event Momtormg Equipment Room            ION       None        Extg.. OSRM ii    Umt i Normal $wgr. & Control Rod Drive            ION       None        Extg 0$RM Room 12    OSC Room                                          lON     w PS-23       Extg.. OSRM 13    Control Room                                      lON       None        Extg. OSRM 14N    Workmg Materials Storage / Lunch Room             ION     % PS-25    Hose Station. Extg.

15 Access Control lON  % PS-20 Hose Station. Extg. 16 Tram "B" Esent Monitormg Equipment Room lON None Extg.. OSRM 17 Unit 2 Normal $wgr. & Control Rod Drive ION None Extg.. OSRM Room 18 Relay an2 Cable Spreadmg Arn., Unit I & Umt ION CO2 OSRM 2 C'om7 uter Room ION CO3 Extg. 05RM 19N_ 20 Umt i 4KV Safeguards $ wgr. (Bus 16) ION None Extg.. OSRM 2tN Unit 14KV Normal $wgr. (Bus 13.14) ION None Extg. O$RM 22 480V Safeguards Swgr. (Bus 121) lON None Extg.. OSRM g 4 23N Umt 2 4KV Normal Swgr. (Bus 23. 24) lON None Extg OSRM 24N Oil storapc Area ILAME. HEAT DA-2 OSRM 25 Diesel Gen #1 Room lON. FLAME PA-1 Extg OSRM - 26 Diesel Gen #2 Room ION. HEAT PA-1 OSRM 27N Water Conditionmg Equipment Area lON  % Ps-9 Hose Station, Extg. Deluge 28aN I ransformer IGT Thermal Deluge Hyd. DM-1 28bN 1ransformer 20T Thermal Deluge Hy d.. DM-5 28cN Transtormer 1R Ihermal Deluge Hyd DM-3 28dN Iransformer IM Thermal Deluge Hyd.. DM-2 28eN Transformer 2M Thermal Deluge Hyd.. DM 4 281N 1ransformer 2RX & Y Thermal Deluge Hy d.. DM-6 29 Admm Building Electrical & Pipmg Room # 1 ION None Extg.. OSRM 30 Admm Buildmg Electrical & Papmg Room #2 ION None OSRM 31 "A" T rain ilot h/D Panel & Air ION.  % PS-10 Extg OSRM Compressor /AFW Rm THERMAL 32 "B" Iram llot S/D Parel & Air lON. W P$-10 Extg OSRM Compressor /AFW Rm THERMAL 33 Battery Room 18 lON None OSRM 34 Battery Room 12 ION None OSRM 35 13attery Room 21 ION None OSRM 36 Battery Room 22 ION None OSILM 37 Umt 1480V Normal Swgr. (Bus 150.160) ION None Extg.. OSRM 38 Umt 2 480V Normal Swgr. (Bus 250,260) lON None Extg . OslLM 39N Radiation % aste Buildmg lON None Hose Station. Extg. 40N Coolmg Towers 121.122.123.124 N/A None Hyd 41A $creenhouse (Dfr% P Room) lON PA-9 Hose station. Extg. 4iB Screenhouse Basement ION PA-9 Hose Station. Extg. 41N Screenhouse (General Area) lON PA-9 Hose Station. Extg. 42N Cooling Tower Pump flouse ION None Extg . Hy d.

  ] <     43N     Umt 21 ransformer Oil Sump                        N/A      None            Hy d.

44N Umt 4 'Iranstormer Oil Sump N/A None Hyd. B-42

Table B.2.8.1 (continued) Fire Detection and Suppression , FIRE AREA AREA PROTECTION

 \    NUMBER                    DESCRIPTION                    DETECTION 45N     Fuel Oil and 1ransler House                          ION         None               Extg.. Hyd.

46N Coolmg Tower Equipment House & ION None Extg Hyd. Transformers 47N Coolmg Tower Iransformer Oil Sump N/A None Hyd. 48N DI. D2 Diesel Fuel Oil Storage Tanks N/A None Hyd. l 49N Heating Boiler i uct Oil Storage Tank N/A None Hyd. i 50N Cooling Tower Control House 121 & 122 ION None Extg., Hyd. i SIN Neutralizer Tank Pump House / Warehouse #2 ION DE-3 Extg., Hyd. 52N Parking Lot N/A None Extg., Hyd. 53N Receiving Wa.chouse, NPD Ottice & NPD ION DPS-l Extg., Hyd., Annex PA-10 Hose Station 54N Coolmg Tower Control House 123 & 124 ION None Extg.. Hyd. 55N Warehouse #1 and Fab Shop ION WPS-26 Extg.. Hose Station 56N Drum Storage Area N/A None DM-7. Hyd.. Extg. l 57N Gas House THERMAL None Extg.. Hyd. 58 Aux Buildmg Ground Iloor Unit i ION, SMOKE, W PS-Il Extg. i TilERMAL SWP-2.4 liose Station 59 Aux Building Menamne Floor Unit i ION SW P-4&2 Extg. l WPS-19, Hose Station i 20.23.24 60 Aux Buildmg Operatmg Floor Unit 1 ION SWP2&4 Extg. WPS-24 Hose Station 61 Aux Bldg Anti"C" Clothmg (735') lON  % PS-27 Extg. v WPS 28 Hose Station Aux Bldg Hatch Ares (755') ION i 61A 62N Sperit Fuel Pool Area ION None Extg., Hose Station  ! 63N hiter Room N/A None OSRM  ! 64N Aux Buildmg Low Level Decay Area. Umt 1 ION None OSRM f 65N Spent Iuct Pool HX & Pumps N/A None -OSRM l 66 Storage Room lON  % PS-22 OSRM I 67N Resm Disposal Buildmg lON None Extg Hose Station 68 Contamment Annulus Unit 1 ION. FLAME PA-3. 4 OSRM 69 Turbme Buildmg Ground & Men Floor Umt 1 ION, HEAT, DA-l&3 Extg. SMOKE WPS-7,8,9,18 Hose Station SWP-3.5 70 Turbme Buildmg Grour d & Men floor Unit 2 ION DA 4&S Extg. WPS-15,16 Hose Station  ; I7,21  ! 1 SWP-13.14 Contamment Umt 2 ION. SMOKE None Extg., Hose Station l 71 72 Contamment Annulus Umt2 ION, FLAME PA-6&7 OSRM 73 Aux Buildmg Ground Floor Umt 2 ION, SMOKE S % P-12 Extg., Hose Station 74 Aux Building Men Floor Umt 2 ION SWP12 Extg., Hose Station 75 Aux Buildmg Operntmg Floor Umt 2 ION SW P-12 Extg Hose Station 76 Vent and Fan Room Unit 2 ION FWP Extg., Hose Station 77N Aux Buildmg Low Level Decay Area. Unit 2 N/A None None 78N Waste Gas Compressor Area lON None OSRM 79 480V Sateguards Swgr Rm(Bus 112) ION None Extg.. OSRM 80 480V Safeguards Swgr Rm (Bus 1Ii) JON None Extg., OSRM 81 4KV Safeguards $wgr Room (Bus 15) lON None Extg OSRM 82 480V Safeguards Swgr Rin (Bus 122) lON None Extg.. OSRM 83N Inst. Lab Area lON None Extg.. OSRM

         $4N     Counting Room & Labs                                 ION        None              Extg.,05 RM 85N     Holdup Tank / Ikmmeralizer Area                      lON        None                  OSRM 86N    intake Screenhouse, Envir Lab, Rad Momtor            N/A        None                Extg., H)d.

Station & De-Icing Pump House 87N Deepwell Pump House #1 lON None Extg. i 8&N Deepwell Pump House #2 lON None Extg. 89N Guardhouse ION DE-1 Extg.. (H) VON Emerfency Generator Building lON DE-2 Extg.. Hyd. 9tN Diesel bre Pump & Diesel Cooling W ater N/A None Hyd. Pump Oil Storage Tanks B-43 i

!' Table B.2.8.1 (continued) Fire Detection and Suppression flRE AREA AREA PROTECTION NUMBER DESCRIPTION DETECTION 92 Water Chiller Room Unit 2 ION None OSRM ! 93N Drum Storage /lmw Level Radwaste % archouse ION DM-7 Extg., flyd. 94N Service lluilding/ Computer Area ION llalon, DPS-2 Extg. SWP-31 flyd. 95N DS Diesel fuel Oil Storage Tanks N/A Nonc ilyd.

96N D6 Diesel Fuel Oil Storage Tanks N/A None liyd.

97 D5 liasement (687) ION PAD-12 Extg OSRM ]' 98 D611asement (687) ION PAD-13 Extg., OSRM 3 99N Stairwells (El.695'.707' & 718') N/A WPS-32 Extg OSRM I 100N #21 D5/D6 Fuel Oil Receiving 1ank ION DA-6 Extg., OSRM { 101 D5 Diesel Generator Room TilLRMAL, PAD-12 Extg., OSRM i FLAME 102 D6 Diesel Generator Room TitLRMAL, PAD-13 Extg., OSRM j FLAME I D5 Emergency Diesel Generator Control Room 103 ION None Extg. OSRM

,                              104    D6 Emergency Diesel Generator Control Room             ION            None       Extg., OS RM 105N    D5 Battery Room                                        lON            None       E xtg.. OSRM 106N    D611attery Room                                        ION            None       Extg OSRM 107    D5 invener Room                                        ION            None       Extg., OSRM 108    D6 inverter Room                                       ION            None       Extg.. OSRM 109    DS Normal MCC & Cable f ray Area                       lON            None       Extg., OSRM i10    D6 Normal MCC & Cable Iray Area                        lON            None       Extg OSRM
;                              all    D5 liuildmg - Menamne f loor 718'                      ION            None       Extg OSRM

] 112 D6 iluildmg - Menanine Iloor 718' ION None Extg.. OS RM 113 #21 D5 fuel Oil Day Tank Room ION WPS-32 Extg., OSRM i14 #22 D6 Iuci Oil Day Tank Room ION WPS-33 Extg.. OS RM i15 #21 D5 Lube Oil M-U 1ank Room ION WPS-32 Extg. OSRM i

        )                      116 117
                                      #22 D6 Lube Oil M-U Tank Room 4KV ilus 25; MCC-21 Al ION lON
                                                                                                           % PS-33 None Extg., OSRM Extg.. OSRM i18    4 KV ilus 26; MCC-21 A2                                lON            None       Extg.. OSRM 119    #21 D511t/Lt M-U lank Pump Room                        ION            None       Extg.. OS RM 120    #22 D6 livLt M-V Tank Pump Room                        ION            None       Extg., OSRM 121N    Stairwell (Lt. 735')                                   lON            None       Extg.. OS RM 122    480V lius 221/222 Room                                 ION            None       Extg.. OSRM 123    D5 Radiator Room                                       N/A            None       Extg., OSRM 124    D6 Radiator Room                                       N/A            None       Extg.. OSRM 125    D5 f an Room                                           N/A            None       Extg.. OSRM 126    D6 I an Room                                           N/A            None       Extg.. OSRM 127    480V Dus 211/212 Room                                  ION            None       Lxtg., OSRM 128N    4KV ilus 27 Room                                       lON            None       Extg.. OSRM 129N    D5 Radiator Lxhaust (Rood                              N/A            None       Lxtg., OSRM 130N    D6 Radiator Lxhaust (Roof)                             N/A            None       Extg. OSRM 13lN    New Admin 11ualdmg                                     N/A       PAD-10 & 11     Extg.. OSRM v                                                                                                                                  i B-44 i

I B.2.9 Fire Growth and Pronacation All potential propagation paths that could result in fire spreading to a compartment containing safe shutdown equipment or plant trip initiators were considered. The Appendix R fire areas I were reviewed to assess the potential for cross-area propagation based on the existing fire l barriers and fire area loading. The potential for fire spread from the compartment being evaluated (exposing compartment) to the adjacent compartments (exposed compartments) was examined. Each common boundary was analyzed for fire spread in either direction. A means of addressing fire spread across these boundaries is addressed in the FIVE methodology and was used in this study. Criteria to ) determine fire spread were identified in Section B.2.1. i

                                                                                                           )

Any scenario where a fire could potentially involve two or more adjacent areas was analyzed for l potential fire spread by extending unscreened boundaries. This step was performed in j accordance with the FIVE screening criteria shown in Section B.2.1. Fire spread scenarios were l identified and tracked for all entered fire areas. l 1 Fire scenarios that have the potential to spread beyond the initiating compartment were identified as Burn Sequences in Table B.2.6.3. There are nine locations within the plant that have the potential for fire spread beyond the originating compartment. Fires in compartments not shown in this table will not spread to adjoining compartments. (m'~-)B.2.10 Fire Event Trees 1 This analysis was based upon the Prairie Island transient and small LOCA event trees (Figures l B.2.10-1 and B.2.10-2). A fire in most locations in the Prairie Island plant would initiate an ) event similar to a transient event with one or more of the systems identified in Section B.2.1 out of service due to the fire. The small LOCA event tree from the internal events PRA was used to 1 model RCP seal LOCA. A top event was added to the diagram for operator cooldown and depressurization on the seal LOCA, although this was not credited in the quantification (see Section B.2.10.1). One additional event tree was developed specifically for this analysis (Figure B.2.10-3). It was developed for fires in the main Control and Relay rooms and was based on the internal events PRA transient event tree. Top events were added to account for the effects of suppression and switching control of the plant to the HSDPs (Hot Shutdown Panels). Accident classes were defined such that core damage sequences with similar characteristics (e.g., reactor vessel failure pressure, core damage timing, system failures) could be grouped and analyzed together. The three accident classes employed in the fire IPEEE are a subset of the accident classes found in the internal events PRA. These accident classes are Class TEH - early core melt with the reactor at high pressure; Class TLH - late core melt at high pressure; and Class SEH - early core melt at high pressure in conjunction with a small LOCA. This is discussed in D more detail in Section B.2.10.4. O B-45

l l B.2.10.1 Fire Event Tree Top Event Definitions l FIRE Fire Initiator The fire is defined as starting in a location that would cause a plant transient initiator, require a manual shutdown, or affect plant equipment potentially useful for plant shutdown. S Suberiticality Insertion of negative reactivity to bring the reactor suberitical. SUP Sunpression of Fire Before Soread (Control / Relay Rooms only, see Section B.2.10.2) The fire is suppressed by either occupants in the room or by automatic I suppression equipment before it can spread to other locations. In the Control Room fire, successful manual suppression limits the extent of the fire to the cabinet in which it is assumed to initiate (initially assumed to be the FW/AFW i panel as they are located in the same panel, and loss of secondary side cooling was judged to be conservative). Successful suppression of a fire in the Relay ) Room assumes that fire damage occurs to FW and AFW but is limited to those ) systems. It is assumed that the smoke created from a fire involving one panel, given the existing ventilation, would not force the evacuation of the Control Room. In the event of fire suppression failure in the Control Room or Relay Room, it is assumed that extensive damage is possible, requiring inventory makeup to be accomplished from the HSDPs. Controls for the AFW pumps and charging pumps are located on the HSDPs. Automatic fire suppression was also credited for fires in the AFW pump room areas. Ilowever, this credit was applied after the sequence quantification, such l that the quantification of those rooms followed the transient event tree (see Section B.2.10.3). IISDP Operators Control Plant at Hot Shutdown Panel 01SDP) (Control / Relay Rooms only) The operators carry out the " Control Room Evacuation (Fire)" procedure, Plant Safety Procedures, F5 Appendix B, evacuating the main Control Room l (immediate actions) and transferring plant control to the HSDPs. RCP RCP Seal LOCA l Loss of all cooling to the RCP seals is assumed to fail the seals and result in a small LOCA. Failure of both the component cooling and charging systems will yield this condition.. li Secondary Cooline B-46

I ( Two systems, auxiliary feedwater and main feedwater, are credited with providing secondary makeup under this event tree heading. Auxiliary feedwater can be provided to either or both steam generators from one of three pumps, a motor or l turbine driven pump from the unit in which the trip occurred, or a motor driven  ! pump from the second unit if operator action to align it is successful. The main feedwater pumps (two) are motor driven and, if tripped (but not failed) as a result of the initiator, can be retumed to service from the Control Room. STI Short Tenn RCS Inventory (Bleed and Feed) For transient initiated events (typical fire events), no short term inventory makeup is required provided secondary heat removal has been successful. Bleed and feed requires manual start of at least one safety injection pump and opening of a pressurizer PORV to provide short term RCS inventory control and to remove RCS decay heat.  ! Given a RCP seal LOCA, a safety injection signal will be generated on low pressurizer pressure or high containment pressure and the SI pumps will start automatically. If secondary heat removal has been successful, injection by a single SI pump is all that is required to satisfy short term RCS inventory control. CD RCS Cooldown and Depressurization For RCP seal LOCA events in which high head injection through the SI pumps is not available, it is possible that the rate ofloss ofinventory through the break is much less than would be expected for a " random" small LOCA event. This would allow time for operator action to cooldown and depressurize the primary system such that RIIR could be used for inventory control. This heading was included in the event tree to illustrate this possibility; however, no credit was taken for cooldown and depressurization in the analysis (failure of CD set to 1.0). LTI Lonn Term RCS Inventorv I For transient initiated events (typical fire events) in which secondary cooling failed but bleed and feed was successful, approximately 8 to 10 hours are I available prior to depletion of the RWST. To continue adequate core cooling, initiation of recirculation from the containment sump is required. Ifigh head recirculation requires realignment of an RHR pump suction from the RWST to the containment sump and then to the suction of a SI pump, " piggy backing" the two systems. Success criteria for long term inventory control for small LOCA sequences (e.g., ) RCP seal LOCA) in which secondary cooling is not available is the same as for the transient events in which bleed and feed occurs. C Containment B-47

p b Containment heat removal is assumed to be necessary for any accident sequence in which long term recirculation from the sump is occurring. Containment pressure control can be provided by operation of two fan coil units or a train of ) containment spray. Similar to SI, spray recirculation requires the containment spray pump suction to be aligned to RHR after the suction from the RHR pumps has been shifted to the containment sump. I H.2.10.2 Event Tree For Fire in Main Control Room and Relay Room The Control Room and Relay Room fires are discussed separately due to credit taken for fire suppression in these rooms. Figure ControlRoom The event tree for fire in the main Control Room is similar to the transient event tree. The differences are:

1. The event SUP is included to account for the likelihood of the fire being suppressed by the operators before it can spread from a single Control Room panel. This event was discussed in Section B.2.8. The probability assigned to the failure of this event is 0.01.

2. The event HSDP is included to account for the operators' ability to recognize the need to

('] U evacuate the Control Room and to successfully transfer control of the plant to the HSDPs and control the plant from that location. A human reliability analysis was performed on this action. The probability of failure of this event is 3.4E-3, given at least thirty minutes to staff the HSDP. This event tree assumes that successful suppression of the fire in the Control Room must take place before it can spread to other locations. Successful manual suppression, therefore, limits the extent of the fire to the cabinet in which it initiates or to localized damage ifit starts outside of a cabinet. Spreading of the fire beyond the initiating cabinet is assumed to force the evacuation of the Control Room. Relay Room The event tree for fire in the Relay Room is also similar to the transient event tree. The differences are:

1. The event SUP is included to account for the likelihood of the fire being suppressed before it can spread to locations impacting more than one injection system. Automatic suppression is j assumed to limit the extent of the fire to the cabling of a single function, secondary cooling I' (main and auxiliary feedwater). These systems were selected to be failed during Relay Room fires that were suppressed because their loss has the highest impact on the core damage p frequency of any of the systems credited in the analysis of this area. The feedwater system V also initiates a plant trip ifit fails. The probability assigned to the failure of Relay Room suppressiori is estimated to be 4E-2 (CO2) as discussed in Section B.2.8.

B-48

Y

2. The event HSDP is included to account for the operators' ability to recognize the need to V successfully transfer control of the plant to the HSDPs and to shut down the plant from that location. This is the same event as described above for the Control Room fire and the probability of failure of this event is estimated to be 3.4E-3. 1 It is assumed in this analysis that when the fire is suppressed by automatic suppression equipment, it does not spread to other locations. Automatic suppression, therefore, limits the extent of the fire to the main feedwater and auxiliary feedwater cabling.

This event tree was quantified using the same methods used in the internal events PRA for the transient tree and the results of that quantification are provided in Table B.2.11.1. B.2.10.3 Fire in AFW Pump Room This event would also follow the transient event tree logic. However, credit was taken for fires i being suppressed before they could spread beyond the location where the fire initiated within an area. The most severe heat load due to a fire in either of these areas would occur due to a postulated oil leak from a pump. Using the FIVE methodology, it was determined that the sprinkler system could be actuated prior to the thermal damage threshold being reached in overhead cable trays. The probability of failure of automatic suppression in these areas is 2.02E-2 per demand (from FIVE). This suppression factor was applied to determine the CDF for e unsuppressed fires. ( Fires that are suppressed in these areas were assumed to result in a transient (i.e., manual shutdown) with one component unavailable, the component in which the fire started. The most limiting case for each of the AFW pump rooms is to assume that the fire starts in the motor-driven AFW pump (the instrument air compressors are also located in these rooms). Assuming this pump is unavailable, but all other equipment is unaffected by the fire and is subject only to random failures, results in a negligible CDF for suppressed fires in the AFW pump rooms. Credit for automatic fire suppression in the AFW pump rooms was applied through the use of recovery actions following sequence quantification. Therefore, no event tree was created to specifically model a fire in this area (followed the transient event tree logic for quantification). This was done since equipment was assumed to have actually failed for this fire, as opposed to controls for remote operation of the equipment from the control room. For fires in the Control and Relay rooms, a separate event tree was required because credit for equipment operation could still be taken iflocal control could be established by the operator at the Hot Shutdown Panel (HSDP). Note that the HSDPs are physically located in the AFW pump room. B.2.10.4 Accident Sequence Classification This section discusses the binning of core damage sequences into functional categories based q upon characteristics of the accident sequences with respect to reactor and containment conditions Gi at the time core damage is assumed to occur. These functional categories are called " accident classes". B-49

p The potential types and frequencies of accident scenarios at a nuclear power plant cover a broad

 \   spectrum. In order to limit these sequences to a manageable number, sequences with similar functional characteristics are grouped together. Three such functional classes were defined for the Prairie Island fire IPEEE:

Class TEH Transient-initiated events in which both MFW and AFW systems become unavailable. Bleed and feed cooling of the RCS fails, causing core uncovery with the reactor at high pressure for these sequences. Core uncovery occurs relatively early (within a few hours of the failure of MFW and AFW). Class TLH Transient-initiated events in which both MFW and AFW systems become unavailable. Bleed and feed cooling is successful, but high head recirculation fails. Core damage occurs relatively late (i.e., approximately 8 to 10 hours) after the accident, and at high RCS pressure. Core damage is assumed to occur at a high reactor pressure. Class SEH These sequences are characterized by RCP seal LOCAs with failure of  ; short-term reactor coolant inventory control. Core damage occurs early and at high RCS pressures. l These accident classes are typical of other PRAs and are a subset of those used in the Prairie b Island internal events PRA. Other accident classes that were not considered to be applicable to l the fire PRA include: l l l Class FEH, FLli These classes are characterized by breaks in cooling water line which result in floods. These breaks cannot be initiated by fires, and the probability of a break concurrent with a fire is extremely low. Therefore, these accident classes are not applicable. Class GEH, GLH These classes are associated with steam generator tube ruptures. These are not considered for reasons similar to those discussed above for FEH and FLH. Class SLL This class is characterized by large or medium LOCAs. No credible fire-related large or medium LOCAs were identified. l Class V This class is the interfacing system LOCA class. No fire-related mechanisms for Class V sequences were identified, and therefore this class is not considered. ATWS Classes No fire initiator was identified that could credibly lead to a failure of the reactor protection system. The simultaneous, independent failure of the reactor protection system or of control rod insertion during a fire is probabilistically insignificant. B-50

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M R A E D T T L E G \: N O C L l J - N I _ M R E T I T S T R O 9 H 1 S . 5 _ G N B I L ., O _ O C _ Y R H e A e r De - T O t n C E S e v E t e A n e C e _ r O L is _ T L A C P n a t E R r n S T _ e P e v C r _ E R i t F n la _ i e n r s n Y T t e a r I L n A i T C I T S d t R e C c S u U d S - I n e r i F R O T A l

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           . Figure B.2.10.2           Fire-Induced RCP Seal LOCA Event Tree O

RCP SEAL LOCA SECONDARY COOLING SHORT TERM INJ RCSCD DEPR LONG TERM INJ stu UI. Ass stuNAME Transfer H STI CD LTI Success 1 9_ m 2 i SLH 3 j SLH 4 SEH 5 Suaess s t SLH 7 SEH B P I 4 I i P I RCP Seal LOCA Event Tree Page 1  ; l C:\ ETA \RCPLTRE l 12/11/96 l 4 i B-52

Figure B.2.10.3 O Fire-Induced Transient Event Tree, Control Room & Relay Room Area 3 O CONT stGGLAS5 stut-?.T SU9CRITICAttTY SUPPRESSION HOT SD PANEL RCP SEAL LOCA SEC. COOLING SHORT TERM INJ LONG TERM INJ FIRE (CR CS) SUP HSDP RCP H STI LTI C Fre S l Success 1 TLC 2 TLH 3 t TEH 4 SLOCA 5 TLC S . TLH 7 TEH B SLOCA 9 Success 10 TEH 11 TEH 12 TEH 13  ;

                                                                                                                                                                                                                                                                  ^TWS                         14 I

i i Control Room and Relay Room Event Tree Page 1 l C:\ ETA \MCCS.TRE l 12/11/96 l , i L B-53

I s l l 1 i i B.2.11 Analysis of Fire Seouences and Plant Response This section gives the results of the fire sequence quantification, first by accident class and then by fire area. Important assumptions, fire initiators, operator actions and hardware failures that I drive the accident class results are given in Section B.2.11.1. Important cables assumed to be damaged by a fire in a given area are discussed in Section B.2.11.2. The following screening criteria were used to identify sequences to be discussed in this section of the report. This criteria is identical to the functional reporting requirements presented in Generic Letter 88-20 as required by NUREG-1407.

1. Functional sequences with a CDF greater than 1E-6 per year. (Functional sequences for the Prairie Island fire IPEEE are the accident classes defined in Section B.2.10. All the accident classes meet this criteria and are discussed in detail below. Also, core damage frequency results by fire area that meet this criteria are discussed in detail below. Result by fire area that are greater than IE-7 per year are reported in Table B.2.ll.l.)

2. Functional sequences that contribute five percent or more to total CDF. (All the accident classes meet this criteria and are diseassed in detail below. Also, fire area results that contribute more than 2% of the total are discussed in detail below. Results by fire area that contribute more than 0.1% of the total are reported in Table B.2.ll.l.)

3. Sequences determined by the utility to be important contributors to CDF or containment performance.

H.2.ll.1 Important Accident Classes Class TEH: The sequences within this class were characterized by an early core melt with the reactor at high pressure. This class contains sequences totaling 2.26E-5/ year or approximately 36% of the overall internal fire events CDF. This class was dominated by sequences initiated by . fires in the Control and Relay Rooms, Turbine Building Ground and Mezzanine Floor Unit I and the "A" Train liot Shutdown Panel and Instrument Air Compressor /AFW Pump Room, imponant assumptions applicable to this class that are reiterated from the internal events PRA:

1. It has been shown through MAAP analysis that only one pressurizer PORV is required for successful bleed and feed cooling.

2. The motor-driven AFW pump from the second unit can be crosstied to Unit I steam generators. A limitation on this crosstie was included in the fault tree for AFW such that if a dual unit initiating event occurred and ihe Unit 2 turbine-driven auxiliary feedwater pump failed, the Unit 2 motor-driven feedwater pump could not be crosstied to Unit I as it would be required on Unit 2. It should be noted that all fires were conservatively assumed to result O in shutdown of both units, thereby limiting credit for this crosstie.

B-54

                                                                                                            +

3. It is assumed that the pressurizer PORVs cannot operate after instrument air has been lost.

U) There are air accumulators on each PORV that are designed to allow approximately 15 cycles j of valve operation after loss ofinstrument air. Bleed and feed requires sustained open times for the PORVs. It is not known how long the PORVs may remain open while on the air accumulators so it was conservatively assumed they are unavailable on loss ofair.

4. Feedwriter addition through the condensate pumps is not credited in the IPE as the majority of the failures for feedwater also fail condensate. Therefore, it was felt that this method of feedwater addition would not significantly reduce the potential for loss of secondary cooling.

l The most significant fire initiating events were: l 1

1. Fire in the Bus 121480V switchgear room (FA 22) accounts for 36% of the core damage  !

frequency in this accident class. Components affected by this fire include the Unit I motor-driven AFW pump and control circuitry for the Unit 2 turbine-driven pump. Both trains of SI are available to support bleed and feed cooling,if required.

2. Fire in the Turbine Building Ground & Mezzanine Floor Unit 1 (FA 69) accounts for 22% of the contribution to Class TEH CDF. A fire in this area is assumed to disable feedwater and the #11 AFW pump, three of the cooling water pumps (due to power and control cables passing through this area), as well as power to the IK2 and 1KA2 MCCs. The #12 and #21 AFW pumps are available for S/G makeup. ,

(m]

 \

3. The Relay Room (FA 18) accounts for 13% of the TEli accident class. These accident i

sequences are dominated by a failure to suppress the fire in the Relay Room, followed by an inability to establish mrbine-driven AFW operation from the Hot Shutdown Panel.

4. The Aux Building Ground Floor Unit 1 (FA 58) accounts for 9% of the total TEll core damage frequency. AFW operation is largely unaffected by fires in this area, limiting the importance of the area to this accident class.

5. Fire in the "A" AFW pump area (FA 31) accounts for about 8% of the fire-initiated contribution to Class TEH CDF. These sequences are a result of failure to suppress the fire and unavailability of the "B" AFW train. An unsuppressed fire in this area is assumed to result in loss ofinstrument air (assuming operator failure to cross-tie station air to instrument air), MFW and #12/22 AFW pumps. The turbine-driven AFW pump remains to provide steam generator makeup.

The most significant operator actions contributing to this accident class were:

1. Failure to suppress the fire in the Control Room / Relay Rcom. Approximately 30% of the core damage associated with this accident class results from sequences in which fire suppression in the Control Room or Relay Room is unsuccessful. Failure to suppress the fire (operator inability to suppress a fire in the Control Room and automatic suppression failure in the Relay Room) followed by failure to take control of the plant at the Hot Shutdown Panel dominated this area.

B-55

i n 2. Failure to cross-tie service air to the instrument air system contributes 23% of the core U damage associated with this accident class. This operator action is assumed to apply to accident sequences in which instrument air is lost to support MFW or bleed and feed.

3. Failure of the operator to line up #21 AFW pump to Unit 1. Approximately 4% of the core damage frequency associated with this accident class resulted from failure of this action. -

This operator action is assumed to be required when loss of Unit I secondary cooling occurs, l and it is only credited if the Unit 2 turbine-driven pump is available to accommodate Unit 2 decay heat removal. (In the accident sequence quantification, the conservative assumption is j made that both units are shut down as a result of the fire.) 1 l Irnportant hardware failures asmciated with this accident class include: l

1. Failure of the #11 and 12 AFW pumps to start and run. At least one of these two pumps plays a role in providing secondary cooling for each initiator.

2. Failure of the #12 and 22 diesel-driven cooling water pumps to start and run. The diesel- I driven pumps play a significant role in providing support for component cooling water, main feedwater or instrument air operation in a number of the fire areas.  !

Class TLJJJ Sequences in this class were characterized by events with late core melt at high pressure. Class TLil sequences made up approximately 5% of the fire-initiated CDF at Prairie Island. They had a combined sequence frequency of 3.2E-6 per year. l The important assumptions made for Accident Class TEli also apply to the TLII Accident Class. Significant fire initiating events for this accident class were: 1

1. Suppressed fires in the Control and Relay Rooms (FAs 13 and 18, fire limited to a single {

eabinet) account for 57% of the fire-initiated contribution to Class TLli CDF. That these J fires dominate the TLil accident class is a result of the assumption that all fires in the Control I Room affect the operation of AFW even if the fire is suppressed. j

2. Fire in the Turbine Building Ground & Mezzanine Floor Unit 1 (burn sequence 69) accounts l; for 42% of the contribution to Class TLII CDF. A fire in this area is assumed to disable j feedwater as well as power to the 1K2 and 1KA2 MCCs (which power the 11 and 13 charging pumps as well as component cooling valve MV-32094).

The most significant operator actions contributing to this accident class were:

1. Operator fails to initiate high head recirculation. This accounts for 58% of the Class TLil CDF. Again, a conservative assumption has been made that Control Room and Relay Rocm l' fires affect the ability to operate AFW except from the hot shutdown panel. Loss of AFW is g assumed to lead to the need for bleed and feed and ultimately high head recirculation.

2. Failure to successfully control the plant from the hot shutdown panel for fires in the Control Room accounts for 55% of the Class TLli CDF contribution.

B-56

i Important hardware failures associated with this accident class include: l

1. Random hardware failure is not an important contributor to core damage sequences making up this accident class. Hardware failures are found in less than 20% of the core damage i contribution. Failure of AFW components, specifically the #12 AFW pump, comprise the majority of the core damage contribution due to hardware failures.

l Class Sell: Class SEH events were accident sequences resulting in early core melt at high pressure as a result of a seal LOCA (SEH). The core damage probability for this accident class was determined to be 3.73E-5 per year due to fires, or approximately 59% of the total. Assumptions for Class SEH events were: u

1. In the fire PRA, no credit was given for cooldown and depressurization of the RCS to initiate shutdown cooling following a seal LOCA. This results in the SI system being a mandatory )

injection source for a seal LOCA.

2. It is conservatively assumed that the SI pumps fail immediately on loss of component cooling as component coolin;; provides cooling for lube oil and seal cooling. In reality, the pump  :

may continue to operate for a length of time and the operator could cycle pumps to prevent lube oil overheatmg. t Significant fire initiating events for this class were:

1. Fires in the Auxiliary Building Ground Floor Unit 1 (FA 58) account for 62% of the core damage associated with this accident class. These fires are significant in that only one train of component cooling is available for RCP seal cooling if all equipment in this area is assumed to fail. Crossticing to Unit 2 component cooling is credited for sequences t contaiming random failure of the surviving train of component cooling.

2. 4kV Safeguard Switchgear Room-Bus 15 (FA 81) contributes 10% of the CDF associated with this class. All three charging pumps and a train of component cooling are assumed to be affected by a fire in this area. Train B component cooling remains to provide seal cooling.

3. 480V Safeguards Switchgear Room-Bus 111 (FA 80) contributes 7% of the CDF associated with this class. This area supports a number of Train A components.

4. "B" Train Hot Shutdown Panel A Air Compressor /AFW room (FA 32) contributes 6% of the CDF associated with this accident class. All three charging pumps and a train of component cooling are assumed to be failed as a result of a fire in this area. Train B component cooling remains to provide seal cooling.

The most significant operator actions in Class SEH were:

1. Failure to manually crosstie the component cooling between units is found in cutsets I

accounting for 54% of the core damage attributable to this accident class. This operator action is most imponant for fires in the Aux Building Ground Floor (fire area 58) where all B-57 i l

l p\ three charging pumps and a train of component cooling are assumed to be damaged as a result of the fire. Failure of the remaining train of CC would necessitate this operator action. l Although the action is covered by a procedure and is relatively simple, the operator will be performing the task under stress and will be relatively close to the fire. As a result, a relatively large screening value of 0.3 probability of failure for this action was used in the analysis. The local manual valves that are required to be opened for the cross-tie action are located at the edge of the fire area (between the CC heat exchangers, at the boundary of Fire Areas 58 and 73) with very little combustible material nearby. As a result no significant fire is expected to propagate to the area where the valves are. In addition, because the valves are at the edge of the fire area, the operator can go to their location from the Unit 2 side of the I auxiliary building ground floor.

2. Failure of the operator to start the standby component cooling train contributes to 21% of the cutsets in this class. This operator action is required when the normally operating train of component cooling water is affected by the fire.

Important hardware failures associated with this accident class include:

1. Various hardware failures of the component cooling system are found in 37% of the cutsets in the Class SEH contribution. The primary hardware failures in this class consist of failure of the valves isolating cooling water from the component cooling water heat exchangers to I open. These failures are found in cutsets accounting for 28% of the total CDF associated with Class Sell failures. Failures of the cooling water system supply account for most of the ,

remaining CDF. j B.2.11.2 Important Fire Arcas/ Rooms As shown in Figure B.I.4.3,95% of the plant risk associated with intemal fires can be traced to , nine fire areas / burn areas. Attachment I contains floor plans showing the locations of the fire l areas. These areas are:  ! l

1. Auxiliary Building Ground Floor Unit 1 (FA 58),

2. 480V Safeguards Switchgear Room-Bus 121 (FA 22),

3. Turbine Building Ground & Mezz Floor Unit 1 (FA 05,08,14,21,27,57,69,94),

4. Relay (cable spreading) Room (FA 18),

5. 4KV Safeguards Switchgear Room-Bus 15 (FA 81),

6. 480V Safeguards Switchgear Room-Bus 111 (FA 80),

l l 7. Train "B"llot Shutdown Panel and Air Compressor /AFW Room (FA 32), p i d

8. Control Room (FA13), and t

9. Train "A" Hot Shutdown Panel and Air Compressor /AFW Room (FA 31).

B-58

,o This section provides the detailed plant response for each fire area /sub-area not previously screened from consideration. The quantification results presented in Table B.2.11.1 include:

1. The sub-area in which the fire occurs,

2. The frequency of fire ignition in that area,

3. The systems / subsystems potentially affected by a fire in that area,

4. The core damage frequency (CDF) for this fire, assuming all the systems in this specific area have failed,

5. Amplifying remarks where appropriate.

Auxiliary buildinc 695' (Area 58h This sub area contains many components that are necessary for safe shutdown of the plant. Both trains of Safety injection, RHR and Component Cooling as well as all three charging pumps are located in this area. In addition to the components physically located in this area, cables powering or controlling other equipment (MFW, AFW, IA, etc.) also transit the area. Although this is an extremely large area and most of these components are sparsely located with significant distance between key equipment, a fire anywhere in this area is assumed to engulf the entire area. The only exceptions to this assumption are as follows:

1. The analysis credits the availability of power to MCC IKA2 and from MCC 1KA2 to the

_ motor-operated valve MV-32146 (on cooling water side of 12 CC heat exchanger). This assumption is based on a fire spread analysis which takes into account all combustibles in the vicinity of the MCC and the fact that the subsequent cables are fire protected. Similarly, cables located directly above the CC heat exchangers are not assumed to fail since there are  ; no combustibles in the area. AFW pumps 11,12 and 21 all remain available. In addition, l Train B component cooling is credited to be available due to fire wrapping of critical power j and control cables. No fire suppression is credited for this fire area. An operator action is credited for this area to cross-tie Unit 2 component cooling should random failure of Train B component cooling occur.

2. Fire area 58 is located next to fire area 73 (Unit 2 Auxiliary building 695'). A fire that initiates in 58 is assumed not to spread to fire area 73 due to a relatively large open area that separates the two fire areas. The only combustibles in this open space are cables in horizontal cable trays. Such combustibles are not conducive to fire spread across significant distances.

This fire area produces 44% of the total core damage frequency for internal fires. The accident class that is dominant is SEH which represents 93% of the total core damage frequency for this fire area. Train B component cooling from Unit I and the cross-tie from Unit 2 are available to protect against loss of reactor coolant pump seals. All three charging pumps and Train A component cooling are physically located in this area and are assumed to f ( be failed. B-59

q 480V Safecuards Switcheear Room-Bus 121 (Area 22k Bus 121 provides power for Train B

 ) 480V equipment. Unit I components with power or control circuitry in this area include the motor-driven AFW pump, #12 component cooling water valve MV-32146, and the #11/13 charging pumps. Control circuitry for the Unit 2 turbine-driven AFW pump is also routed through this area. Fuel supply for the 22 diesel cooling water pump is dependent on panels ultimately powered from Bus 121 as well as the 21 safeguards screenhouse roof exhaust fan / dampers.

Area 22 accounts for 14.1% of the total core damage frequency. The bulk of the core damage sequence frequency (90%)is associated with class TEH. Only 9% of the potential for core damage results from sequences leading to seal 1 OCA. The area was analyzed assuming all equipment and cables located in the room were damaged by the fire. No credit for manual fire suppression was tsken.  ! The Unit 1 turbine-driven feedwater pump is the principo! :r.eans of providing secondary heat removal for fires in this area. Should secondary cooling be lost, the #12 cooling water pump is 1 I available along with either the #11 or #121 cooling water pumps to assure bleed and feed capability through support ofinstrument air compressors and component cooling. Turbine Buildine Ground & Mezzanine Floor Unit 1 (Fire areas 05. 08.14. 21. 27. 57. 69. and 94h This area represents one of the higher fire initiating frequencies due to turbine oil and gas : V fires. A fire in this area has the potential to fail all of main feedwater. Both feedwater pumps l and all three condensate pumps are physically located in this area. Other key components located  ! I in this area are cables supporting the operation of the #11 AFW pump, and the main power cables between 480VAC bus 121 and MCCs 1K2 and 1KA2. MCC 1K2 powers the #11 and #13 charging pumps as well as component cooling water valve MV-32094. MCC IKA2 powers cooling water valve MV-32146 as well as "B" train safety injection valves. Valve MV-32146 is I on the cooling water side of the #12 CC heat exchanger. This area accounts for 10.2% of the total core damage frequency. The TEH and TLH classes are the primary contributors to core damage (76% and 21%, respectively) for this area. The availability of both the motor and turbine-driven AFW pumps limits the risk significance of fire in this area. Control Room /Relav Room (Fire areas 13 & 18h The Control and Relay Rooms contain controls, monitoring instrumentation, and cables for most of the equipment used to achieve safe shutdown of the plant. Failure to suppress a fire in these areas was assumed to disable all equipment that could not be controlled locally or from the HSDPs. Most Control and Relay Room fires start in electrical cabinets or panels. Fire damage or subsequent suppression induced damage were assumed to render all circuits within the initiating cabinet inoperable. Fires within enclosed cabinets (Relay Room) were assumed not to spread d beyond the initiating cabinet. Fires in Control Room cabinets were assumed to spread to engulf the area if not successfully suppressed, forcing the evacuation of the Control Room. Fires B-60

1 I starting outside of cabinets were also asmmed to spread and engulf either the Control Room or v Relay Room if not successfully suppressed. If the fire was suppressed, all equipment not controlled from that panel was assumed to be available for use and would fail only due to random causes. If the fire was not suppressed, evacuation of the Control and Relay Rooms is assumed necessary and only equipment controlled from the HSDPs was considered available. General area fires (i.e., fires initiating outside of enclosed electrical cabinets) within the Control and Relay Rooms were assumed to engulf the entire room if not suppressed. Manual suppression was credited in the Control Room and automatic suppression was credited in the Relay Room. If suppression was successful, the cabung associated with at least one system (AFW) was assumed to be damaged. Suppression therefore limits the extent of the fire to a single system. These fire areas combined produce 9.4% of the total internal fire CDF. Class TEli and Class TLII sequences comprise the majority of the risk (69% and 31%, respectively) associated with Control Room and Relay Room fires. Class TEII sequences were dominated by operator inability to take control at the llSDPs in time to provide adequate core cooling following failure to suppress the fire in the Control Room or the Relay Room. This procedure is detailed in NSP Plant Safety Procedure F5, Appendix B, " Control Room Evacuation (Fire)." Core damage from Class TLil sequences consists of failure to initiate high head recirculation or take control of the plant at the llSDPs following successful suppression of the fire. Efforts to repair and recover l these components were not credited in these accident sequences.  ; 4kV Safecuards Switchcear Room-Bus 15 (Area 81) This fire area contains equipment that l provides power for Train A components such as the #11 Si and RiiR pumps, the #11 component cooling pump as well as power to 480V Switchgear Bus 111, which supports the operation of the

   #12 charging pump. Control cables for feedwater and condensate also transit this area.

This area was analyzed assuming all switchgear and cables located in the room were damaged due to the fire. No fire suppression was credited. 1 This fire area contributes only 5.8% to the total core damage frequency. Nearly all of this risk is due to RCP seal LOCA (accident class SEli). Very little is associated with accident class TEli due to the availability of both AFW pumps as well as the ability to crosstie the motor-driven pump from Unit 2. Train B component cooling as well as the #11 and #13 charging pumps limit the potential for a seal LOCA. Should bleed and feed be required for a seal LOCA due to random failures, Train B SI is available to provide adequate core cooling. 480V Safecuards Switcheear Room-Bus 111 (Area 80) Bus 111 provides power for Train A l 480V equipment. Equipment affected by fires in this area include Train A SI and RIiR, cooling j ! water valve MV-32145 and charging pump #12. Control circuitry for the 21 motor-driven AFW {O pump is routed through this area. Fuel supply for the #12 diesel cooling water pump ultimately is dependent on power provided from Bus 111. l B-61

l, i r~T Area 80 accounts for only 4.7% of the total core damage frequency, much less than that  ! U associated with the Bus 121480V switchgear room. Approximately 85% of this is due to accident Sell. The availability of both Unit I motor-driven and turbine-driven AFW pumps for this area largely accounts for the difference between the core damage frequencies for Bus 111 and Bus 121480V switchgear fires.  ! This area was analyzed assuming all equipment and cables located in the room were damaged by the fire. No credit for manual fire suppression was taken. The 12 AFW pump is available to provide secondary heat removal for fires in this area. Seal LOCAs are precluded by a train of component cooling or either of the #11 or #13 charging pumps.

     "A" Train llot S/D panel & Air Compressor / AFW numn area (Fire Area 31h This area                    !

contains the #12 AFW pump, #22 AFW pump, MCCs 2A1 and 2A2,123 instrument air l compressor and the "A" hot shutdown panel. In addition to the equipment physically located in the area, cables for power to MCC 1 AC2 and various other Train B components are routed through this area. Although only 123 instrument air compressor is physically located in this area, I 121 and 122 instrument air compressors are assumed to fail in this area due to cables traversing through the area. An automatic wet pipe suppression system is available and was credited in this area. If the suppression system actuates, it will prevent any fire spread or collateral damage a'nd I limits the damage to the initiating component. Otherwise the fire is assumed to engulf the entire area. - In the event of a fire in this area, only #11 AFW pump is available for secondary side cooling (21 AFW pump is assumed to be unavailable to Unit 1, since 22 AFW pump has failed, requiring 21 pump to supply Unit 2). With the loss ofinstrument air, failure of the operator to cross-tie station air to instrument air leads to the inability to bleed and feed and therefore loss of short term injection. This results in the TEli accident class dominating this fire area (>99%). Because of the installed automatic fire suppression capability, this area represents only 2.9% of the total internal fire CDF.

     "B" Train llot S/D Panel & Air Compressor / AFW numn area (Fire Area 32h This area contains the #11 AFW pump, #21 AFW pump, MCCs 1 Al and 1 A2, instrument air compressors 121 and 122, and the "B" hot shutdown panel. In addition to the equipment physically located in the area, cables for the #11 MFW discharge valve, MCC 1K1 and various other Train A components are routed through this area. Unlike fire area 31, the ability to cross-tie station air to instrument air is not available in this area since the valve that enables this operator action is physically located in this AFW pump room. An automatic wet pipe suppression is available and was credited in this area. If the suppression system actuates, it will prevent fire spread or collateral damage and limits the damage to the initiating component. Otherwise the fire is O
 'J assumed to engulf the entire area.

B-62

i i Unlike fire area 31, the TEH accident class does not contribute significantly to core damage for this fire area. A fire in this area most often would result in an SEH class accident due to loss of RWST as a source to charging and failure of 11 and 12 cooling water pumps. The motor operated valve MV-32060 fails to open automatically due to loss of 480 V AC power cables to MCC 1K1 which pass through this area. This results in reduced reliability for seal LOCA i protection and higher contribution to the CDF by SEH class. Class SEH represents 95% of the l CDF contributed by fire area. Overall, this fire area represents 3.6% of the total internal fire CDF.  ; I i

                                                                                                                                               ?

O  ! l l LO r l B-63 l

                                                                  .- - - - .                        .                 .. .                ---       -                                        _=, .-              .     . ..    -
                                                                                                                                                                                                                        ~

O O Table B.2.11.1 Prairie Island Plant Response to Area-Specific Fires Area Area Train / Function Failed try Fire TreintFametion Ignition Transient Transient SLOCA Total Commenta Number Description Available Freq. (TEM) (TLH) (SEH) 'CDF 13 Control Room All equipment not controlled from #11 AFWPmp 2.07E-2 1.05E-6 9.17E-7 < 1 E-8 1.97E-8 Credd for manual the HSDP failed for fires requinng #12 CHG Pmp supp ession of the Control Room evacuation fire. Controlof AFW from the HSDP is modeled for at CR fires. 18 Relay and Cable Spreading Rm.. All equipment not controlled from #11 AFW Pmp 2 07E-2 3 03E-6 9.17E-7 < 1 E-8 3.94E-6 Credit for auto Units 1 & 2 the HSDP failed for fires that are #12 CHG Pmp suppression of the not suppressed fire.Controlof AFW from the HSDP is  ! modeled 20 Unit 14KV Safeguards Swgr,(Bus MFW/COND, #12 St Pmp, #12 CS #11,21 AFW 2.04E-3 5.70E-7 < 1E-8 4.1 M-7 9.78E-7

16) Pmp, #2DG, #12 CC Pmp, #12 #11 CC AFW, #11/13 CHG Pmps, #12 CHG

                                       #11/22/121 CL Pmp, #12 RHR                             #11 St Pmp, #122 IAC                                          #21/12 CL 22   480V Safeguards Swgr,(Bus 121) #122 IAC, #11/13 CHG Pmps,                              #11 AFW Pmp         2.09E-3        8.05E4        3.55E-8   8 02E-7                      8.90E-6                                       1
                                       #12/22 AFW Pmps, #21/22 CL                             #12 CHG Pmp Pmp                                                    811/12 CC Pmp
                                                                                              #11/12 CL
                                                                                              #11.12 SI 31   "A" Train Hot S/D Panet & Air   #12/22 AFW Pmps, tA, MFW, #22 #11 AFWPmp                                    1.52E-3        1.82E-6       < 1E-8   < 1E-8                       1.82E-6       Auto suppression Comp /AFW Room                  CL Pmp, CHG4ul Pmp, Service                            #11/13 CHG Pmp                                                                                        assumed to prevent Air                                                    #11/12 CC                                                                                             fire spread to entre
                                                                                              #11/12/121/21 CC                                                                                      area. Manual action to crosstie service air is assumed to allow continued operaton of MFW.

32 *B* Train Hot S/D Panei & Air IA, #11 CC Pmp, #11/21 AFW MFW i 61E-3 1.11E-7 < 1E-8 2.14E-6 2.25E4 Auto-suppression Comp /AFW Room Pmps. SI-Alt, #11 RHR Pmp, #12 AFW assumed to prevent

                                       #11/12 CL Pmps. CHG Makeup,                            #12 CC                                                                                                fire spread to entre Bus 15, #12 Si                                         #21/22/121 CL                                                                                         area.

Servia Air , 34 Battery Room 12 #12 Battery, #12 CC Pmp, #12 #11 Battery 1.18E-3 1.26E-7 < 1E-8 < 1E-8 1.33E-7 AFW Pmp, #12 RHR Pmp, #12 St #11 CC Pmp Pmp, #123 LAC, #12 AFWPmp i

                                                                                              #12 S1 Pmp 36    Battery Room 22                Bus 23, DG #6, CL Pmp #21,                                                  1.13E-3       5.72E-8        < 1E-8   2.83E-7                      3.46E-7 Battery 22 37    Unit 1480V Normal Swgr. (Bus   CL Pmps #11/12, A-MFW, Bus 13,                                             2.10E-3        3.28E-8        < IE-8   5.04E-7                      5.38E-7 150,160)                       Bus 150/160 I

B-64

C O . Table B.2.11.1 (continued) Prairie Island Plant Response to Aren-Specific Fires Area Area TraWFunct6on Fa60ed by Five TreWFunction Ignttien Trans6ent Transient SLOCA Total Comments Number Description Available Freq. (TEH) (TLH) (SEN) COF , 38 Unit 2 480V Normal Swgr, (Bus CL Pmps #21/22, Bus 250/260, 2.10E-3 <1E-8 < 1E-8 1.14E-7 1,16E-7  ! 250.260) Bus 23 58 Aux Building Ground Floor Unit 1 8-MFW, #123 IAC, St-All, CHG- CC Pmp 812 1.03E-2 2.08E-6 < 1E-8 2.57E-5 2.78E4 Indudes operator AB, CC Pump 811, RHR4 CC Xte from U2 action to x-tie CC 11,12,21 AFW from Unit 2. i Separation assumed  ; to predude fire spread to MCC1K1, F're spread across l FA 58/73 boundary assumed not ' l credible B59 Aux Building Mezzamne Floor Urut #11 AFW(Steam Suppfy), #12 CC MFW 9 41E-3 1.05E-7 < 1E-8 6.94E-7 7.95E-7 Control catWes for 1 (FA 59,84) Pmp, #11113 CHG Pumps, #12-SI, #12/21 AFW MV-32060 assumed

                                                                   #12-RHR                                                                                811 CC                                                                                      to be unaffected by                               l 812 CHG                                                                                     the fire.                                         ;
                                                                                                                                                          #11 St B69        Turbine Buriding Geound & Mezz     MFW/COND, #11 AFW Pump,                                                                812/21 AFW        1.94E-2  4.88E-6      1.35E-6                            1.88E-7  6.44E-6 Floor Uait 1 (FA 05,08,14,21,27, #11/12/22 CL Pmp,811/13 CHG 812 CHG 57,94)                             Pmps, 812-St. #12-RHR                                                                  8121/21 CL sit Si 870        Turtune Butid:ng Ground & Mezz     #22 AFW Pmp, Bus 26                                                                    #11/12/21 AFW     1.66E-2  3.14E-8      < 1E-8                             1.51E-7  1.82E-7                                                    ,

Floor Unit 2 (FA 07,08,23,90) #11/12 CC  ; t

                                                                                                                                                          #11/12/13 CHG
                                                                                                                                                          #11/12 St 73      Aux Building Ground Floor Unit 2   # 21 AFW Pmp, #12 CC Pmp,                                                                                2.53E-2  1.58E-7      < 1E-8                             1.01 E-7 2.59E-7
                                                                 . #123 IAC
                                                                                                                                                                                                  < 1E-8                                      2 93E-6                                                   I 80      480V Safeguards Swgr Room          MFW, Bus 111, lA, #21 AFW, #12 811/12 AFW                                                               2.09E-3   4.32E-7                                         2.51 E-6 (Bus 111)                          CHG, #12 CL                                                                            #11/13 CHG
                                                                                                                                                          #11/12 CC                                                                                                                                      ,
                                                                                                                                                          #11/12 SI 81      4KV Safeguards Swgr Room (Bus Bus 15, #11 RHR Pmp, #11 CC                                                                 #11/12/21 AFW     2.03E-3   < 1E-8      < 1E-8                             3.66E-6  3.67E-6

15) Pmp, #121 IAC, #11 St Pmp, #12 CC MfW/COND,812 CL, CHG-AB #11/22/121/21 CL 812 St CDF 2.26E-5 3.23E-6 3.73E-5 6.32E-5 TOTAL B-65

__ _ _. _ . _ _ . . _ _ . _ _ _ _ _ _ _ - _ _ _ - - _ - - - _ _ _ _ _ _ _ _ _ _ _ - _ - - _ _ _ _ _ _ - _ - - - - _ _ - - _ _ - _ _ _ _ - _ - - _ = - _ _ - - _ _ _ _

H.2.11.3 Unit 2 Considerations l The preceding analysis focused on generating insights regarding the effects of a fire on Unit 1 of  ! the Prairie Island Generating Plant. For reasons that are outlined in this section, similar quantitative results and insights would be expected for Unit 2. 1 Sharedand CrosstiedSystems A number of systems at Prairie Island are common to both units in that they are either shared or can be crosstied to support important safety functions in either unit. The logic modeling for the , Prairie Island Unit I fire PRA includes credit for specific Unit 2 systems as a result. For example, the following systems are common to both Units 1 and 2. Fires affecting the operation of these systems would be expected to have similar effects on both units.

• Cooling Water

             . Instrument Air e     Safeguards Chilled Water Systems which can be crosstied between units in the event of random failures or failures resulting from a fire that were credited in the fire PRA include:

Auxiliary Feedwater )

• 4
• AC Power .

• Component Cooling 4

Because of these shared and crosstied systems, many of the rooms containing Unit 2 equipment have been evaluated as a part of the Unit I fire analysis. SymmetricalSystems I A number of the systems that cannot be crosstied are safety systems that are generally

symmetrical between units both in terms of function as well as location. Examples of these types of systems important to the outcome of the fire PRA include

• Charging e Safety injection

e Component Cooling (also a crosstied system)

• DC Power Where these systems are symetrical between units, the effects of a fire in Unit 2 would be l expected to be similar to Unit 1.

d B-66

t 3 Application of Unit 1 Results to Unit 2  ; l To estimate the effect that fires may have on Unit 2, a two step review was performed. The first step examined the dominant area from the Unit I fire PRA to determine if that area would also be expected to dominate the results for Unit 2. The second step was to identify any potentially significant asymmetries between the two plants that may have a significant impact on the ! quantitative results.

• Dominant Fire Area Review The most significant fire area in the Unit I fire PRA is the Auxiliary Building Ground  ;

Floor (Area 58). This area constitutes over 40% of the total estimated core damage frequency due to fires for Prairie Island. The corresponding area in Unit 2 is Area 73. As noted in Table B.2.1.1, the fire loading is very similar for both areas. Equipment located in area 73 includes both SI pumps, all three charging pumps, both trains of RilR as well as component cooling, similar to Unit

1. Both trains of Auxiliary Feedwater are available to provided secondary cooling. As a result, a reactor coolant pump seal LOCA would be the dominant contributor to core I damage for Unit 2 as identified in the Unit I analysis. Power and control cables for a train of component cooling are protected to provide adequate seal cooling. An important operator action to reduce the potential for seal LOCA would be to crosstie a train of O Component Cooling from Unit 1.

Given the similarity between Unit 1 and Unit 2 Auxiliary Building Ground Floors, the risk associated with a fire in Area 73 is expected to be dominant for Unit 2 as it was for Area 58 in Unit 1.

• Potentially Significant Asymmetries As a result of recent modifications resulting in the installation of two new diesel l generators, the most significant asymmetries which exist between Unit I and 2 are associated with the operation and layout of the AC distribution system. The following summarizes the differences between the two units in this regard.  ;

1 The new Unit 2 emergency diesel generators are air cooled whereas the original diesels now tied to Unit I require cooling supplied from the Cooling Water System. This asymmetry would have little effect on the outcome of a fire PRA as no fire area is expected to result in a loss of offsite power sources. The emergency buses for Unit 2 (Buses 25 and 26) are located in fire areas that are not separated by fire barriers from the diesel generators themselves. The diesel generators and emergency buses for Unit 1 (Buses 15 and 16) are in separate fire areas. The effect of this location difference is to increase the frequency of fires that may affect the l' , emergency buses in Unit 2. Table B.2.6.3 shows the frequency of fires in areas that could affect Unit 2 4ky switchgear (for example, Train A areas include 101,103,105,107,109, B-67 l

l l l n 111,115,117,123 and 127). At 1.7E-2/yr, the combined fire frequency for these areas is U roughly an order of magnitude greater than that for Unit 14ky switchgear (Train A Area 81,2.0E-3/yr). The 121 cooling water pump is powered from 4kV Bus 27, which can be supplied from 4kVBus 25 or Bus 26 through local manual operator action. It is nonnally powered from 4kV Bus 25. As a result, a fire in Unit 2 affecting Train A AC power (and to a lesser extent, a fire in Unit 2 affecting Train B AC power) can also affect the operation of this cooling water pump. 1 The fuel supply for diesel pumps 12 and 22 are modeled as being dependent on Unit 1 AC power only. In addition, screenhouse ventilation for the diesel pumps as well as motor driven pump 121 is dependent on Unit I safeguards AC (in fact, a manual transfer exists for these functions to Unit 2 that was not credited in the Unit I analysis). Given this conservative modeling, the diesel cooling water pumps are not affected by fires a.ssociated with either of the two trains of AC power in Unit 2. I As noted above, the first asymmetry has little effect on the risk associated with fires as the potential for a loss of offsite power at the time of a fire is small. l The second and third asymmetries would have the impact of raising the risk of a fire in a p Unit 2 train of AC power over that quantified for Unit 1 if only for the larger frequency of V fires in areas containing important Unit 2 switchgear. However, the last item, the independence of the operation of the two diesel cooling water pumps from Unit 2 AC power, offsets any increase in Unit 2 switchgear fires. Recall from the discussion of Unit I fire area 81 (4kv switchgear - Bus 15) that the fuel pump for diesel cooling water pump 12 is ultimately dependent on Train A AC power. Screenhouse ventillation for the two diesel cooling water pumps and pump 121 are also dependent on AC power. Therefore, loss of a train of Unit 1 AC as a result of a fire combined with the random failure of two cooling water pumps leaves only one cooling water pump available. As the success criteria for the Cooling Water System requires two pumps, it is assumed that the Cooling Water function is lost given these failures. Without Cooling Water, Component Cooling and instrument air eventually are assumed to fail. As instrument air supports normal makeup to the volume control tank, charging is assumed to be lost as well, leading to a reactor coolant pump seal LOCA. This dependency of three cooling water pumps on Unit I emergency power does not exist in Unit 2. Additional random failures of cooling water pumps and charging would be required before a seal LOCA would be possible. Even with the larger potentici for fires in the emergency trains of AC power, the frequency of core damage due to postulated fires in Unit 2 are expected to be similar to or possibly less than that for Unit 1. ( B-68

A) i L.) Analysis of Containment Performance H.2.12 As indicated in NUREG-1407, the focus of the fire IPEEE containment evaluation is to identify any severe accident issues unique to fire events that may involve early failure ofimportant containment functions. The scope of this containment analysis is based on a review of the Level 2 analysis in the internal events PRA. The focus of the evaluation was to identify any potential early containment failure modes unique to fire events that had not already been evaluated as a part of the intemal events PRA. The NUREG-1407 guidance requires an evaluation of any fire-induced containment failures and other containment performance insights. Particularly, it should consider vulnerabilities found in the systems and functions which could lead to early containment failure or which may result in high consequences. These include containment isolation, bypass, and integrity, and systems required to prevent early failure. The conclusion of this review was that the types of challenges to containment are similar to that evaluated in the intemal events PRA. No new or unusual means of challenging the containment were identified as a part of the IPEEE. B.2.12.1 Containment Structures and Systems A fire assessment was performed to identify any vulnerability that could lead to early failure of containment functions. The structures, systems, and components needed to ensure containment integrity, containment isolation, and prevention of bypass were reviewed. j i The containments at Prairie Island are large dry concrete structures. The combustibles located in the containment consist of cable insulation, RCP lube oil and charcoal filter media. Because the l containment contains few ignition sources and much of the combustible material is enclosed, a significant fire within each containment is not expected to occur. The spaces surrounding the containment also contain very little combustible material or have suppression systems that will limit the size of a fire. The screening criteria used in the FIVE methodology indicates that a significant fire in these areas is therefore not likely. The same methodology also indicates that fire spread between these areas is not credible. Therefore, because any fire in the spaces adjoining the containment will be contained within a single area and will be oflimited duration and intensity, structural damage to the contaiament is not expected. To help focus the analysis on containment penetrations that may contribute to a release, the following screening criteria were used to eliminate some penetrations from further consideration:

     . Penetrations of open containment or reactor systems: if the system is not open to the containment atmosphere or the reactor, the probability of simultaneous failure of the isolation valve (s) in the system and a pipe break is considered negligibly small.

[')

• Pipes with diameters less than or equal to 2 inches: aerosol plugging is considered likely to b minimize the amount ofleakage that could occur from these penetrations.

B-69

l p e llatches and airlocks: these items are closed during operations as part of technical V specification requirements and are opened only for monthly inspections of containment.

     . Normally closed lines: lines containing normally locked closed valves, or lines containing closed valves that would not be expected to open during the course of an accident do not contribute significantly to containment isolation failure.

Nine penetrations did not meet the screening criteria identified above. A description of the piping configurations and the failures required to bypass containment for each of these remaining penetrations are discussed below: CVCS lines (Penetrations 11 and 12) The CVCS letdown penetration includes a normally open AOV in parallel with two normally closed AOVs, which together provide a range of flow control options. A single, normally open AOV located downstream can isolate all three parallel valves. Another line containing a normally closed MOV (MV-32234) joins the letdown line downstream of the three parallel valves. For isolation failure either the MOV must spuriously open, or both of the open AOVs must fail to close an J remain closed. The CVCS charging pene: ration includes two check valves, a normally open AOV, and a normally open manual valve in series. The AOV does not receive an isolation signal. For isolation failure, both check valves must fail to close and remain closed. (v) e RCP Seal cooling lines (Penetrations 13A and B) These two lines each contain a check valve and a normally open manual valve. For isolation failure, the check valve must fail to close and remain closed. Instrument Air line (Penetration 20) This line includes two normally open AOVs in series. For isolation failure, both AOVs must fail to close and remain closed. However, two considerations effectively result in a relatively insignificant contribution for this penetration. First, the air system is effectively a closed system within containment, only subject to back-leakage through the valve operators. Second, no failure should be considered while this line is pressurized with instrument air.

     . Containment Sump A Discharge (Penetration 26)                                                   l This line includes two normally open AOVs in series. For failure, both valves must fail to close and remain closed for the mission duration.
     . Containment Vacuum Breakers (Penetrations 41 A and B)

Each containment vacuum breaker line contains a normally open air-operated valve and an q(j air-assist check valve (i.e., Instrument Air holds the check valve open). Failure results if both the AOV and the check valve in either line fail to close and remain closed. ! B-70 l

I 1 p = Makeup to Pressurizer Relief Tank (Penetration 45)

                                                                                                          )

\"I \ This line contains a normally open air-operated valve in series with a check valve. Failure for this penetration involves failure of the AOV to close and remain closed, coupled with i failure of the check valve to remain closed. Fires can affect containment isolation valves in several ways: (1) failure of power cables or failure of motive power to solenoid-operated valves or air to air-operated valves will cause the valve to fail closed; (2) hot shorts in control cables to air-operated or solenoid-operated valves I could possibly cause inadvertent valve opening; (3) failure of power cables to a motor-operated valve will fail the valve in its current position; and (4) hot shorts of control or power cables to a motor-operated valve could potentially result in a change of the valve's position.110 wever, as discussed below, these failure modes are not expected to result in containment failure or bypass:

1. With one exception, the active valves associated with the unscreened penetrations are air-operated valves. These valves fail closed on a loss of air or power. Although extremely unlikely, if a hot short in one of these valve circuits were to occur that did not fail the protective fuse, manual recovery by removing fuses in the affected circuit would cause the valve to fait closed.

2. Similar to the control circuits on air-operated valves, it is extremely unlikely that a hot short p in motor-operated valve control circuits could occur without first failing the circuitry required d to reposition the valve or actuating the circuit's protective features, such as fuses.

Additionally, control valve CV-31325 is in series with the MOV (MV-32234) in question. Much of the control cable associated with CV-31325 is in the vicinity of the cables i associated with MV-32234. It is likely that a fire that would impact MV-32234 cabling would also damage cabling associated with CV-31325 causing it to fail closed. Finally, the fire areas where the majority of this cable is located (fire areas 59,60) have a relatively low 1 area core damage frequency. For the reasons discussed above, fire-induced degradation of containment performance is expected to be negligible. There were no unique containment failure modes identified during the fire IPEEE analysis that differ from those identified in the internal events PRA. I H.2.12.2 Containment Systems Systems important to maintaining containment integrity after a core damage event also were identified in the Prairie Island intemal events PRA. A summary of these systems and the functions that they provide follows: Containment Isolation Isolation Valves O V Debris Cooling (in-vessel and Ex-vessel) Iligh liead SI Low Ilead SI B-71

I Containment Spray Containment Pressure Control RHR (aligned for high head or containment spray recirculation) Fan Coil Units Radioactive Release Control Containment Spray Fan Coil Units The components in many of these systems were included as a part of the Level 1 analysis performed for the Fire PRA. In evaluating containment performance following a fire, any system or component which must be disabled in order to reach core damage was not credited as a means of avoiding containment failure. Table B.2.12-1 summarizes the systems which would be available to provide functions j such as debris cooling and containment heat removal. ' The accident sequence types defined in the internal events PRA are presented below. Each discussion supports the conclusions that (1) the majority of systems important to containment performance under severe accident conditions were considered as a part of the Level 1 analysis,  ! and (2) the containment response to core damage following a seismic event is similar to that I analyzed in the internal events PRA. f} G l Containment Response Three accident classes or accident sequence types dominate the results of the Fire PRA and are a subset of those included in the internal events PRA. These include: TEH Transients (non-LOCA) in which core damage occurs at high reactor pressure without high head injection TLH Transients (non-LOCA) in which core damage occurs at high reactor pressure without high head recirculation l l SEH LOCAs in which core damage occurs at high reactor pressure without high I head injection Transient Initiator at High Reactor Pressure Without Injection (Accident Class TEH) For this accident class, core damage is assumed to occur as a result of the loss of secondary heat removal and high pressure injection in the bleed and feed mode. The primary system is intact for these types of accident sequences as the fire has not led to to sufficient failures that a loss of RCP seal cooling would occur. Should high head safety injection not be restored before core debris j melts through the lower vessel head, then the reactor would depressurize when the lower head is I breached. The response of containment at this stage of the accident is dependent on the Dre-induced and random failures that have occurred. B-72

1 l q For all but one fire area, initiation ofinjection systems would occur in the form of SI, RHR, or b containment spray, or a combination of the three. The depressurization of the reactor on lower  : head penetration, the rise in containment pressure or manual initiation would result in RWST water being provided to the debris in the containment. These are the same systems available to provide debris cooling that were considered in the internal events PRA. Short-term challenges to containn'ent include Direct Containment Heating (DCH), hydrogen combustion and steam explosions. The potential for containment failure due to these challenges was evaluated in the internal events PRA and was found to be low. The potential for and magnitude of these early challenges is not affected by any of the fire initiators. The one fire area that would not necessarily result in RWST water being transferred to j containment is the Auxiliary Building Ground Floor (Fire Area 58) as both trains of SI, RHR and i containment spray are located in this area. The impact of the loss of these systems is on the potential for slowly evolving containment challenges, such as overpressurization or basemat penetration, as described below. The loss of these systems does not lead to any new early containment failure modes as a result. For long-term debris cooling and containment pressure control, with one exception, sufficient systems are available to accomplish these functions. The one fire area that is again the exception is the Auxiliary Building Ground Floor containing all SI, RHR and Containment Spray pumps. n Although Fan Coolers are available for long-term heat removal for this area, the lack of RWST k,) inventory in the containment is assumed to leave debris uncovered, resulting in long-term  ; pressurization of containment due to noncondensible gas generation from concrete interaction. l This, however, is a slowly evolving containment challenge no different than identified in the internal events PRA that would take on the order of a day or more to challenge containment to its ultimate capacity. Transient initiator at High Reactor Pressure Without Recirculation (Accident Class TLH) This accident class is similar to the previous one in that secondary heat removal is lost. Bleed and feed operation is successful in providing short-term core cooling. Core damage is assumed to result from failure to successfully align recirculation. Because of bleed and feed operation, the contents of the RWST have been successfully transferred to containment at the time of core damage. The volume of water in the primary system combined with the RWST inventory results in the submergence of the lower vessel head. As long as condensation of steam continues and the water is returned to the reactor cavity, it is likely that core melt progression can be terminated within the vessel. The early challenges to containment for this accident class are a subset of those that are postulated for Class TEH due to the potential for preventing transport of the core debris into containment. These early challenges are similar to those defined in the intemal events PRA for this accident class. l [^\ j Q For each of the dominant fire areas in this accident class, several modes of containment heat ! removal are available. These include fan coolers as well as containment spray recirculation. B-73

rs RilR recirculation is also available should lower head penetration occur, resulting in the ( depressurization of the reactor. Due to the availability oflong-term decay heat removal sytems,  ! there is little potential for long-term overpressure challenge of containment. l Seal LOCAs Without Safety Injection (Accident Class SEH) l The fire initiators that dominate this accident class are those in which equipment damaged as a j result of the fire affects the operation of one or more trains of component cooling and charging. The affected equipment can include support systems such as electrical distribution and cooling water. The dominant fire area in this accident class is assumed to result in failures ofinjection ; systems in addition to seal cooling (Auxiliary Building Ground Floor). This accident sequence l would result in a high pressure melt ejection without RWST water. Short-term challenges to i containment would include DCil, hydrogen combustion and steam explosions. As noted before, I the magnitude of containment challenge for these phenomena was evaluated in the internal j events PRA and found to have limited consequences on containment.

                                                                                                    )

l The remaining two areas that dominate this accident class include Train A 4kV and 480V l switchgear. SI is assumed to fail as a result of a combination of fire damage as well as random j failures. However, on vessel penetration and depressurization, RHR and containment spray are available to provide short-tenn debris cooling. Similar to the Aux Building Ground Floor, the short-term challenges to containment include DCH, hydrogen combustion and steam explosions, O d which were evaluated as a part of the internal events PRA. , Long-term challenges for this accident class are dominated by gradual pressurization of containment from steam or noncondensible gas generation. No new challenges to containment are identified that were not previously evaluated as a part of the intemal events PRA. fm O B-74

                                                                                            -                                                                      s Teble B.2.12-1               Prairie Island Fire IPEEE Level I to Level 2 Dependencies Fire Area                           Secondary Cooling                     Detels Cooling                               Containment Centrol injection                       Recircolation AFW            MFW  SI   RilR        CS 3          SI     RilR        CS       RHR        RCil         Cs 3 Recire   Recire      Recire Class Illi
                                                                              /     /          /           v5        g5        v5        y           y          v5 Control Room (13)I                                   -             -

i Relay Room (IR)I - - / / / #5 #5 g5 y y g5 480V Swgr-Bus 121 (22) - - - / / ~ / / / / / AFW/ Air Comp (31) - - / / / / / / / / / Aus Bldg Ground Floor (58) - - - - - - - - - / - TB Ground & Mez (69) - - - / / - - / / / / Class 1Lil 4 4 # - #6 g6 g6 y g6 Control Room (13)2 - - Relay Room (18)2 _ _ 4 4 f _ g6 f6 g6 f g6 4 4 / - ,6 g6 g6 y g6 TB Ground & Mer (69) - - Class Sell Aus Bldg Ground Floor (58) / -7 - - - - - - - / - 480V Swgr-Bus ill (80) / -7 -7 / / - - - - -7 - 4kV Swgr-Bus 15 (81) / -7 -7 / / - - - - -7 -

 # Available post-core damage.
 - Failed as a part of Level I accident sequences (random or fire related).

I Dominated by unsuccessful fire suppression. 2 Fire successfully suppressed. 3 Containment spray recire is available but not proceduralized. 4 Succeded as part oflxvel I accident sequences. 5 Must be aligned locally. 6 Provided the reason for recirculation failure was not RilR. 7 Random failures in Cooling Water are required in addition to Frre damage. B-75

B.2.13 Treatment of Fire Risk Sconine Study Issues NRC Generic Letter 88/20, Supplement 4 lists the following fire risk scoping study issues to be addressed in IPEEE fire analyses:

1. Seismic /fireinteractions,

2. Fire barrier assessment,

3. ElTectiveness of manual fire fighting,

4. Effects of fire suppressants on safety equipment (total environment equipment survival), and

5. Control systems interactions.

The specific concerns regarding each of these issues are discussed in the FIVE methodology. This methodology was used as guidance for evaluating each of the issues. Where appropriate, relevant fire risk scoping study issues have been incorporated into other phases of this study, such as the area screening and the detailed fire scenario evaluation. Review of the fire risk scoping study issues resulted in the conclusion that these issues are not significant contributors to fire-induced core damage at Prairie Island. The evaluation of each fire risk scoping study issue is discussed below. B.2.13.1 Seismic / Fire Interactions This issue involves three concerns: seismically induced fires, seismically induced actuation of fire protection systems, and seismically induced degradation of fire suppression systems. Seismically Induced Fires in general, carthquakes are not known to cause fires in industrial facilities [12). However, the potential failure of vessels containing flammable or combustible liquids or gases could cause a fire hazard in the plant following an earthquake. As a part of the seismic walkdowns, a survey of tanks and vessels that may contain flammable fluids was performed. Day tanks for the diesel generators and diesel cooling water pumps were found to be adequate in the seismic 1PEEE (see Appendix A of the IPEEE report). The fire areas containing flammable liquids that were not seismically screened are: O B-76 1 I

Fire Area Description Flammable Gas or Liquid 8 Turbine Deck H2 T/G Oil 24 Admin Building Oil Storage T/G Oil 41B Screenhouse Basement Diesel Fire pump fuel oil , day tank 57 Gas House H2Bottles 69 Turbine Building Ground & Mezzanine T/G Oil, T/G H2 Floor, Unit 1 l 70 Turbine Building Ground & Mezzanine T/G Oil, T/G H2 Floor, Unit 2 Of these, the fire evaluations indicate that only Areas 69 and 70 are of concern if a fire occurs in those areas. The other areas contain little or no safe shutdown equipment, and substantial equipment will remain unaffected by the fire to enable shutdown. For Fire Areas 69 and 70, the seismic / fire interaction was evaluated by assuming that a seismic event occurs of sufficient magnitude to result in a loss of ofTsite power. In addition, it is p assumed for evaluation purposes that a fire starts (the combustible material is the flammable gas

 \- or liquid) and spreads without being suppressed. Each of these areas is a part of a burn sequence (Burn Sequences 69 and 70), comprised of other fire areas in addition to the area containing the flammable gas / liquid (see Table B.2.6.3). Thus, under the assumptions being employed,it is possible for equipment not located specifically in Fire Area 69 or 70 to be disabled by the fire.

For Burn Sequence 69 (starting in Fire Area 69), the combination of an unsuppressed fire and a loss of offsite power (LOOP) results in failures of:

             *   #11 AFW pump (fire)
             *   #11 CL pump (fire and/or LOOP)
             .   #12 CL pump (ventilation / air damper #11 failure due to fire)
             .   #21 CL pump (LOOP-Bus 23)
             .   #22 CL pump (ventilation / air damper #21 failure due to fire)                           l e                                                                                            '
                 #11 and #13 CVCS pumps (#11 pump cable, #13 pump cable, #1K2 bus)
             . Train B SI(due to loss of CL pumps)

Remaining equipment unaffected by the fire or LOOP event includes: . 1 e #12 AFW pump

• Ability to crosstie to #21 AFW pump e #121 CL pump O e #12 CVCS pump

             +   Train A SI B-77

O The amount of equipment still available is sufficient for safe shutdown in response to the combined seismic / fire event. If a small LOCA also occurs, an SI pmnp would be available as noted above. For Bum Sequence 70 (initiated in Fire Area 70), the LOCA/ unsuppressed fire combination results in failures of:

             *   #11 CL pump (LOOP) e   #21 CL pump (LOOP)
             . D6 DG Remaining equipment unaffected by the fire or LOOP event includes:
             . D5DG e   All AFW pumps (including the crosstie from Unit 2)

• CL pumps #121, #122, #22
• Si pumps, both trains e CVCS pumps, all pumps The remaining equipment is sufficient for safe shutdown, LOCA concerns are not important for this sequence due to the availability of SI.

.- Actions not incorporated into this evaluation which could be taken, if necessary, to reduce the (m) potential CDF include:  : 1

             . Credit for suppression (manual fire fighting)
             . Credit for curbs to contain tube oil                                                   i e   Assessment of the potential for ignition given a loss of offsite power                 l

• Additional seismic evaluation of fiammable storage containers (to determine seismic l

ruggedness and reduce conditional failure probability given a seismic event) 1 Seismic Actuation of Fire Suppression Systems l The NRC's information notice 94-12 notes that (1) mercury relays are susceptible to seismic actuation, (2) smoke detectors could be actuated by dust rising during a seismic event, and (3) unprotected essential components could be damaged by spray from deluge systems. Mercury relays and fire suppression equipment actuated by smoke detectors (except for exterior transformer deluge) are not used for fire protection of essential equipment considered in the Prairie Island IPEEE. Of the important plant areas containing essential equipment considered in the seismic IPEEE, only the AFW pump rooms are protected by fire water systems. Loss of essential equipment in these areas due to inadvertent actuation of the fire water system by a seism:c event is considered highly unlikely. Actuation of the system requires failure of the fusible links in the sprinkler I

• heads. No mechanism was identified that could cause failure of these fusible links during a seismic event. Also, as discussed previously (for inadvertent actuation), failure of multiple systems would require the actuation of multiple sprinkler heads.

B-78

i i i p Seismic Decradation of Fire Protection Systems L During an eanhquake, fire suppression systems could disable nearby safe shutdown components either by colliding with them, or by bursting and either spraying or flooding the equipment. Such interactions were investigated as a pan of the seismic walkdowns. Spray or flooding of essential components due to actuation of fire water systems is considered unlikely, as discussed above. No potential for failure of essential equipment due to collision with fire protection systems was identified in the seismic walkdown.  ! 1 H.2.13.2 Fire Barrier Effectiveness Fire barriers are used at Prairie Island to provide physical separation of redundant trains of safe shutdown equipment. Qualification of these barriers must be maintained to ensure an effective fire protection program. A series of detailed barrier inspection procedures are implemented to inspect all fire area boundaries for the express purpose of protecting safe shutdown equipment. Fire barrier inspection procedures require that every square inch of every boundary be inspected, ' including penetration seals and fire dampers. Fire doors are inspected and maintained per procedure. All fire barrier inspections are performed on an eighteen-month interval. In addition to inspection of the fire area boundaries required by Appendix R, certain boundaries are also inspected per previous NRC commitments and/or good fire protection practices. Other ,fq fire barrier concerns such as tire damper operability, as outlined in NRC information notices 83-( ,/ 69 and 89-52, have been resolved with walkdowns or inspections, or by modifying the operating I procedures. This detailed inspection and maintenance program ensures that all fire boundaries are adequate and in good repair. Fire barrier effectiveness is ensured by implementation of these procedures. I i B.2.13.3 Effectiveness of Manual Fire Fighting NUREG/CR-5088," Fire Risk Scoping Evaluation" {l1], identified six components of an effective manual fire fighting program: (1) fire reporting, (2) fire brigade personnel and equipment, (3) fire brigade training, (4) fire brigade practice, (5) fire brigade drills, and (6) record keeping on fire brigade members. NSP's fire fighting procedures, training, and administrative work instructions address all six of these issues. Fire reporting is accomplished with two-way radios carried by the operators and staged with the fire brigade equipment, or via phone lines designated for that purpose. Use and staging of this equipment is detailed in plant procedures. Adequate staffing is considered to consist of six operating shift fire brigades of five people each; three of whose members must be operations personnel. Supporting equipment is prestaged in the fire brigade equipment room and includes personal protective equipment, communications equipment, portable lights and ventilation, etc. p Course work associated with fire brigade training covers subjects ranging from basic principles () of fire chemistry and physics to more advanced subjects including evaluation of fire hazards and fighting fires in confined areas. All fire brigade members receive hands-on fire fighting training B-79

l n at least once per year to provide experience in actual fire extinguishment and the use of U emergency breathing apparatus. Fire brigade drills are performed in the plant so that each fire brigade shift can practice as a team. Backshift drills and unannounced drills are performed for each brigade at least once per year. Detailed training records and periodic quality assurance audits of the fire protection program assess the adequacy of the fire brigade training. Audit reports are kept on file at the plant. Based on an examination of Prairie Island's established fire fighting training program, the attributes of an adequate fire protection program related to manual fire fighting identified in NUREG/CR-5088 are satisfied. The plant's fire brigade and manual fire fighting capability is therefore considered to be effective. Section B.2.8 describes how manual fire fighting is accounted for in this study. B.2.13.4 Total Environment Equipment Survival This issue includes the following three concerns: (a) The potential for adverse effects on plant equipment caused by combustion products released from the fire causing damage to, and possible loss of, safe shutdown ftmetion. (b) The spurious or inadvertent actuation of fire suppression systems resulting in the loss of safe shutdown functions.

   ,o]

L (c) Operator effectiveness in performing manual safe shutdown actions and potentially misdirected suppression effects in smoke-filled environments. With the exception of the Control and Relay Rooms, all fire initiators included in the accident sequence quantification are assumed to spread and engulf the entire sub-area in which they are assumed to occur. Smoke effects on equipment located in these spaces is not an issue because the equipment is assumed to be destroyed by the fire. Equipment in adjoining spaces is unlikely to be damaged because the barriers that prevent the fire spread will, in most cases, also limit smoke propagation. Smoke that does propagate to other spaces will be dissipated. In addition, the FIVE methodology does not currently evaluate non-thermal environmental effects of smoke on equipment because the detrimental effects of smoke on equipment are not believed to be significant. The plant design philosophy is to avoid damage to safe shutdown equipment by inadvertent actuation of the fire protection equipment. Deluge valves that protect safety related equipment are preaction type. The exception to this philosophy is the auxiliary feedwater pump room, l which has a wet pipe system expanded to add sprinkler heads below congested areas. Unit specific pumps are located in separate rooms so that actuation in one room would not affect the redundant train of the same unit. The Fire Detection System provides the Control Room operator

 ,     with status indication of automatically-actuated suppression systems thus permitting appropriate action in the event ofinadvertent actuation. Manual shutoff valves are provided to terminate B-80

l l l 3 system operation. Susceptibility of multiple trains of safe shutdown equipment to spurious ' d actuation of suppression systems is not expected in any case. l 1 l Manual actions to operate equipment outside of the Control Room or HSDPs are not given significant credit in this study. Manual response to fires inside the Control Room is discussed in Section B.2.8. Review of the heating, ventilation, and air conditioning systems determined that sufficient ventilation is available to prevent excessive smoke propagation between systems and structures. Emergency lighting is positioned throughout the plant and self-contained breathing apparatus equipment is also staged at appropriate locations in the plant. This equipment allows the fire fighter to efTectively combat any fire. H.2.13.5 Control Systems Interactions Control system interactions following a fire is principally a concern at facilities without a remote shutdown capability. Installation of the hot shutdown system panels resolved this issue at the Prairie Island station. These panels allow the operators to remotely control at least one train of ' safe shutdown equipment from the auxiliary feedwater pump rooms. I l One of the primary features of these panels is that cables for equipment controlled from this location can be completely isolated from the Control and Relay Rooms. This feature allows remote operation of the equipment regardless of the condition of these rooms. The Prairie Island

  ,   operations manual provides the necessary guidance to control the plant from these panels. In

() addition to the written guidance, all tools and equipment required to implement the actions are staged near the panels. H.2.14 USI A-45 and Other Safety issues The Prairie Island fire IPEEE is an integrated look at core damage risk for internal fires and includes potential impacts from loss of decay heat removal. The IPEEE used a systematic approach to evaluate plant systems and components looking for vulnerabilities during a fire or precipitated by a fire. Inherent to this approach is an evaluation of the potential for loss of decay heat removal capability. NUREG-1289 " Unresolved Safety Issue A-45, Shutdown Decay Heat Removal Requirements", Section 1.1, lists two criteria that must be met by systems that are used to remove decay heat. These criteria are (1) to maintain water inventory to the RCS to ensure adequate cooling to the fuel and (2) to provide the means for transferring decay heat from the reactor coolant system to an ultimate heat sink. With this definition in mind, NSP chose to define DHR as decay heat removal from the reactor core. . There are four possible methods of removing decay heat from the core at Prairie Island. These consist of: l (N 1. Secondary cooling through the steam generators with main feedwater and auxiliary feedwater providing steam generator makeup. B-81

1

2. Bleed and feed cooling utilizing the SI pumps and pressurizer PORVs.

3. Reactor coolant system injection and recirculation as provided by the SI and RHR systems l during medium and large LOCAs. (Note

No fire is postulated that will lead to a medium or j; large LOCA. A medium or large LOCA occurring simultaneously with a fire is considered

{ probabilistically insignificant.) _

4. Shutdown cooling mode of RHR operation after the reactor coolant system has been cooled

{ down and depressurized to RHR shutdown cooling conditions.

Secondary cooling through the steam generators is the preferred means of removing decay heat j during normal shutdown until reactor pressure drops to the point where RHR shutdown cooling

. can be placed in service. Steam relief was not modeled for the Prairie Island IPEEE because of j the many diverse means of steam removal. Because of the many and diverse means of steam , relief, it was assumed that loss of steam generator cooling would be dominated by loss of j makeup capability. There are two means of makeup to the SGs that were modeled in the Prairie j Island fire IPEEE; auxiliary feedwater (AFW) and main feedwater (MFW).

Ifsecondary cooling is unavailable, bleed and feed cooling utilizing the SI pumps and pressurizer

{ PORVs is directed. To perform decay heat removal via bleed and feed, the operators inject cool j- water to the reactor coolant system with the SI system and remove hot water from the reactor j coolant system through the pressurizer PORVs. SI injection in this mode maintains adequate reactor coolant system inventory as well as provides decay heat removal. The shutdown cooling mode of RHR operation is initiated after the RCS has been cooled down and depressurized to RHR shutdown cooling conditions. In this mode of operation, the RHR pumps draw suction from the Loop A and B hot legs and discharge the coolant through the RHR heat exchangers and back to the RCS Loop B cold leg. The heat load of the coolant is transferred to the component cooling water system from the RHR heat exchangers. The SDC mode of RHR operation can only be entered after the RCS has been cooled and depressurized to 350 F and 425 psig. Given that NSP chose to define DHR as decay heat removal from the reactor core, loss of DHR becomes synonymous with core damage as there are no Level I core damage sequences that do not involve loss of either one or both of the two requirements identified in NUREG-1289. As identified above, there are many redundant and diverse means for DHR at Prairie Island. Multiple DHR systems and operator actions would have to failin combination to have an impact on the DHR capability at Prairie Island. Additionally, there is no area in the plant in which a fire would lead directly to the inability to cool the core. Without additional random equipment failures unrelated to damage caused by the fire, core damage will not occur. With the overall fire induced CDF being an acceptably low level of <7E-5/yr, NSP considers it has fulfilled the requirements of USI A-45 with respect to fire events. O B-82

B.2.15 Results and Conclusions B.2.15.1 Summary of Results The total vulnerability due to fires at Prairie Island is calculated to be less than 7E-5 core damage events per year. These results are summarized by fire area in Table B.2.11.1. More than 95% percent of the plant risk associated with internal fires can be traced to nine rooms / burn sequences. These rooms / burn areas consist of the Auxiliary Building 695' elevation, the 480V safeguards Bus 121 room, the Turbine Building Ground and Mezzanine Floors, the Relay Room, the 4160V safeguards Bus 15 room, the 480V safeguards Bus 111 room, the Trains "A" and "B" Hot Shutdown Panel and Air Compressor /AFW Rooms, and the Control Room. B.2.15.2 Conclusions and Recommendations The results of the fire IPEEE accident sequence quantification were derived using a methodology that includes a number of conservative assumptions. Fires were assumed to spread until they completely engulfed the sub-area in which they started. In addition, with the exception of the main Control Room, the Relay Room, and the auxiliary feedwater pump area, the effects of fire suppression were not credited.No repair actions were applied to any accident sequence even if the equipment was not in the area affected by the fire. Therefore this methodology, while demonstrating relatively low risk due to internal fires, yields conservative core damage frequencies. The relatively low plant risk due to fires is in large part due to Prairie Island's implementation of the requirements of 10CFR50, Appendix R. These requirements, including separation of alternate or redundant trains of safe shutdown equipment, installation of fire barriers, and an installation of an alternate shutdown system outside the Control and Relay Rooms, combine to limit the total risk due to fires. The administratise control of transient combustibles also contributes to the low fire risk. O B-83

1 e a fp B.2.16 Refe_rggert

1. Generic Letter No. 88-20, Supplement 4, " Individual Plant Examination Of External Events

(IPEEE) for Severe Accident Vulnerabilities", United States Nuclear Regulatory i Commission, June 1991.

2. Prairie Island Nuclear Generatine Plant Individual Plant Examination (IPE), NSPLMI-94001, Rev. O, Northern States Power Company, February,1994.

4

3. Safe Shutdown Analysis Engineerine Report - Prairie Island Nuclear Generatine Plant,

) Rev.2, Northern States Power Company, February 1991.

4. Fire Induced Vulnerabilities Evaluation (FIVE) Plant Screenine Guide, EPRI, September j 1991.

4 , 5. NUREG/CR-4527/1 of 2, "An Experimental Investigation ofInternally Ignited Fires In

Nuclear Power Plant Control Cabinets

Part 1: Cabinet Effect Tests," U.S. Nuclear

Regulatory Commission, April 1987.

6. [ DELETED]

1

7. Updated Fire Hazards Analysis - Prairie Island Nuclear Generatine Plant, Rev.7, Northern

                                                                                                                  ]

States Power Company, January 1990. i

8. " Fire Events Database for U.S. Nuclear Power Plants," NSAC-178L, June 1992.

9. Appendix III, Table III 5-3, " Reactor Safety Study: An Assessment of Accident Risks in U.S. Commercial Nuclear Power Plants," WASH-1400,1975. l

10. " Report on Full-Scale Horizontal Cable Tray Fire Tests," FNAL-TM-1549, Fermi National Accelerator Laboratory, September 1989.

11. NUREG/CR-5088, " Fire Risk Scoping Study: Investigation of Nuclear Power Plant Fire Risk, Including Previously Unaddressed Issues," NRC, January 1989.

12. EPRI NP-6041, "A Methodology for Assessment of Nuclear Power Plant Seismic Margin", Rev.1, EPRI, July 1991.

O 1 B-84 l

i O Prairie Island Individual Plant 3xamination of External Events (IPEEE) l Appendix B Internal Fires Analysis l Attaclunent 1 Selected floor plans from the Updated Fire Hazards Analysis Pages: 1 through 4 of Figure 1.1-1 O B-85

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                                                                                           <@,          dd        M'                      i

O i I l Prairie Island } Individual Plant Examination i of External Events (IPEEE) l l NSPLMI-96001 l i O Appendix C Revision 0 Other External Events O C-1

m i - () Table of Contents UST O F TAB LES ... . .. . ... ... . _. . .. . .. _ _ .. .. . . .. .. C-3 LIST O F FIG U RES ......... . . . . .. .. . . ..... . ... ... . . . .... .. . C-3 C.1

SUMMARY

               ..                                            .                                                                                         . C-4 C.l.1 Background..                             .                                           .               .               .         . ..                 .      ..C-4 C.I.2 Plant Familiarization .          . . . . . . .       ..              . . . . .                 .             . .         . . . .         ..        ..      ..C-4 C.I.3 Overall Methodology.. .                    .     .             . .                                                                                         ..C-5 C.I.4 Summary of Major Findings.. .                                            .
                                                                                                                                                                      . ..C-6 C.2 ASSESSMENT OF OTHER EXTERNAL EVENTS FOR PRAIRIE ISLAND.. ......                                                                            .....           .. . C-8 C.2.1 External Events Considered For Prairie Island..                                                                                                           ..C-8 C.2.2 High Winds and Tornadoes..                                                                                                                          ....C-10 D

C2.2.1 fligh Winds.. ,

                                                                                                                                                                .      ..C-10 C2.2.2 Tornadoes.           .
                                                                                                                            .                    .                     ..C-11 C.2.3 External Flooding and Probable Maximum Precipitation..                                                                                             . ..C-15 C2.3.1 ExternalFlooding.                                                                                              .                                    ..C-15 C2.3.2 Probable Afaximum Precipitation..                                                                            .                         .. .. C-17 C.2.4 Transportation and Nearby Facility Accidents..                                      ..                   .                          .                   ..C-19 C2.4.1 Aviation Accidents..                                .    .                                   .                                                      ..C-20   l C2.4.2 Afarine Accidents.                                                                                                                                    C-22   l C2.4.3 Pipeline Accidents..                                                                                   .                                            ..C-23   l C2.4.4 RailroadAccidents..                                                                                                                                 ..C-23   l C.2.4.5 Truck Accidents..                                                                      ..                                                          ..C-25   :

C2.4.6 NearbyIndustrialFacilities.. . .. C-26 C 2.4. 7 Nearby Afilitary Facilities .. ...C-28 C2.4.8 lla:ardous AfaterialReleasesfrom On-Site Storage.. ..C-28 l C.3 C O N C L U S I O N S. .. ........... ............. . .. .... ..... .............. ...... ... .... ... ... . . . ... C-2 9 C.4 RE FE R E N C E S . ...... ................ ........ .. ......... . ....... ........ .... ... .. ......... ....... C-3 3 w C-2

    -_ - . - -               .     .     - .      - .     - - . - .  - - - - .              . .~                        .- . _ . - .

F O List orTables l Table C.1 D5/D6 Building Tomado Generated Missiles... .. .. .. . ..C-13 i Table C.2 Combinations ofD1/D2 Failures and Frequencies . .. . . . ....C-14 l Table C.3 City ofRed Wing MajorIndustry. . . . .. ... C-27 List of Figures i Figure C.1 Flow Chart: IPEEE Screening for External Events Other Than Seismic and Fire ...C-30 Figure C.2 Tomadic Windspeeds Corresponding to a Probability of 10~7 Per Year.. .. ..C-31 4 Figure C.3 Tomadic Windspeeds Corresponding to a Probability of 10 Per Year.. . .. C-32 O l [ t C-3

C.1

SUMMARY

C.1.1 Background The assessment that is described in this appendix addresses the external events other than seismic and internal fires. These "other" external events include phenomena such as high winds, floods, transportation-relatedaccidents and accidents at nearby facilities that could potentially pose a threat to the Prairie Island plant. This assessment is performed using the screening approach suggested in Generic Letter 88-20, Supplement 4 [1], and the accompanying guidance for implementation, NUREG-1407[3]. t C.1.2 Plant Familiarization The Prairie Island Nuclear Generating Plant consists of two units, each employing a 2-loop pressurized water reactor. Northern States Power Company owns and operates the plant. Westinghouse Electric Corporation designed and supplied the nuclear steam supply system Q (NSSS), the initial reactor fuel, and the turbine-generatorunits. Pioneer Service and Engineering (now Fluor Power Services,Inc.) was the architect-engineer for the two units. Northern States , Power Company was the constructor. The plant was constructed, pursuant to Construction Permits CPPR-45 and CPPR-46,in Goodhue County, Minnesota. Construction started on June 26,1968. Initial fuel loading was completed during Fall of 1973 for Unit I and Fall of 1974 for Unit 2. Following a period of testing, full commercial operation began on December 16,1973 for Unit I under facility Operating License Number DPR-42, and on December 21,1974 for Unit 2 under Facility Operating License Number DPR-60. The only significant new construction to occur since operation began was the recent addition of the D5/D6 Building, located adjacent to the Turbine and Auxiliary Buildings on the west side of the plant. The reactor for each unit is capable of an ultimate power output of 1721.4 MWt, and all steam and power conversion equipment, including the turbine-generator, has the capability to generate a maximum calculated gross unit output of 583 MWe. All plant safety systems, including containment and engineered safeguards, were designed and originally evaluated for operation at the maximum power level of1721.4 MWt. Prairie Island was designed prior to the final issuance of the general design criteria for nuclear power plants (10CFR50, Appendix A) and the 1975 Standard Review Plan (NUREG-75/087)[6]. O V Instead, the Prairie Island design followed the proposed Atomic Energy Commission (AEC) C-4

• l 1

l l 4 General Design Criteriapublished in the Federal Register on July 11,1967 (32FR10213). The only exception to this was the recent addition of the D5/D6 Building which was designed as a Class I structure, but to more recent codes and standards. The review documented by this report

considered the more recent criteria, and any significant differences from the General Design Criteria and Standard Review Plan are noted where applicable.

1 C.1.3 Overall Methodology

Generic Letter 88-20 Supplement 4 [1], along with NUREG-1407, " Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident i

Vulnerabilities"[3], provide guidance for a screening technique that can be employed for assessing the potential impact of high winds and tornadoes, external floods, and transportation and nearby facility accidents on the safe operation of the plant. This screening approach was employed for

PrairieIsland.

l Figure C.1 shows a flow chart of this screening approach. The approach consists of the following l steps: i i j l. Reviewing plant-specific hazard data and licensing bases. J

2. Identifying significant changes since the plant operating license was issued.

i ! 3. Detennining if the plant and facilities design meets the 1975 Standard Review Plan (SRP) [6] criteria. 2 i l For the external events of high winds and tornadoes, external floods, and transponation and nearby facility accidents, a review of the SRP was conducted to detennine if the criteria in the SRP are i satisfied by the Prairie Island design bases. Because Prairie Island received its operating license j prior to 1975, when the SRP was issued, it was necessary to review the Prairie Island Updated l Safety Analysis Report (USAR) [14] and subsequently prepared analyses and calculations to make

                                                                                                               ]

this assessment. Ifit was determined that the SRP requirements are satisfied, and a site walkdown  ;

l confirmed that the current plant configurationis in agreement with the plant design bases, then the IPEEE screening criteria was considered satisfied. 1

If the SRP was not satisfied, then additional analyses may be necessary, such as a determination that hazard frequency is sufliciently low, performance of a bounding analysis, or the development i of PRA models to evaluate the specific concerns, i

Using the guidance and recommendationsprovided in Section 2 of NUREG-1407 [3], a number of 1 the external events were determined not to require extensive evaluation due to specific rationale

  )

C-5 I N

o Q (e.g., extremely low frequency, geographical considerations, etc.). These external events are as follows: Lightning Severe Temperature Transients (Extreme Heat and Extreme Cold) Severe Storms (Including Duststorms and Sandstorms) ExtraterrestrialActivity VolcanicActivity Earth Movement (Including Avalanche and Landslide) ExternalFires Section 2.1 of the report addresses those external events not requiring extensive evaluation which are therefore eliminated from further consideration in the IPEEE. Sections 2.2, 2.3, and 2.4, respectively, provide the evaluation of the remaining external events: High Winds and Tornadoes External Flooding and Probable Maximum Precipitation Transportationand Nearby Facility Accidents Also, NUREG-1407 requests that licensees assess Generic Issue 103, " Design for Probable Maximum Precipitation (PMP)". Generic Letter 89-22, " Potential for Increased Roof Loads and (,#) Plant Area Flood Runoff Depth at Licensed Nuclear Power Plants Due to Recent Change in Probable Maximum Precipitation Criteria Developed by the National Weather Service" [2], refers to updated criteria which are to be reviewed by licensees to determine whether on-site flooding or roof ponding due to precipitation could cause a severe accident. Roof ponding is therefore addressed as part of the assessment for flooding, and is included in Section 2.3.2 of this report. C.1.4 Summary of Maior Findines Based upon the evaluations presented in Section C.2 of this report, there is no "other" external event (fire and seismic are examined in separate appendices) that is a safety concern to the Prairie Island Plant. No vulnerabilities were identified, and the screening criteria contained in NUREG-1407 and Generic Letter 88-20, Supplement 4, are satisfied for all events. Because no vulnerabilities were found in this assessment, no changes to plant hardware or procedures are recommended. Most of the external events considered could be readily eliminated from further consideration because they either do not apply to the Prairie Island site, or their impact has been determined to be insignificant. The remaining events (high winds and tornadoes, external flooding and probable maximum precipitation, and transportation and nearby facility accidents) were evaluated in greater detail. C-6

1 O Using the methodology presented in ASCE Paper No. 3269 [20],it was determined that the Prairie i Island design of structures meets the acceptance criteria for high winds stipulated in SRP Section 3.3.1. Tornadoes were evaluated for the three concerns of dynamic forces on structures resulting from the high winds generated, forces on structures from differential (negative) pressure from the tornado, j and impact from missiles generated by the tomado. Using the guidance presented in Reg. Guide 1.76 [8] and ANSI /ANS 2.3-1983 [21), and employing additional deterministic and probabilistic analyses,it was determined that tomadoes do not impact the safe operation of the PINGP. Flooding had been evaluated in the Prairie Island Probable Maximum Flood Study (Appendix F of the PINGP USAR) and it has been determined, using the most conservative assumptions for flood levels and precipitation,that the effects of flooding will not impact the safe operation of the plant. Probable maximum precipitation was evaluated to determine effects on plant risk. Roof drainage was reviewed, including the potential to have ponding as a result of actual roof configuration. A walkdown was performed of the roofs for the Service Building, Auxiliary Building, Radwaste Building, Turbine Building, and D5/D6 Diesel Generator Building. Based on measurements from this walkdown and conservative calcuhtions,it was determined that precipitation and potential ponding do not contribute to plant risk. O Transportation and nearby facility accidents were determined not to significantly contribute to plant l risk. The plant is at least 2 statute miles from a federal airway, holding pattern, or approach pattern, and at least 5 statute miles from the edge of military training routes. It was also concluded that barge and ship traffic on the Mississippi River did not pose a threat to the safe operation of the plant either due to explosion or release of toxic materials. There are no gas pipelines near the plant site. Railroad accidents, on either of the two railroad lines that are in close proximity to the site, were determined not to pose a risk to plant safety. There is only one major highway within 5 statute miles of the plant. Shipment of hazardous material along this highway would be very infrequent. Local industry in the City of Red Wing, the nearest major industrial town, would pose no threat to the safe operation of the PINGP. There are no military facilities within 5 miles of the site. Finally, a toxic chemical study [16] was performed which concluded that accidents from chemical releases from on-site storage would not impact the safe operation of the plant. O C-7

O C.2 ASSESSMENT OF OTHER EXTERNAL EVENTS FOR PRAIRIE PLAND C.2.1 External Events Considered For Prairie Island The following external events were reviewed for their impact on the design bases of the plant and were determined to have no significant impact on core damage frequency, for the specific reasons l noted for each event. They were therefore excluded from further analysis. i Lightning: At Prairie Island, lightning protection exists for the Containment Buildings, Auxiliary Building, Turbine Building, Screenhouse, Cooling Tower Substation, and Plant Substation. The i lightning protection system satisfies NFPA Standard 78-1975 requirements [30]. 1 As stated in NUREG-1407, the primary impact oflightning on nuclear power plants is the loss of  ; offsite power (LOOP). ' A review of plant operating history was performed which identified the following lightning-related j events at PrairieIsland: i n Q. In September,1978, an apparent lightning strike on the 161 kV transmission line ultimately resulted in the loss of two sources of offsite power, leaving only one source of offsite power in l operation [27]. This event occurred at a time when one of the two Diesel Cooling Water Pumps I was out of service for maintenance. However, a second offsite power source was restored before an orderly plant shutdown needed to be accomplished; therefore, neither plant unit was taken to cold  ! shutdown. A transformer was damaged during the event and was subsequentlyreplaced. Due to an apparent lightning strike on the 345 kV transmissionline in July,1980, the Unit 2 main j generator was separated from the grid and one offsite power source was lost [28]. This situation 1 resulted in a subsequent trip of the reactor and the reactor coolant pumps. Natural circulation was established for core cooling for Unit 2 (at the time of the event Unit I was in cold shutdown). Shortly thereafter, another transformer was locked out, leaving only one source of offsite power. The diesel generators successfully started, supplying power to the safeguard buses. Approximately one hour later both offsite sources that were previously lost were restored. In September,1982, an apparent lightning strike on the 345 kV transmission line caused the Unit 2 Main Generator output breakers to open, ultimately causing a Unit 2 trip [29]. The unit was subsequently restarted with no major problems encountered during recovery. No damage to safety related equipment occurred as a result of these three events, and in the case of the plant trips, no system required for safe reactor shutdown failed. C-8

The loss of offsite power is included as part of the internal events IPE, and examination of the vulnerabilities due to this aspect of lightning is therefore already included in the IPE process. Therefore no further analysis of this event is necessary. Severe Temperature Transients (Extreme Heat and Extreme Cold): As stated in NUREG-1407, the effects of severe temperature are usually limited to reducing the capacity of the ultimate heat sink (UHS) and increasing the loss of offsite power (LOOP) frequency. The climatology of j the Prairie Island site locale is such that extreme cold would potentially have more significant effects on plant operation than would extreme heat. Plant piping and equipment located outside of l plant buildings are protected by heat tracing to prevent adverse effects from severe cold. t Furthermore,the capacity reduction of the UHS due to extreme cold would be a slow process that would allow plant operators sufficient time to take proper actions, such as reducing plant power output level or achieving safe shutdown. Also, to preclude the possibility of a reduction in UHS capability, PINGP Operating procedure C25, " Circulating Water System" [24), places the plant

deicing system in operation to prevent the traveling screens from icing up during winter months.

The deicing system is placed in service when Mississippi River water temperatures drop to 40 i degrees F, and the system remains in operation until the river temperatures rise above 40 degrees. } Regarding the effects of a Loss of Offsite Power, the LOOP is included as part of the internal eventsIPE process. { Based on the above considerations,it is concluded that no further analysis for severe temperature transientsis necessary. Severe Storms (includes Ice. Hail. Snowstorms. Duststorms, and Sandstorms): The potential impacts of these events on Prairie Island is the increased potential for a loss of offsite power i (LOOP) event, effect on control room habitability, and effect on the UHS. LOOP is included as part of the internal events IPE. It is extremely unlikely that a duststorm or sandstorm would occur 2 at the Prairie Island site, let alone have an adverse effect on the habitability of the control room. i However, if this did occur, the operators would have sufficient time to don proper breathing apparatus. Any capacity reduction of the UHS due to the impact of these storms would be a slow process which would allow sufficient time for appropriate operator actions (such as reducing plant power output level or achieving safe shutdown). Winds and precipitation resulting from storms are specifically addressed in Sections 2.2 ar * ? 3. Therefore, no further analysis of these events is necessary. l lO c.p 4

i

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External Fires: External fires are fires that take place outside .he site boundary and involve forest, crops, grass or other vegetation. The chance of the fire traveling onto areas of the site containing critical plant equipment is minimal due to the fact that these areas are cleared, having an insignificant number of trees and major foliage. The only potential impacts from an external fire would be LOOP, and smoke and gases entering the control room environment. If a LOOP should occur as a result of an external fire, its impact on plant accident response would be modeled by the PINGP IPE. Smoke and gases degrading control room habitability is deemed extremely unlikely, since insignificant amounts of gases would reach the control room atmosphere. However, if such an event were to occur, plant operators would have sufficient time to take appropriate control room action, such as donning the protective air masks available within the control room if the concentration of smoke begins to increase. Therefore it is concluded that external fires pose no hazard to the PINGP, and they are eliminated from further analysis. Extraterrestrial Activity: Extraterrestrial activity is considered to be natural satellites such as meteors, or artificial satellites that enter the earth's atmosphere from space. As stated in Supplement 2 to NUREG/CR-5042 [5], the probability of such extraterrestrial activity is very low, and therefore this hazard can be dismissed on the basis of the infrequencyof the initiating event. Volcanic Activity: No sources of volcanic activity exist near the Prairie Island site. Therefore, no volcanic activity analysis is necessary. Earth Movement (i.e.. Avalanches. Landslidesh Avalanches are not applicable to any plant in the United States. As discussed in NUREG/CR-5042 [4], the NRC has also deemed that landslides and other large earth movements (other than those caused by seismic events) would have an insignificant impact on all plants. The Prairie Island site is on level ground with slightly rolling hills, having an elevation variance of approximately 35 feet. Therefore it is concluded that earth movements would pose no threat to Prairie Island, and no further analysis of this event is required.  ! G2.2 High Winds and Tornadoes In this section, the effects of high winds and tornadoes are evaluated against the plant design bases. The results of this evaluation are presented below. C.2.2.1 Ifigh Winds The NRC acceptance criteria for high winds is stated in Standard Review Plan Sections 3.3.1 (Wind Loadings). SRP Section 3.3.1 states that ". . . the procedures delineated in either the American Society of Civil Engineers (ASCE) Paper No. 3269, ' Wind Forces on Structures' . . . or in ANSI C C-10

i i - I g 4 tj A58.1-1972,' Building Code Requirements for Minimum Design Loads in Buildings and Other Structures' . . . are acceptable" for addressing wind velocity and effective pressure applied to I exposed surfaces of structures. PINGP USAR Section 12.2.1.3.1, Environmental Loads, states that the design wind speed for Prairie Island is 100 mph. Wind pressure, shape factors, gust factors, and variation of winds with height have all been determined in accordance with the methodology presented in ASCE 3269. Based on the fact that the ASCE 3269 methodology was employed for wind design for plant structures, the Prairie Island design meets the acceptance criteria for high winds stipulated in SRP Section 3.3.1. Additionally,as is demonstrated in Section 2.2.2 of this report, the effect of high winds is bounded by the maximum winds produced by the design basis tornado. Therefore it is concluded that high winds contribute no significant safety risk at the PINGP. C.2.2.2 Tornadoes The potential hazard from tornadoes arises from three concerns: dynamic forces on structures resulting from the high winds; forces on structures resulting from differential (negative) pressure from the tornado; l impact forces from missiles generated from the tornado. The NRC acceptance criteria for tornadoes is given in Standard Review Plan Sections 3.3.2 l (Tornado Loadings), 3.5.1.4 (Missiles Generated by Natural Phenomena), 3.5.2 (Structures, Systems, and Components to be Protected from Externally Generated Missiles), and 3.5.3 (Barrier Design Procedures). Supplementaryguidance is provided in Regulatory Guide 1.76, " Design Basis Tornado for Nuclear Power Plants" [8] and Regulatory Guide 1.117, " Tornado Design Classification"[13]. According to Reg. Guide 1.76, the PINGP site is located in Tornado Region I. The characteristics of a design basis tornado in that region are as follows. , l C.I1

p d Maximum Wind Speed (mph): RotationalSpeed(mph): 360 290 l i Maximum TranslationalSpeed(mph): 70 l Pressure Drop (psi): 3.0 Rate of Pressure Drop (psi /sec): 2.0 l l Section 12.2.1.3.2 of the PINGP USAR, Tornado Loads, states that the tornado loadings used in the i design of PINGP Class I structures (except for the D5/D6 Diesel Generator Building, which is discussed below)are as follows: 1 A differential pressure equal to 3 psi. This pressure is assumed to build up from normal l atmosphericpressurein 3 seconds. l 1 A lateral force caused by a funnel of wind having a peripheral tangential velocity of 300 mph and a forward progression of 60 mph. The design tornado-driven missile was assumed to be equivalent to an airborne 4" x 12" x i 12' plank traveling end-on at 300 mph, or a 4000-pound automobile flying through the air at 50 mph and at not more than 25 feet above ground level. Section 12.2.1.3.2 of the USAR also states that the tornado loadings used in the design of the O D5/D6 Diesel Generator Building, which houses the PINGP Unit 2 Diesel Generators D5 and D6, are as follows: A lateral force cause'd by a funnel of wind having a rotational speed of 290 mph and  ; maximum translationspeed of 70 mph. A pressure drop of 3.0 psi, with the rate of pressure drop being 2.0 psi /sec. The design tornado generated missiles as shown in PINGP USAR Table 12.2-43. The design bases of the PINGP Class I structures (excluding the D5/D6 Diesel Generator Building) is slightly less severe than the criteria stipulated in SRP 3.3.2 with regard to maximum wind speed (300 vs. 360 mph) and rate of pressure drop (1.0 vs. 2.0 psi /sec). However, Figure 3.2-1 of ANSI /ANS-2.3-1983," Standard for Estimating Tornado and Extreme Wind Characteristics at Nuclear Power Sites" [21], indicates that the PINGP is located in a geographical area where the 7 probability of experiencing tornado wind speeds of 320 mph or greater is 10 per year (the ANSI figure is reproduced in this report as Figure C.2). Figure 3.2-2 of that ANSI standard (reproduced in this report as Figure C.3) indicates that the probability of the PINGP cxperiencing tornado wind 4 speeds of 260 mph or greateris 10 per year. Therefore the probability of the PINGP experiencing 4 tomado wind speeds in excess of the design bases value of 300 mph is between 10 and 10 per year. Based on this low probability of occurrence,it is concluded that the PINGP design bases for tornado wind speed is acceptable. C-12

i According to USAR Section 12.2.1.3.2, the design bases for the D5/D6 Diesel Generator Building with regard to tornado wind loadings and tornado generated missiles are: a lateral force caused by a funnel of wind having a rotational speed of 290 mph and a maximum translation speed of 70 mph; l a pressure drop of 3.0 psi with a rate of pressure drop of 2.0 psi /sec; and the design tornado- l generated missiles as shown in US AR Table 12.2-43. Table 12.2-43 is repeated below- l Table C.1 D5/D6 Building Tornado Generated Missiles Missiles Dimension (meters) Mass (kilograms) Velocity (meters /sec)* Wood Plank 0.092 x 0.289 x 3.66 52 83 6 inch Sch 40 Pipe 0.168 Diameterx 4.58 130 52 1 inch SteelRod 0.0254 Diameterx 0.915 4 51 Utility Pole 0.343 Diameterx 10.68 510 55 j 12 inch Sch 40 Pipe 0.32 Diameterx 4.58 340 47 Automobile 5x2xl.3 1810 59

• Velocities are horizontal velocities. For venical velocities,70 percent of the horizontalvelocities shall be used.

These criteria for wind loadings and tornado-generated missiles meet the design requirements specified in Reg. Guide 1.76, SRP 3.3.2, and SRP 3.5.1.4. Therefore the design of the D5/D6 i Diesel Generator Buildingis acceptable. Regarding the PINGP Unit 1 Diesel Generators D1 and D2, the design of the D1 Diesel Generator l room door, as well as portions of the D1 and D2 combustion exhaust piping and HVAC supply  ! ducting, did not explicitly considerprotection from tornadoes. (Portions of the exhaust piping and the IIVAC ducting are located in non-Class I structures and are not tornado-protected; the D1 Diesel Generator room door is not Class I and is not designed to act as a missile barrier.) A probabilistic analysis was performed to determine the ri: k resulting from the potential failure of D1 and D2 Diesel Generators from a tornado [17]. The calculation evaluated the effects of tornado dynamic forces, pressure drop and tornado-generated misciles, as well as the plant response in the event of the failure of both the D1 and D2 Diesel Generators. The calculation identified eleven possible combinations for the failure of Diesel Generators D1 and D2 and estimated a frequency of occurrence for each failure combination. The eleven combinations and their calculated frequencies of occurrence are as follows: C-13

l I Table C.2 - l Combinations of D1/D2 ' Failures and Frequencies Combination Frequency (yr) Both combustion exhaust pipes struck 9.2E-11 D2 exhaustpipe and D1 door struck 5.2E-11 D1 exhaust pipe struck and D2 fails to start / load 5.0E-9 D2 exhaust pipe struck and D1 fails to start / load 1.1 E-8 i HVAC duct and D1 door struck 3.6E-11 HVAC duct and D1 exhaust pipe struck 6.4E-11 HVAC duct and D2 exhaustpipe struck 1.4E-10 i HVAC duct struck and D1 fails to start / load 7.6E-9 HVAC duct struck and D2 fails to start / load 7.6E-9 HVAC duct struck disabling both EDGs <1 E-7' D1 door struck and D2 fails to start / load 2.9E-9

• Note: The probability of the HVAC duct being struck and disabling both EDGs is not quantified but is significantly less than IE-7 since the probability of crushing the duct (resulting in inadequate ventilation flow for one EDG) is necessarily much less than the i overall missile strike probability for the duct.

Based on these results, the calculation concluded that the overall risk from the loss of both the D1 and the D2 Diesel Generators due to tornado missile impact on either the combustion exhaust piping, the HVAC supply ducting, or the D1 Diesel Generator room door, is less than approximately 10 per year, and thereby meets the acceptance criteria provided in Standard Review Plan Section 3.5.1.5, which requires that the probability of site proximity missiles impacting the plant and causing' radiological consequences greater than Part 100 guidelines must be less than approximately10' peryear. The calculation also evaluated the effects due to tornado pressure drop on the D1 and D2 Diesel Generator combustion exhaust piping, HVAC supply ducting and the D1 Diesel Generator room door. For the combustion exhaust piping the calculation concluded that, based on the 3/8" wall C-14

O thickness of the pipe, there would be no effect on the piping integrity as a result of the tornado pressure drop. For the HVAC supply ducting, the calculation concluded that even if the ducting were to fail due to excessive pressure forces, it was not considered credible that the ducting would crush to the extent that its flow area would be significantly restricted. This conclusion is further supported by the existence of vertical supports in the ducting which would resist a collapse of the ducting. For the D1 Diesel Generator room door, the calculation concluded that no hazard to the D1 Diesel Generatoris expected due to failure of the room door, since any failure of the door due to tornado pressure drop would cause the door to be forced away from the D1 Diesel Generator room and into the service buildingarea. The overall conclusion of the calculation was, therefore, that the existing configuration of the D1 and D2 Diesel Generator combustion exhaust piping, HVAC supply ducting, and the D1 Diesel Generator room door, relative to tomado protection,is acceptable. This conclusion is based on the demonstration that these components are either adequately designed to withstand tornado effects or that the probability of a loss of D1 and D2 Diesel Generators due to failure of these components during a tornado is sufficiently low to require no further analysis. Furthermore, the calculation states that, even if D1 and D2 Diesel Generators were unavailable, procedures exist for supplying AC power to Unit I from the Unit 2 D5 and D6 Diesel Generators within 10 minutes of the blackout occurring. Based on the existing design bases of PINGP structures relative to the effects of high winds and (\ tornadoes,it is concluded that tornado events can be eliminated from consideration as being a significant contributor to plant risk. C.2.3 External Floodine and Probable Maximum Precipitation This section of the report consists of assessments for both the external flooding event and the probable maximum precipitation event. The assessment for external flooding is presented in Section 2.3.1. The assessment for probable maximum precipitation, including an assessment for roof ponding,is presented in Section 2.3.2. C.2.3.1 External Flooding The NRC acceptance criteria for external flooding is stated in Standard Review Plan Sections 2.4.2 (Floods),2.4.3 (Probable Maximum Flood on Streams and Rivers),2.4.10 (Flooding Protection Requirements),and 3.4.1 (Flood Protection). Supplementary guidance is provided in Regulatory Guide 1.59, " Design Basis Floods for Nuclear Power Plants" [7] and Regulatory Guide 1.102,

  " Flood Protection for Nuclear Power Plants" [12].

O C-15 i

l O External flooding at the PINGP site would be as a result of a rise in the water level of the Mississippi,the Minnesota,and the St. Croix Rivers, as well as numerous tributaries. According to I estimates by US Army Corps of Engineers, a flood in the vicinity of the site would have a 1000-year occurrence of approximately 693.5 mean sea level (MSL) (1929 Adjustment). i 1 Prairie Island has performed an analysis for determining the Probable Maximum Flood (PMF).  ; This analysis is presented in PINGP USAR Appendix F [15]. In this report, probable maximum

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flood was defined as the hypothetical flood that would result if all the factors that contribute to the generation of the flood (e.g., precipitation rates, soil infiltration and retention rates, spring and summer storm levels, snow fall and snow melt rates, temperature sequences, etc.) were to reach their most critical values concurrently. This probable maximum flood is derived from hydrometeorologicaland hydrological studies and is independent of historical flood frequencies. The study states that the probable maximum discharge at the Prairie Island site has been determined to be 910,300 cubic feet per second (cfs), with a corresponding peak stage of 703.6 feet MSL (1929 adjustment). This is equivalent to 704.1 feet MSL using the 1912 datum mean sea level (as ir. the USAR, this evaluation will use the 1929 datum to ensure consistency). The study has determined that this probable maximum flood condition would reach its maximum level about 12 days after the beginning of high temperatures and would remain above a flood stage of 681.0 feet MSL (1929 adjustment) for about 30 days. The maximum one percent wave height, consistent with the highest significant wave, is estimated to be less than 3.1 feet from trough to crest. Therefore if the conservative assumption is made that run-up equals the approaching wave height, then the maximum waterlevel would be 706.7 feet MSL (1929 adjustment). According to PINGP USAR Section 2.4.3.5, Floods, ". . . the plant is designed such that all areas critical to nuclear safety are protected against the effects of the probable maximum flood and associated maximum wave run-up." The Reactor Buildings, the Auxiliary and Fuel Handling Building, the Turbine Building, and the Class I portion of the Screenhouse Structure are protected against the effects of the probable maximum flood and associated maximum wave run-up to an elevation of 706.7 feet MSL (1929 adjustment). All openings from the plant exterior into these buildings below the maximum flood level are protected by flood barriers (stop logs). The base slabs of these structures have been designed to resist the full hydrostatic head of the PMF. Additionally,these structures were checked regarding the buoyant force due to the PMF and were found to have an adequate design to prevent uplift from such buoyant force [15]. Long-range weather forecasts and flood advisories are available through the National Weather Service and are routinely monitored by NSP. They would afford the PINGP ample warning of an impending flood. Abnormal Operating Procedure AB-4, " Flood" [23], specifies the actions to be performed if flood levels reach 683 feet MSL (1929 adjustment). The PINGP will sustain regular operation to a flood stage of 692 feet MSL (1929 adjustment). When the flood stage exceeds 692 feet MSL, both units would be taken to hot standby, and the C-16

(O)

~

main generator disconnect links would be removed from the generator leads of both units per Technical Specification 6.5.A.6. Offsite power would then be available through any of the offsite transformers and IR and 2R. Control circuitry for the respective source breaker in the plant substation would be defeated, and fault protection would be provided at the source end of all offsite transmissionlines. In this way, two different paths of offsite power could be provided up to a flood levelof 698 feet MSL. In the event ofloss of offsite power, the Unit I design minimum supply of diesel fuel oil is 70,000 l gallons, which is suflicient to operate one diesel generator and one diesel cooling water pump for j more than 14 days. The Unit 2 design minimum supply of diesel fuel oil is 75,000 gallons, which l is sufficient to operate one diesel generator set for 14 days. l Based on the existing design bases of the PINGP,it is concluded that the effects due to external flooding do not impact the safe operation of the PINGP. C.2.3.2 Probable Maximum Precipitation i Generic Letter 89-22, " Potential for Increased Roof Loads and Plant Area Flood Runoff Depth at Licensed Nuclear Power Plants due to Recent Change in Probable Maximum Precipitation Criteria Developed by the National Weather Service" [2], informed licensees that more recent probable l maximum precipitation (PMP) criteria had been published by the National Oceanic and Atmospheric Administration (NOAA)/ National Weather Service (NWS). These criteria are contained in NOAA/NWS HydrometeorologicalReports (HMR) No. 49 (1977), No. 51 (1978), No. 52 (1982), No. 53 (1980), and No. 55 (1984). The criteria contained in these documents call for higher rainfall intensities over shorter time intervals and over smaller areas than have been previously considered. This could potentially lead to higher site flood levels and greater roof ponding loads than have previously been considered. For the IPEEE, licensees should review this new precipitation criteria against their existing design bases in terms of revised flood levels and higher roofponding values. Regarding increases in the magnitude of flood levels, Appendix F of the PINGP USAR documents a study to determine the probable maximum flood (PMF). The study considered, among other parameters,the heaviest possible contribution to the flood by precipitation. The study includes the following definition of " probable maximum flood": The probable maximum flood is derived from hydrometeorological studies and is independent of historical flood frequencies. It is the estimate of the boundary between possible floods and impossible floods. Therefore, it would have a return period approaching infinity and a probability of occurrence,in any particular year, approaching zero. ( k )) C-17

1 Therefore it is judged that the flood levels determined in the USAR Appendix F analysis would bound the levels calculated by the criteria given in Generic Letter 89-22. Regarding roofponding (accumulation of water on the structure roof resulting from precipitation),a review of the existing configuration of the Class I structures at the PINGP was made to determine if roof ponding would adversely impact the design bases of the structure. The conservative assumption was made that all the drains would be plugged. A certain amount of water, therefore, would remain on the structure roof, an amount that would depend upon the actual roof configuration. This amount of water remaining on the roof would be assessed to determine ifit exceeds the design loading of the roof and could pose a hazard. l To aid in this determination, a walkdown of the roofs was performed for the Service Building, Auxiliary Building, Radwaste Building, Turbine Building, and D5/D6 Diesel Generator Building. The purpose of the walkdown was to determine the amount of water that could physically accumulate on the roof, assuming that the roof drains were inoperable. The roofs were examined for configuration, slope, and size of roof rim or parapet. The results of this walkdown are presented below. For the Service Building, the roof was verified to be essentially flat, sloping toward the existing j roof drains. Metal flashing runs along the north, east, and south edges of the roof, creating a rim conservatively measured as 5" higher than the surface of the roof. In the event of precipitation,if the roof drains were plugged, a pond of water would develop, covering the entire surface of the roof. The water would accumulate until the level of the top of the rim was reached (approximately 5" high), and then the water would start spilling over the rim and off the roof. As stated in PINGP USAR Section 12.2.1.3.1, Environmental Loads, " snow load of 50 lbs per sq ft of horizontal projected area is used in the design of structures and components exposed to snow". This criterionis from applicable codes and standards, including the Uniform Building Code which i accounts for snow loading in the safe design of structures. Using a weight of water of 62.4 pounds per cubic foot and assuming a conservative height of water of 5", the weight resulting from the water ponding would be 26 pounds per square foot. Therefore the maximum amount of water that could physically accumulate on the roof of the Service Building would not approach the design load limit of 50 pounds per square foot. For the Auxiliary Building, the roof was verified to be essentially flat, sloping toward the existing roof drains. Metal flashing runs along the east and west edges of the roof, creating a rim conservatively measured as 5" higher than the surface of the roof. In the event of precipitation,if the roofdrains were plugged, a pond of water would develop covering the entire surface of the roof. The water would accumulate until the level of the top of the rim was reached (approximately 5" high), and then the water would start spilling over the rim and off the roof. The maximum weight load on the Auxiliary Building roof due to water ponding, therefore,is 26 pounds per square foot, ) /G considerablyless than the design value of 50 pounds per square foot. l C-18

I For the Radwaste Building, the roof was verified to be essentially flat, sloping toward the existmg roof drains. Metal flashing runs along all four edges of the roof, creating a rim conservatively measured as 7" higher than the surface of the roof. The maximum weight load on the Radwaste , Building roof due to water ponding is, therefore,36.4 pounds per square foot, considerably less i than the design value of 50 pounds per square foot. For the Turbine Building, the roof was verified to be essentially flat, sloping toward the existing roof drains. Metal flashing runs along all four edges of the roof, creating a rim conservatively measured as 7" higher than the surface of the roof. The maximum weight load on the Turbine i Building roof due to water ponding is, therefore,36.4 pounds per square foot, considerably less  ! than the design value of 50 pounds per square foot.

For the D5/D6 Diesel Generator Building, there are two roofs involved

the main roof of the l D5/D6 Diesel Generator Building and the roof to the ventilation compartment on top of the main i roof. The main roof of the D5/D6 Diesel Generator Building was verified to be esentially flat, j sloping toward the existing roof drains. Metal flashing runs along the northyest, and south sides of the roof, creating a rim conservatively measured as 5" higher than the surface of the roof. The maximum weight load on the D5/D6 Diesel Generator main roof due to water ponding is, therefore, 26 pounds per square foot, considerably less than the design value of 50 pounds per square foot.

                                                                                                            )

i

                                                                                                            \

O d The smaller roof of the ventilation compartment atop the D5/D6 Diesel Generator Building main roof was verified to be sloped, with no existing rim. Therefore, all the precipitationlanding on the roof would flow off. Therefore, for the roofs of the Service Building, Auxiliary Building, Radwaste Building, Turbine Building, and D5/D6 Diesel Generator Building,it is concluded that water ponding does not pose a hazard by impacting the design bases of the structures, and therefore does not contribute to plant risk. i I i  ! C.2.4 Transportation and Nearby Facility Accidents The NRC acceptance criteria for transportation and nearby facility accidents is stated in Standard Review Plan Sections 2.2.1-2.2.2 (Locations and Routes, Descriptions), 2.2.3 (Evaluation of Potential Accidents), and 3.5.1.6 (Aircraft Hazards). Supplementary guidance is provided in Regulatory Guide 1.78, " Assumptions for Evaluating the Habitability of a Nuclear Power Plant Control Room During a Postulated Hazardous Chemical Release" [9], Regulatory Guide 1.91,

       " Evaluations of Explosions Postulated to Occur on Transportation Routes Near Nuclear Power Plants" [10], and Regulatory Guide 1.95, " Protection of Nuclear Power Plant Control Room Operators Against an Accidental Chlorine Release"[11].
   ' O V                                                 C-19

In accordance with the guidance presented in NUREG/CR-5042, hazards associated with

  .V                              -

transportationaccidents melude: i Aviation accidents (Commercial, General, and Military) Marineaccidents(Shipand Barge) Pipeline accidents (Gas and Oil)  ! Railroad accidents j . Truck accidents i i In accordance with the guidance presented in Supplement 2 of NUREG/CR-5042, hazards associated with nearby facility accidents include: Accidents in nearby industrial facilities Accidents in nearby military facilities Hazardous material releases from on-site storage l As defined by NUREG-1407 (Chapter 5), the term " nearby" refers to being within 5 miles of the site. Each of these individual accidents are addressed in the sections below. rh 3 b C.2.4.1 Aviation Accidents To assess the potential for aviation accidents and their consequences to the plant, the initial step is to determine whether conditions exist that make this a credible scenario. These conditions include ^ the proximity of the plant to commercial and military airfields, the number of flights taking off and landing at these airfields, and the proximity of the plant to the path of approaches, routes and holding patterns of commercial and military aircraft. In accordance with the acceptance criteria given in SRP 3.5.1.6 [6], the probability of an aircraft accident resulting in radiological consequences greater than 10 CFR Part 100 guidelines is considered to be less than 10E-7, provided that:

1. The plant-to-airport distance D is between 5 and 10 statute miles, and the projected annual 2

number of operationsis less than 500 D , or the plant-to-airportdistance D is greater than 10 statute 2 miles, and the projected annual number of operations is less than 1000 D ; a

2. The plant is at least 5 statute miles from the edge of military training routes, including low-level training routes, except for those associated with a usage greater than 1000 flights per year, or where activities (such as practice bombing) may create an unusual stress situation; O

V C-20

m

3. The plant is at least 2 statute miles beyond the nearest edge of a federal airway, hc,lding pattern,or approach pattern.

l There are two airports that are relatively close to the PINGP: the Minneapolis /St. Paul International Airpo t and the Red Wing Airport. Each of these two airpcrts is evaluated below, with regard to the three acceptance criteria of the SRP. As stated in PINGP USAR Section 2.2.1," Location", the plant is located at 44' 37.3' north latitude and 92 37.9' west longitude. The Minneapolis /St. Paul International Airport is located at 44" 53' north latitude and 93 13' west loi gitude [26]. Therefore the distance between the plant and the airport is approximately 30 statute miles. Substituting a value of 30 for D in the appropriate equation for maximum acceptable number of projected annual operations gives:  ; Maximum AcceptableNumberofOperations= 1000 D 2= 900,000. i Since the projected annual number of airport operations from August 1996 to July 1997 is 494,197 [26], the first criterion is satisfied. There are no military training routes or low-level training routes within five statute miles of the plant [26]. Therefore the second criterion is satisfied. O As stated in Reference 26: "The only airway in the vicinity of the Prairie Island plant is V-2/97, the 125 radial of the Gopher VOR, which passes approximately three miles to the northeast of the plant's location. The extended final approach course for Runways 29R and 29L passes approximately two and three miles south of the plant. However, the final approach normally extends only twenty to twenty-five miles out. The plant is located nearly 30 miles southeast of the airport. On limited occasions the final may extend out to 30 miles. It would occur during a heavy arrival rush and would last for only a brief period. Only about four aircraft would transit the area during each rush and we have approximatelysix of these periods of heavy traffic daily. Annually, 49% of the traffic land on Runways 29L and R. "Thereforeit is concluded that the third criterionis satisfied for the Minneapolis /St. Paul International Airport. As stated in Reference 26: "The Red Wing Airport is located approximately six miles east of the plant at 44* 35.41' north latitude and 92 29.17' west longitude. The airport traffic pattern extends 2.5 miles southwest of the airport. The airport primarily services small general aviation aircraft and had 3294 instrument operations in the past year. "The distinction made regarding " instrument" operations at Red Wing refers to those operations known by the FAA. Operations involving

    " visual" landings and take-offs are not tracked by the FAA at small airfields (such as Red Wing) for which there is no tower. Therefore, the total number of operations is not known. However,it should be noted that most operations at these small airPelds involve small planes, and usually involve recreational flying during daylight hours under god weather conditions, V                                                   C-21

q Q' The distance between the plant and the Red Wing airport is approximately six statute miles. Substituting a value of six for D in the appropriate equation for maximum acceptable number of projected annualoperationsgives: Maximum AcceptableNumber of Operations = 500 D2 = 18,000. Since the Red Wing Airport had only 3294 instrument operations in the past year, there would have to be on the order of 15,000 visual operations to exceed the first criterion. This would correspond to over 40 additional flights per day if spread evenly over the year. Red Wing does not approach having this level of activity. Therefore,it is concluded that the first criterion is satisfied. As stated above, there are no military training routes or low-level training routes within five statute miles of the plant. Therefore the second criterion is satisfied. The airport traffic pattern extends 2.5 miles southwest of the airport. Since the airport is approximately six miles east of the plant, it is concluded that the third criterion is satisfied. I i Based on satisfying the three criteria for each of the nearby airfields,it can be concluded that there  ! I is no hazard to the safe operation of Prairie Island. This evaluation has shown that the opportunity for having such an accident is highly remote, making further analysis of accident consequences unnecessary. ) i V C.2.4.2 Marine Accidents l l Marine accidents pose a hazard due to the possible release of hazardous material towards the plant and/or the possibility of explosion and fire with resulting physical damage to the plam due to blast, debris and fire. There is also the possibility of physical damage to the cooling water intake and outlet structures due to collisions by the ship or barge. As stated in PINGP USAR Section 2.9.1, " Effects of Oil Spillage", and 2.9.2, " Postulated Explosion of Munitions Barge", the Prairie Island plant is fully protected from the possible effects of oil spillage on the Mississippi River by a permanent barrier wall or skimmer that has submerged flow openings. The safety related emergency intake is submerged well below the normal river levels. Therefore a spill will not affect the emergency intake system. In addition, the suction intakes for the Circulating Water System, the Cooling Water System, and the plant fire pumps are submerged in bays within the Screenhousestructure. Regarding the possibility of explosion and fire, the explosion of a munitions barge on the Mississippi River has been postulated. This hazard is based on a hypotheticaljumbo barge (195 feet long,35 feet wide, and having 8-1/2 feet of draft) fully laden with 1400 tons of TNT, with the cargo exploding in mid-channel 2600 feet directly east of the plant. The resulting blast effect of 2.25 psi and the transient wind velocity of 78 mph was conservatively obtained by assuming the (]J

\.

C-22

O g entire detonation occurs at the surface of the water even though most of the explosives would be located below the waterline. The control room is designed for the postulated blast without injury to its occupants. The entire room is enclosed with a two-foot thickness of concrete, except for the north wall which is 18 inches thick, and is surrounded by other structures. Conservative application of the linear and rotational components of tornado velocities for those areas of the structure that would be exposed to the blast has effectively resulted in design for a 2.25 psi internal loading, plus allowance for missiles and earthquakes. The USAR states in Section 2.9.2 that some damage from such a blast may be expected to occur to light external structures. However, the USAR also states that this damage would be consistent with the intent of the design for these structures with regard to tornado forces. With regard to the efTects of toxic chemicals, according to the PINGP Control Room Habitability Toxic Chemical Study [16], data was obtained from the U.S. Army Corps of Engineers for barge traffic along the Mississippi River. From this data it was determined that the only substances that were shipped in 1990 in excess of RG 1.78 criteria (i.e., shipments of 50 times per year) were chemical fertilizers. These fertilizer shipments had an average weight of 2000 tons. Although chemical fertilizers can be used in creating a potent explosive, this would require additives that are not normally ir cluded in such shipments. Introducing these additives to the chemical fertilizer shipment would constitute an act of attempted sabotage which is outside the scope of the IPEEE investigation. The conclusion of the study was that since chemical fertilizers represented the only hazardous material shipped, toxic chemical shipment by barge does not pose a hazard to the k PINGP. Additionally,an analysis was performed to determine the vulnerability of the cooling water intakes to a hypothetical barge collision. As stated in PINGP USAR Section 2.9.3, " Vulnerability of Cooling Water intakes to Barge Collision", the total loss of plant cooling capability is not credible since, in order to disable all supplies of cooling water, an accident would have to result in concurrently blocking the intake screenhouse structure screens and totally damaging or blocking the emergency intake structure. Emergency bypass gates are provided in the intake screenhouse to prevent the possibility of eliminating all supplies of cooling water. The emergency intake structure is designed and located to preclude total blocking by the postulated accident. Based on the above analyses, it is conduded that marine accidents could not impact the safe operation of the PINGP. C.2.4.3 Pipeline Accidents Pipeline accidents pose a hazard due to the release of hazardous material and/or the possibility of explosion. As stated in PINGP USAR Section 2.2.4.4, " Nearby Industrial, Transportation, and A) l G C-23

i cx  ! l i Military Facilitief', no large natural gas pipelines pass close to the plant site. Therefore no further i V assessment of pipeline accidents need be performed. l C.2.4.4 Railroad Accidents Railroad accidents pose a hazard to a nuclear power plant due to the possible release of hazardous  ! material and/or the possibility of explosion and fire. Physical damage to the plant due to actual I collision with plant structures is considered minimal due to the distance between main rail lines and j plant structures. As stated in PINGP USAR Section 2.2.4.4, " Nearby Industrial, Transportation, and Military Facilitief', there are two railmads within 5 miles of the site: The Soo Line Railroad, which runs across the southwest portion of the PINGP site and is within approximately0.2 miles of the site; The Burlington Northern Railroad, which runs on the opposite side of the Mississippi River i in Wisconsin and is within approximately2 miles of the site. C'T The guidance presented in Regulatory Guide 1.91 [10] was employed to evaluate the effects of a l

 \J  railroad car explosion. Regulatory Guide 1.91 states that the maximum probable explosive cargo in        !

a single railroad box car can be assumed to be 132,000 pounds (of TNT equivalent). The regulatory guide also provides the following formula for determining the minimum safe distance from the postulated explosion to plant structures: R2kW" where R is measured in feet, W is measured in pounds mass, and k = 45. This formula is based on the postulated explosion producing a peak positive incident overpressure on plant structures of 1 psi, a value at which no significant damage to the structures is assumed to occur. With regard to the evaluation of an explosion of a railroad car on the Burlington Northern Railroad, the value of 132,000 for W is substitutedin the formula to yield a value for minimum safe distance R of 2291 feet, which is less than the actual distance of 2 miles (10,560 feet). Therefore it can be concluded that the postulated explosion of a railroad car on the Burlington Northem Railroad presents no hazard to the PINGP. With regard to the Soo Line Railroad, the 2291 feet minimum safe distance R exceeds the actual p) ( distance of 0.2 miles (l.056 feet). However, PINGP USAR Section 2.9.2," Postulated Explosion of C-24

O Munitions Barge", states that analyses have demonstrated that an overpressure of 2.25 psi resulting from a postulated barge explosion would be acceptable. The USAR states that some damage may j be expected to occur to light extemal structures for such an event, but that this would be consistent I with the intent of the design for these structures with regard to tornado forces. l Therefore if both sides of the formula are divided by R, the result is: 1 = 45 WA R ' j which expresses peak positive incident overpressure in terms of W and R. If values of 132,000 and 1056 are then substituted for W and R, respectively,the result is: 45 (132.000@ = 2.17 1056 This indicates that an explosion of 132,000 pounds mass at a distance of 1056 feet will result in a peak positive incident overpressure on plant structures of 2.17 psi. Since it has been demonstrated that an overpressure of 2.25 psi would be acceptable,it is concluded that the postulated explosion of a railroad car on the Soo Line presents no hazard to the PINGP. I d With regard to the effects of toxic chemicals, the PINGP Control Room IIabitability Toxic Chemical Study (16] determined that two chemicals, chlorine and anhydrous ammonia, shipped by l the SOO Line Railroad, could potentially present a hazard to the control room operators. However, according to the results of calculations ("PINGP Toxic Chemical Analysis - Chlorine and Ammonia Probability Analysis" [18], and "PINGP Toxic Chemical Analysis - Revised Chlorine and Ammonia Spill Estimates" [19], it was determined that the probability of a SOO Line Railroad railcar accident releasing chlorine that would incapacitate control room operators was 1.16 X 10 per year. These calculations also determined that the probability of a similar railcar accident releasing ammonia would be 1.47 X 10 per year, which is less than the Regulatory Guide 1.91 criterion of <1E-6 per year for offsite hazardous releases. Therefore it is concluded that toxic 4 chemical shipment by rail does not pose a hazard to the PINGP, based on the low probability of occurrence of this event. C.2.4.5 Truck Accidents Truck accidents pose a hazard to a nuclear power plant due to the possible release of hazardous material toward the plant and/or the possibility of explosion and fire, with resulting physical damage to the plant due to blast, debris and fire. Physical damage to a plant due to actual collision U C-25

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l [\ {} with plant structures is considered minimal due to the distance between main highways and plant structures. At the PINGP, the movement of trucks carrying hazardous materials inside the exclusion area is infrequent and controlled, and only a limited amount of hazardous materials is carried in each shipment. Further, the combination of a heightened level of caution onsite when such a delivery is made (e.g. security inspection and escort, scheduled delivery), along with the low level of truck accident precursors (e.g., negligible traffic, slow speed when inside the gates, non-explosive material) makes the likelihood ofsuch an event very small. With regard to the effects of toxic chemicals, the PINGP Control Room Habitability Toxic Chemical Study [16] evaluated traffic within a five-mile radius of the site. The study states that only one major highway, Highway 61, is within that radius. The study concluded that frequent hazardous materials shipments along Highway 61 are not anticipated, but would occur instead along major interstate routes. Also, according to this study, the City of Red Wing Fire Department has indicated that no accidents involving a truck carrying hazardous materials on Highway 61 has occurred in over 10 years. Therefore it is concluded that toxic chemical shipment by truck does not pose a hazard to the sire. With regard to potential truck explosions, and using the data collected for the PINGP Control Room Habitability Toxic Chemical Study, it is concluded that shipments of hazardous materials on Highway 61, the only major highway within the five-mile radius of the plant, would be very (} b infrequent. Hazardous material shipments of any significant frequency would occur on the interstate highways beyond the five mile radius. Therefore, truck explosions do not pose a hazard to the site. Based on the above analyses it is concluded that truck accidents have no impact on the safe operation of the PINGP. C.2.4.6 Nearby Industrial Facilities The nearest industrial center to the PINGP site is the city of Red Wing, Minnesota, located approximately 3-4 miles from the site. In evaluating toxic hazards to the site, the PINGP Control Room Habitability Toxic Chemical Study obtained information regarding nearby industrial  ! facilitieslocated in the Red Wing area. That list is reproduced below: l

 ~N (b                                                      C-26

  -- -     .-     . - .- -          --         -.           _~     . . - . - . - .      _ - - . . .           - _ . - ,

e ! I l l l Table C.3 City of Red Wing MajorIndustry l

Employer Products / Services Employees I i Red Wing Shoe Company Work Shoes and Boots 1040 i Northern States Power Co. Utilities 676 j Josten's Diploma Division Diplomas, Plaques 325 -

St. John's Hospital Medical 322 l F.L. Meyer Industries Transmission Poles 288 i

, S.B. Foot Tanning Co. Leather Processing 280 Durkee-Atwood Rubber Products 262 Red Wing Ilealth Center Medical 231

Interstate Medical Center Medical 191 Riviera Cabinets Kitchen Cabinets 170 St. James Hotel Food & Lodging 153 Riedell Shoes, Inc. Sports Footwear 130 Central Research Manufacturing Mechanical Arms 58 RAM Control Inc. Robotics 55 Although these industries are in the vicinity of Prairie Island (some are within a five-mile radius of the plant), it is concluded, based upon their size and the nature of their products, that they create no hazard to the PINGP site as a result of potential explosion or fire.

With regard to the effects of toxic chemicals, the PINGP Control Room Habitability Toxic Chemical Study evaluated the industrial facilities in the City of Red Wing and concluded that, based on the size of the industries, and the types of products and services produced by these i industries, that the hazardous chemicals used by nearby industrial facilities pose no hazard to the safe operation of the PINGP. l Therefore it is concluded that accidents from nearby industrial facilities would not impact the safe operation of the PINGP. C-27

i O C.2.4.7 Nearby Military Facilities According to PINGP USAR Section 2.2.4.4, Nearby Industrial, Transportation, and Military - Facilities, there are no military facilities within 5 miles of the Prairie Island site. Therefore, this j

potential contributor to risk can be eliminated. '

I l l l C.2.4.8 Hazardous Material Releases from On-Site Storage 1

                                                                                                                        )

The PINGP Control Room Habitability Toxic Chemical Study [16] was performed to assess the need for toxic chemical detectors at the site. The study consisted of the following steps: l e Define the appropriate regulatory requirements; e Perform a survey to identify hazardous materials; j

• Develop a toxic chemical spill analysis model; l e Define incapacitation assessment criteria; and

           .        Assess the effects of toxic chemical spills on control room operators.                              )

The study included an evaluation of toxic materials stored on site. This study determined that , eight hazardous chemicals were stored onsite that exceeded the Superfund Amendments and Reauthorization Act (SARA) reportable limits:

           .        Sulfuric acid (maximum capacity 5,000 gal.)

e Diesel fuel #2 (maximum capacity 142,000 gal.)

                                                                                                                        ]

e Boric acid (maximum capacity 36,000 lbs.) '

           .        Liquid nitrogen (maximum capacity 3,000 gal.)                                                         ,

e Sodium hydroxide (maximum capacity 5,000 gal.) e Hydrazine 35% (maximum capacity 250 gal.) e Sodium bromide (maximum capacity 400 gal.) e Sodium hypochlorite (maximum capacity 1,142 gal.) Four of these chemicals (boric acid, liquid nitrogen, sodium bromide, and sodium hypochlorite) were eliminated from further consideration because they are not identified by 29CFR1910, the National Institute for Occupational Safety and Health, or the American Conference on Governmental Industrial Hygienists as being toxic. l - Of the four remaining chemicals, three (sulfuric acid, hydrazine, and sodium hydroxide) were eliminated from further consideration since they were evaluated in the original toxic study issued in 1981 and found at that time to pose no threat to Control Room operation. With the exception C-28

of hydrazine, these chemicals are stored in the same locations and quantities as they were when they were evaluated in the 1981 study. Although current hydrazine storage is 250 gallons, it is , now stored much farther from the Control Room ventilation intake and therefore is eliminated  ! from further consideration. j The one remaining chemical stored on-site requiring consideration was diesel fuel oil. The i majority of the fuel oil at the site is stored underground and, therefore, presents no real hazard. A l rupture of the underground tank would result in ground seepage of the fuel oil and not vapor  ! release. There are also a small number of day tanks located within plant structures. These are of  : much smaller volume. The hazard presented by these day tanks would be as a source of l flammable material. The Internal Fires IPEEE (Appendix B) accounts for these tanks in its , assessment of the potential increase to plant risk caused by combustibles located onsite. j Therefore, the study eliminated fuel oil from further consideration.  ; Therefore the Control Room Habitability Toxic Chemical Study concluded that no toxic j chemical poses a hazard to Control Room operation. Based on these results, it is concluded that i accidents from chemical releases from on-site storage would not impact the safe operation of the i PINGP. l i C.3 CONCLUSIONS 1 Based upon the evaluations presented in Section C.2, we conclude that there is no external event l other than fire and seismic that may be a safety concern to the Prairie Island Nuclear Generating i Plant. No vulnerabilities were identified and the screening criteria contained in NUREG-1407 and Generic Letter 88-20, Supplement 4, are satisfied for all events. ( C-29

    ._ __ _    _ . - _ . _ _ _ _ .        .      . . _ _ _ _ __ ._                _ . . . . _ . . __ . . . _ . . _          ~ . _

d i 1 j (1) Review Plant Specific Hazard Data and Licensing Bases (USAR) I d

}

1r ] (2) Identify Significant Changes, if any, since OL lssuance 1 A i 1r NO l(3) Does Plant / Facilities Design Meet 1975 SRP Criteria? (Quick Screening & lYES

Walkdown)  ;

4

                         !                                                                                            I i

~ OR  : 'YES

                    ; (4)is the Hazard Frequency Acceptably Low?

NO 4. ( OR . 1V

                                                                                                                       'YES

, s'(5) Bounding Analysis (Response / Consequence)

                         !                                                                                             I NO
                                                                        -1r OR           l
                    ; (6) PRA
                                                                                                                     -J NO 1r l(7) Documentation (incl. Identified Reportable items and Proposed                               l

[ Improvements) I l Figure C.1 Flow Chart ofIPEEE Screening Process For External Events Other Than Seismic and Fire b C-30

O

           'f      '*

ean... s

                                                           ~~~.~~~         mx                  _

s

                                                                            /-            2        -; ..
       ...                                 f    250                                 ,

t ~ l u e \<- - . 180 320 mph " -

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                                                                            .f   1    .-

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           ~...
                     '~.

h' .- s .... _. u. . -. 5

               - - - .._ m                                                                  ..

1 Figure C.2 Tornadie Windspeeds Corresponding to a Probability of 10# Per Year [ C-31

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j

                  'i t.,    '-
                                   '             ......                                                                                        / f#\
                                   .."'%~~..M ._                                       $..Q e,                                                      ,
                                                                                                        ~

q 7 f ., _ N 200 #' l ar m'

                                                                                                                   . ~

!. t - \P'~ .1 -

!             k                                                            ,,,
                                                                                                   \                                         4 i                                      140                                                  h 260 mph                 "'

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                 ~
                                                -w

n. -

p- .f j .. . 4 e s%-

                                                                                %_1.-

u. u.. - ..

f 1

. - -- asvami m

! l A l j J Figure C.3 Tornadic Windspeeds Corresponding to a Probability of104 Per Year 4 i O C-32

C.4 REFERENCES

1. Generic Letter 88-20. Supplement 4, " Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - 10CFR50.54(f)", June 28,1991.

2. Generic Letter 89-22, " Potential for Increased Roof Loads and Plant Area Flood Runoff Depth at Licensed Nuclear Power Plants due to Recent Change in Probable Maximum Precipitation Criteria Developed by the National Weather Service", October 19,1989.

3. NUREG-1407, " Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities", June 1991.

4. NUREG/CR-5042, " Evaluation of External Hazards to Nuclear Power Plants in the United States", December 1987.

5. NUREG/CR-5042, Supplement 2, " Evaluation of External Hazards, to Nuclear Power Plants in the United States, Other External Events", February 1989. i

6. NUREG-75/087, " Standard Review Plan for the Review of Safety Analysis Reports for  !

(,) Nuclear Power Plants", September 1975. V

7. USNRC Regulatory Guide 1.59, " Design Basis Floods for Nuclear Power Plants",

Revision 2, August 1977 (Rev.16).

8. USNRC Regulatory Guide 1.76, " Design Basis Tornado for Nuclear Power Plants", April i 1974.

9. USNRC Regulatory Guide 1.78, " Assumptions for Evaluating the Habitability of a Nuclear Power Plant Control Room During a Postulated Hazardous Chemical Release", June 1974.

10. USNRC Regulatory Guide 1.91, " Evaluations of Explosions Postulated to Occur on Transportation Routes Near Nuclear Power Plants", Revision 1, February 1978.

I1. USNRC Regulatory Guide 1.95, " Protection of Nuclear Power Plant Control Room Operators Against an Accidental Chlorine Release", Revision 1, January 1977.

12. USNRC Regulatory Guide 1.102, " Flood Protection for Nuclear Power Plants". Revision 1, September 1976.

C C-33

(O 13. USNRC Regulatory Guide 1.117, " Tornado Design Classification", Revision 1, April 1978.

14. PINGP Updated Safety Analysis Report, Rev. 7, December 1988.

15. PINGP USAR Appendix F, " Probable Maximum Flood Study Mississippi River at Prairie Island, Minnesota", incorporated into USAR Revision 4, December 1985.

16. Northern States Power Company Prairie Island Nuclear Generating Plant Control Room Habitability Toxic Chemical Study, Revision 1, December 11,1991.

17. PINGP Calculation GEN-PI-005, " Tornado and Seismic Evaluation of D1 and D2 Components (HVAC Duct, Exhaust Piping, & Door)".

18. TENERA Calculation 1934-2.2-005, "PINGP Toxic Chemical Analysis - Chlorine and Ammonia Probability Analysis".

19. TENERA Calculation 1934-2.2-006, "PINGP Toxic Chemical Analysis - Revised Chlorine and Ammonia Spill Estimates".

20. Transactions of the American Society of Civil Engineer's Paper ASCE 3269, " Wind

,C Forces on Structures", Volume 126, Part II (1961). b

21. ANSI /ANS-2.3-1983, " Standard for Estimating Tornado and Extreme Wind Characteristics at Nuclear Power Sites", American Nuclear Society,1983.

22. PINGP Abnormal Procedure AB-2, " Tornadoes", Revision 9, October 21,1994.

23. PINGP Abnormal Procedure AB-4," Flood", Revision 9, April 12,1993.

24. PINGP Operating Procedure C25, " Circulating Water System", Revision 13.

25. Non-Modification Safety Evaluation No. 427, " Cooling Water Emergency intake Line Capacity", November 21,1995.

26. U. S. Department of Transportation Federal Aviation Administration letter, B. Wagoner to R. Newman, dated August 29,1996.

27. PINGP Reportable Occurrence Report RO-78-18, date of event 9/12/78.

28. PINGP Reportable Occurrence Report RO-80-20, date of event 7/15/80.

p 29. PINGP Trip Report for Unit 2, date of trip 9/12/82. C-34 l

                                                                                                  \

l

i l ) 4 !o

30. Prairie Island Nuclear Projects Department Follow-On Item No. A0686, " Documentation i of Adequate Lightning Protection."

I i i 1 d I e 5 I i C-35}}