ML20214U202

Technical Rept 86.2SH Verification of IPE for Shoreham. W/ 870313 Release Memo

ML20214U202
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Site:	Shoreham File:Long Island Lighting Company icon.png
Issue date:	01/31/1987
From:	DELIAN CORP., INDUSTRY DEGRADED CORE RULEMAKING PROGRAM, LONG ISLAND LIGHTING CO.
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NUDOCS 8706110091
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IDCOR Program Report Technical Report 86.2SH Verification ofIPE for Shoreham January 1987 DO K hhohh22 PDR G()/

The Industry Degraded Core Itulemaking Program, Sponsored Ily the Nuclear Industry

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Arizona Public Serivce Company IDCOR Nebraska Public Power District T*he Babcock & IVilcox Compny New York Power Authority Baltimore Gas and Electric Company Niagara Atohawk Ikwer Corporation BuhtelIkwer Corpration Northeast Utilities Service Company Black & Veatch, Consulting Engineers Northern Indiana Public Service Company Boston Edison Company Northern States Power Company C F Braun & Co Paajc Gas and Elutric Company The Cincinnati Gas & Elutric Company Iknnsylvania lbwer & Light Company The Cleveland Elutric illuminating Company Philadelphia Elutric Company Combustion Engineering, Inc. Ibrtland General Elutric Company Commonwealth Edison Company Public Service Company ofOklahoma Consolidated Edison Company ofNew York, Inc. Public Service Elutric and Gas Company Consumers IMwer Company Public Service Indiana Daniel Construction Company Puget SoundIMwer & Light Company The Detroit Edison Company Rochester Gas and Electric Corpration Duke Ibwer Company Sargent & Lundy Duquesne Light Company South Carolina Elutric and Gas Company Ebasco Services incorprated Southern Cahfornia Edison Company Ente Nazionale per l'Energia Elettrica Southern Company Services, Inc.

Exxon Nuclear Company, Inc. Stone & IVebster Engineering Corporation Florida ikwer & Light Company Swedish State ikwer Board Fluor ikwer Servius, Inc. Taiwan IMwer Company General Elutric Company Technical Rescarch Centre ofFinland Gibbs & ilill, Inc. Tennessee Valley Authority Gilbert / Commonwealth Companies Texas Utilities Generating Company GPU Nuclear The Toledo Edison Company GulfStates Utilities Company Union Elutric Company llouston Lighting & Power Company United Engineers & Constructors inc.

Illinois IMwcr Company Virginia Elutric and Ikwer Company lowa Elutric Light & Ikwer Company IVashington Public lbwer Supply System IT Corpration lVestinghouse Electric Corpration Japan Atomic industrial Forum, Inc. IVisconsin Elutric Ikwer Company Kansas Gas and Elutric Company IVisconsin Public Service Corporation Long Island Lighting Company Yankee Atomic Electric Company Aliddle South Servius, Inc.

The IDCOR program is a large, independent technical effore sponsored by the nuclear industry. The Program is directed by a Policy Group comprised of representatives of the sponsoring organizations and operates under the cc,rporate auspices of the Atomic Industrial Forum. The Program's purpose is to develop in an expeditious manner a comprehensive,in-tegrated technically sound position to assist in determining whether changes in regulation are needed to reflect degraded core and core enelt accidents. Further information on the Program can be obtained by contacting Roger W. Huston, Reactor Licensing and Safety Projects Manager /IDCOR, Atomic Industrial Forum,7101 Wisconsin Avenue,11ethesda, MD 20814 4891,(301) 654-9260.

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IDCOR TechnicalReport 86.2SH Verification ofIPE for Shoreham January 1987 by:

Long Island Lighting Company t

, Wading River, New %rk l with assistancefrom:

Delian Corporation and Erin Engineering and Research, Inc.

The Industry De' graded Core Rulemaking Program. Sponsored by the Nuclear Industry

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NOTICE This report was pepared on accouas of work under comeract to the Atomic Indurrial Forum. Neither ebe Aeomic Indmerial )

Forusa, not any ofin emplopes or aussben, the IDCOR Policy Group or the IDCOR or Aeomic ladusenal Foran consulman and comeractors, mabes any warranty, espesud or implied, or asumes lept liability or responsibiliey for the accuracy, com-pleermeas or usefulmen of any information, apparacus, peduct or pacen discloud, or repewan ibat is use would noe infringe F iveerly omd rigius, The opsances, concisions, and recommendacions set forth in this report are abase o(the authors and do not necesarily repe-eene the views of abe Asomuc Industrial Forum,Inc.,la employees, or the IDCOR Policy Group,its members or the Atomic In-detrial Fonen or IDCOR Policy Group consultana or contractors.

Because IDCOR is suppried in pre by Federal funds, the following notice is required by Federal regulations:

The Asomic ledmerial Forusn's IDCOR activities are subject to Title VI of the Civil Rights Act of 1964, which prohibits dis-crimination based on race, color, or national origin. Wriewn complaints of esclusion, denial of benefits, or other discrimina.

tion of those bases under this param rnay be filed with (among others) the Tennessee Valley Authority (1YA), Office of EEO,400 Commerce Avenue EPBl4, Knoxviile TN 37902, and mmt be filed not tant alun 90 daysfrone the den of allegrd extinuinssion Applicable TVA regulations appar in prt 302 of Title 18, Code of Federal Regulations. Copies of the regulations, or further information, may be obuined from the above address on request.

I Copyright Cl987 by Atomic Industrial Forum, Inc.

7101 Wisconsin Avenue Bethesda, MD 20814 4891 All rights reserved.

PREFACE 1

In 1935 the Nuclear Regulatory Commission issued a policy statement on severe accident issues which rescinded the intended rulemaking on severe accidents announced in 1980. In this policy statement. NUREG-1070, "NRC Policy on

' Future Reactor Designs - Decisions on Severe Accident Issues in Nuclear Power Plant Regulation", the Commission concluded that based on the information currently available, existing power plants pose no undue risk to public health and safety. They also found no basis for Leeediate action or generic rulemaking or other regulatory changes for these plants because of severe accident risk.

Although the Commission concluded that generically existing plants are safe posing no undue risk to public health and safety, they also concluded in

• i NUREG-1070 that a systematic examination of existing plants should be done on a plant specific basis: " Recognizing that plant-specific PRAs have yielded valuable insights to unique plant vulnerabilities to severe accidents leading to low cost modifications, licenses of each operating reactor will be expected to perform a limited-scope, accident safety analysis designed to discover instances (i.e. outliers) of particular vulnerability to core melt or to unusually poor containment performance, given core-melt accidents."

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the Industry Degraded Core Rulemaking (IDCOR) Program undertook the levelopment of an individual plant evaluation methodology (IPEM) that would se responsive to the requirements of the Severe Accident Policy Statement for

. nae by its members. Separate but equivalent methodologies were developed for BWR and PWR reactors. Each methodology contains two main parts; a systems evaluation methodology and a source term evaluation methodology. ,

The IPE methodology is a limited scope screening analysis. It is based on PRA techniques, but it has been simplified so that the essential insights that can be obtained from a PRA are developed without the level of detail normally 4

developed in PRAs. The systems methodology is similar to but less detailed {

than a level one PRA. The source term methodology provides containment ,

response event trees that are evaluated for specific accident sequences.

Approximate fission product source terms have been assigned each tree end state. These and states determine whether a particular plant has a potential  ;

for outlier performance. This part of the methodology is similar to the containment evaluation performed in a level two PRA, although it is much simplified so that only the key plant issues that could substantially affect j the containment performance are evaluated. These simplifications of the PRA technology save about 50% or more of the resources required to perform a level one PRA.

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IDCOR recognized early in the methodology planning that a demonstration of the methodology would be needed. Testing would verify that the methodology 2- -

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i was adequate to acreen individual plants for outliers and that it could be used by organizations and individuals having limited familiarity with PRA techniques. Seven plants were selected by IDCOR for test applications of the methodology. These are the original IDCOR reference plants; Grand Gulf Nuclear Station, Peach Botton Atomic Power Station, Sequoyah Nuclear Plant, and Zion Nuclear Generating Station, and three additional plants; Calvert Cliffs Nuclear Power Plant, Oconee Nuclear Station, and Susquehanna Steam Electric Station. An eighth plant, Shoreham Nuclear Power Station, was added 3 1 ster in the application phase. These eight plants allowed IDCOR to verify i

1 the methodology for all vendor nuclear steam supply systems and all major containment types used in domestic facilities.

i The application of the methodology to the four IDCOR reference plants was i

intended to directly demonstrate the ability of the methodology to uncover significant effects normally found by PRAs. Within this group, the application of the PWR methodology to the Zion Nuclear Plant was limited to 4

verifying that the results obtained from the methodology reproduced the results obtained in the Zion PRA. Only the analytical methods in the methodology were exercised in this application. The four additional plants cyplying the methodology were plants with nuclear steam supply systems or l containment types not studied intensively during the base IDCOR program.

l l These additional applications were undertaken to demonstrate that the l

i methodology is adequate for assessment of system and containment features cyplicable to plants of Combustion Engineering or Babcock & Wilcox design or to the General Electric Mark II containment.

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In this report, Long Island Lighting Company has summarized its application of the IDCOR methodology to the Shoreham Nuclear Plant. The Shoreham Nuclear Plant is a General Electric Boiling Water Reactor 4 series reactor system with a Mark II containment. This study was not only important in providing coverage of this plant type, but it was also important because much of the information used to develop plant system insights in the BWR systems methodology was derived from the Shoreham PRA.

In using this report, the reader should keep in mind that the study was performed using the first draft of the IDCOR methodology. Substantial changes have been made to the methodology based on this and other test .

applications. These were included in Revision 0 of the methodology in April, 1986. Additional changes and features were included in Revision 1 of the methodology submitted to the NRC in December, 1986. Use of the revised methodology would have resulted in additional information that would have .

been incorporated into the report.

Section 4 of the report was not submitted to IDCOR. This section covers the evaluation of containment performance using the IDCOR source term methodology. During the application of the source term methodology to Shoreham, the NRC undertook several containment initiatives on BWR nuclear plants. Becam a the Shoreham Nuclear Plant may be affected by these initiatives, the applicaticn of the source term method to Shoreham will not be reported as part of the IDCOR IPEM test application task.

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The Shoreham IPEM application is an excellent example of the application of the BWR systems methodology and level of reporting that should be performed.

Some exceptions to the requirements of the methodology were taken by LILCO for the Shoreham application. To reduce the time required to apply the methodology, some information on systems was taken from the existing Shoreham PRA. Also, plant walkdowns called for in the method were not conducted because of the familiarity with the plant of the evaluation team personnel.

• who are located on the plant site and because plant walkdowns had been completed for other purposes. IDCOR did not find these exceptions to be significant in verifying the applicability of the methodology, however, the use of plant walkdowns are an extremely important element in the individual plant evaluation. Plant walkdowns should always be carried out unless extenuating circumstances exist that would merit an exception to the methodology.

IDCOR appreciates the cooperation of the many individuals involved in this -

application of the IPE methodology and believes that the positive results obtained from this study substantiates the methodology's extensive capabilities.

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ACKNOWLEDGEMENTS l

-IDCOR would like to thank the Long Island Lighting Company and the following individuals of the Img Island Lighting Company for their major contribution to the evaluation and verification of the IDCOR Individual Plant Evaluation  ;

Methodology for Boiling Water Reactor Plants: John D. Leonard, Vice President of Nuclear Operations; Brian McCaffrey, Manager of Nuclear Engineering Support; Richard J. Paccione, Section Head Nuclear Systems Engineering; and the evaluation team members, A. D. Bunch; D. J. Kelly; T. G. I Pappas; and R. J. Travis.

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TABLE OF CONTENTS Section Page, ABSTRACT ................................................ 111

.0 TNTRODUCTION ............................................. 1-1 1.1 Background /Obj ective s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1 1.2 Scope and Limitations ............................... 1-2 1.3 Report Organization ................................. 1-3

.0 COMPLIANCE WITH THE METHOD ............................... 2-1 2.1 Introduction ........................................ 2-1 .

2.2 Information Used .....................................2-4 2.3 Exceptions to the Method ............................ 2-5 2.4 Resources Required .................................. 2-5 2.5 Pl an t De s c rip t ion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-6 2.6 System Dependercies ................................. 2-15 1.'O POMINANT CORE MELT ACCIDENT SEQUENCES .................... 3-1 3.1 Ov e rv i ev . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 - 1 3.2 Description of Accident Sequence Classes ............ 3-2 ,

3.3 Frequency of Dominant Sequence Contributors .,....... 3-2 to Each Type 3.4 To tal Core Melt Frequency . . . . . . . . . . . . . . . . . . . . . . . . . . 3-13 3.5 Summary ............................................. 3-15 1.0 CONTAINMENT PERFORMANCE ASSESSMENT ....................... 4-1 5.0 INSIGHTS DERIVED FROM THE INDIVIDUAL PLANT . . . . . . . . . . . . . . . 5-1 EVALUATION j 5.1 Commitments IntroductionCredited ........................................

in the Analysis ................ 5-1 5-1 5.2 i

5.3 open Design Itees ................................... 5-3 l 5.4 open Analytical Results ............................. 5-4 5.5 P ro c e dura l In s ight s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-6 6.0 CON C LU S I ON S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6- 1 APPENDIX A -

SUMMARY

OF PLANT SPECIFIC PROBABILISTIC ......A-1 RESULTS USED IN THE IPE METHOD APPENDIX B - DEVELCPMENT OF PLANT SPECIFIC DATA AFD........B-1 SYSTEM UNAVAILABILITIES APPENDIX C - PLANT SPECIFIC TEFRMAL-HYDRAULIC STLTIES . ....C-1 APPENDIX D - SYSTEM DEPENDENCIES ..........................D-1 APPENDIX E - EVENT TREES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . E-1 I

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LIST OF TABLES Table Title Page 3.2-1 Accident Sequence Classification ................................. 3-3 3.2-2 Summary of the Accident Sequence Subclasses (Plant Damage Bins)... 3-4 3.2-3 Summary o f the Dominant Ac cident Sequence . . . . . . . . . . . . . . . . . . . . . . . . 3-5 Frequencies That Lead to Core Melt (Fer Reactor Year) by Initiatcr and Class 3.4-1 Summary of the Dominant Accident Sequence . . . . . . . . . . . . . . . . . . . . . . . . 3-14 Frequencies by Initiator and Class D-1 Shoreham Matrix for Front Line Dependencies .......................D-2 on Support Systems D-2 Shoreham Matrir. f or the Suppert System . . . . . . . . . . . . . . . . . . . . . . . . . . . .D-4 Dependencies on Other Support Systems D-3 Shoreham Matrir for Identification of Corponent ...............D-6 Dependencies on General Support Functions (CFEERAL TRANSIENT)

D-4 Shoreham Matrix for Identification of Coeponent ...................D-11 Dependencies on Gereral Support Functions (SMALL LOCA)

D-5 Shoreham Matrix for Identificatien of Component ...................D-15 Dependencies on General Support Functions (MEDIUM LOCA)

D-6 Shoreham Matrix for Identification of Component ...................D-18 Dependencies on General Support Functions (LARGE LOCA)

D-7 Shoreham Patrix for Identification of Coeponent ...................D-20 Dependencies on General Support Functions (LOOP)

D-8 Shoreham Hatrix for Identification of Coeponent ...................D-24 Dependencies on General Support Functions (ATWS)

D-9 Shoreham Matrix for Identification of Corponent ...................D-29 Dependencies on General Support Functions (DC BUS FAILURE)

D-10 Shorehan Matrix for Identification of Cor.ponent ...................D-34 Dependencies on General Support Functions (LOSS OF SERVICE WATER)

D-11 Shorehar Matrix for Identification of Component ...................D-38 Dependencies on General Support Functions (INTERNAL FLOOD)

D-12 The Iden tification of Potential Vulnerabilities . . . . . . . . . . . . . . . . . . .D-40 Due to Instrumentation Unavailability During Postulated Severe Accident Scenarios

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ABSTRACT This repcrt provides a summary of the Industry Degraded Core Rulemaking Individual Plant Evaluation (IDCOR-IPE) method as applied to the Shoreham Nuclear Power Station (SNPS). This method was applied over a four-eonth period by an intensive effort of dedicated Long Island Lighting Company personnel.

Assistance was provided by Delian Corporation and Erin Engineering and Researca.

The effort was aided by the use of the Shoreham Level III PRA and by the fact that the SNPS plant and risk assessment served as a large part of the bare plant ans3ysis in the generic Individual Plant Evaluation method development. The methodology has been initiated in draft form to der.onstrate its usability and verify the approach. The IPE methodology was found to provide a way to search for and identify potential risk or core melt frequency outliers. The quantitative results do not appear to differ substantially (i.e., within a factor of two) from the SNPS PRA estimate of 5.5E-5 events per year for the core melt frequency calculation.

I The application of the method has developed several engineering insights of value in pctentially reducing an already Iow core damage frequency and public risk. However, no risk or ccre melt frequency outliers were found which would require irrediate action. The overall conclusion is that the Shoreham Kuelear Power Station's frequency of core damage is small. The Shoreham IPE f.eulated frequency of core melt is 8.5E-5 per year. Although this represent an increase over the 1DCOR baseline core melt frequency of 5.8E-5 it is not considered to be a substantial deviation. The SNPS IPE conclusions support the generic IDCOR conclusion that the core melt frequency is low and no risk " outliers" were

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found. Insights regarding procedures ano design attributes are described in Section 5 of this report.

Additional insights involve the methodology itself. It is concluded that the methodology does not employ a cookbook epproach that can be easily adopted by personrel not familiar with risk assessacnt techniques. However, it does provide a framework wherein a plant can be assessed in a concistent savner relative to the potential for inducing core datar.e or containment challenFe without expending the resourcee needed for a Level 3 PRA. In this regard the method is a significant step forward. It is expected that future effort to clarify the relationship between the question descriptien and the urderstanding available through risk arsessment experience will further enhance the methodology.

Future enhancement of the IPE method should also include seditionel

• documentation regarding the values utilized in the base plant quantification.

The results stated herein vould not have been generated in this time frame without access to and essistance from both the Shoreham PRA and the IPF methodology developer.

It is judged prudent for successful implementation that a single IDCOR fccal point be provided to address questions regarding the method feplementatien as individual utilities use the method. This will eliminate eeny of the open questions and wil1 provide a consistent applicction of the method quantification.

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1.0 INTRODUCTION

1.1 Eackground/ Objectives The Individual Plant Evaluation method has been applied to the Shoreham Kuclear Power Station in order to determine whether the core damage preven' tion and mitigation capability is similar to that assessed for the IDCOR baseline, given Shoreham's specific design, operational and maintenance procedures. This effort was aided by the existence of a Level III plant specific risk assessment and by the incorporation of limited portions of this risk assessment in the IPE methodology.

The primary objectives cf the study involve the assessment of risk significant features and a determination whether any design features or procedures associated with the plant contribute to produce risk

" outliers". The term " outlier" refers to a single accident sequence, or set of sequences, which dominate the overall core damage frequency and are of a frequency substantially higher than interim safety goals. The study has not resulted in the identification of any risk " outliers".

The IPE atudy has been performed over a four-month period by a staff of fo'ur experienced Long Island Lighting Company engineers and several part time participants. The staff of personnel included representation from systems engineering, electrical engineering, 1-1

operations (Shif t Technical Advisor) and safety analysis. In addition, support was provided by representatives of Delian Corporation, who participated in the development of the IPE method, and by representatives of Erin Engineering and Research, who have assisted in application of the methodology to the Peach Bottom plant.

The Individual Plant Evaluation method is an approximate approach, useful in the evaluation of risk characteristics, features and sensitivities. The method is still ur.dergoing refinement. However, this is censidered te be a minor drawback in terms of overall conclusions reached during the effort. It is believed that the future refinements in the metbed will primarily address the ease of use and application by the utility engineers.

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1.2 Scope and Limitatiers 2

The SNPS program has addressed all portions of the Individual Plant Evaluation mathedology. The Shoreham PRA has been useful as a source of descriptive design material of a risk assessment nature.

It should be emphasised, however, that the availability of the PRA has not been allowed to shift the effort from an independent 1

i evaluation to a synopsis of the previous risk study. A full IPE evaluation has been made.

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~The methodology is currently undergoing further development cnd

. refinement. It is anticipated that in the coming months additional text will be added to clarify the intent of the IPE questions for

,the benefit of apn-risk assessment personnel. This should represent i significant enhancement in the methodology. Howeyer, this limitation has not. prevented the plant evaluation from being successful as Delian Corp. provided interpretations of the questions throughout the process.

These improvements notwithstanding, LILCO believes the

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quantification effort will continue to require reasonably experienced PRA practitioners.

1.3 Report Organization The following sections of the report provide significant information on the applicatfen and results of the method. Section 2 discusses the compliance with the method end provides information of value to other utilities in developinF a program of plant implementation.

Section 3 summarizes the dominant sequences, their frequency, and overall affect. It is concluded that the Shoreham Nuclear Power Station falls within the IDCOR generic results. Section 4 presents the containment performance assessment and quantifies the consequences associated with each potential accident class. Section 5 provides a discussion of insights derived from the Individual Plant Evaluation method. These insights are believed to represent a i- 13

significart b:n3 fit of p3rfcrmicF this study cnd may hsva valus to other utilities. Section 6 summarizes the conclusf ons of the study and provides a comparison of plant specific results with IDCOR conclusions. Appendices A through D provide sustaries of plant specific evaluations, data, and studies. Appendix E presents the event trees that were utilized for the Shoreham IPE.

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2.0 005.?lIANCE VI!!! THE METh0D 2.1 Introduction The accident sequence evaluation methodology was applied at the

" detailed engineering level" as defined in Section 3 of the IPE Methodology. Shoreham is very similar to the IPE 3aseline plant.

The availability of support system fault trees in the Shorehar PRA did not require the development of new support system functional fault trees and the IPE trees were used with some redification.

The method was primarily implenented by two systems engineers, one with previous Shoreham licensing experience, one electrical engineer end one operations engineer. Each initiator and plant system identified in the IPE was assigned to ens of the systems or electrical engineers. Fach section in Appendix D of the IPE methodology was completed independently. The operations engineer provided support for all the sections, j Using the Shoreham PRA system descriptions as a basis, an attempt to resolve the questions in Appendix D was made. Any additionel information consulted in response to the questions was referenced in the reply and/or included as part of the system notebooks. This inclu.ded such iteer as FSAR sections, Technical Specifications, ,

station procedures, correspondence, flow diagrams, logic and elementary drawings and calculations. The PRA was primarily used as 2-1

a system rasourca dscument cnd th3 cystem functional fcult tross were not incorporated into the rethodology. Any inforr.ntion taken from the PRA ves verified es current. General system walkdowns were not performed as part of the IDCOR effort because the team menbers are located at the plant site, and during their norral daily activities they have become very familitr with the plant design.

However, specific design features such as emergency switchgear ventilation and the 69 KV ruitchyard bypass capability were reviewed in the field. Due to the developmentel nature of the method many questions were unclear in their intent and Delian Corp. was consulted daily for clarificatien. The combined task of coupleting Appendix D and developing system notebooks required extensive manpower. This comprised approximately eighty percent of the totc1 effort.

Although the Appendix D questions addressed specific cencerns about the operating procedures, a thorouFF review of the procedures, especially the emergcucy procedures, is essential for a clear understanding of the system interactions and to identify insights.

The majority of insights found through the r.ethod were identified in the procedures.

A reliability engineer, working part tiac, reviewed the IDCOR Appendix A initiators and CoFpared this Against the Shoreham PRA and the Brookhaven National Laboratory (BNL) review of the SNPS PRA.

The initiator frequencies from the three documents generally agrec l

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and the IPE numbers were typically used in the quantification. The loss of off-site power initiator was modified to incorpcrate LILCO specific grid data. Additicnally, the PRA event trees were used for the flooding and water level instrurentation leakage initiators.

With the completion of IDCOR Appendices A, B and D of the IPE l

methodology the four full time LILCO engineers, two Erin and one Delian erployee met for one week to quantify the trees. Appendix D l

! vas completely reviewed by the group and the remainirg questionr.

from Appendix D vere resolved. The questions requiring action and other differences from the baseline were reviewed again and the trees were modified accordintcly. Although Shoreham is similar in many design details to the baseline, the quantification required l

personnel with substantial probabilistic risk assessment knowledge, i

! as provided by Erin and Delian.

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( During this quantification the group examined issues such as loss cf service water, venting, and room cooling and generally eFccined the systems beyond the IDCOR questions. The sequence event trees were then reviewed for completeness to ensure all sequence dependencies

( on the systems had been evaluated and the dominant core celt accident sequences were identified.

l An approximate source term nethodology for boiling water reacters was not available during the quantification effort, and will be addressed in a future supplement to this report.

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2.2 Inforestion Used The application of the IPE methodology to the Shoreham Nuclear Power Station required an extensive review of the existing plant basis.

This information included: .

o The existing SNPS Level III Probabilistic Risk Assessment (PRA) o The Emergency Procedure Guidelines (EPCs) o The FSAR o Brookhaven National Laboratory (BNL) review of the SNPS PRA (NUREG/CR 4050) o The Operating and Emergency Operating procedures including draft Escrgency Procedures which incorporate Revision 3.0 of the EPGs.

o The centro 11ed design documents including P& ids, electrical diagrams, and eleaantaries, o The Safety Evaluation Report, licensing responses to the NRC and l other commitment documents generated as a result of Suffolk l County contentions.

o System Descriptions and Operator Lesson Plans

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o S. Levy Inc. Report No. $221, " Review of the Shoreham Water Level Measurement System".

o Station operating logs including LER, Master Preventative Maintenance Jog, Report cf Abnormal Cenditions and the Limitirg Condition of Operation log.

o Technical Specifications 2.3 Exceptions to the Method There were no exceptions taken to the methodology during this evaluation. Given the developmental nature of the documentatien

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associated with the method, it is anticipated that future revisions will create some methodological refinements. These may be ,

interpreted as exceptions, however it is concluded that the method,

! as currently developed, is sufficient for the determination of plart l

corpliance with the IDCOR ebjectivec.

2.4 Resources Required As previously described, the assessment involved four full-time engineers. These engineers represented 26 years of overall nuclear i

! plant engineering experience with 13 years of Shoreham-specific experience. Electrical engineerinr., syscars engineering and plant operations (Shift Technical Advisor) were represented. In addition, 2-5

several part-time personne), primarily from safety analysis, were necessary to support the effort. The services of Erin Engineering and Research Incorporated were utilized to further support the

. effort in terms of planning, management, question interpretation, and assistance in the ovarall quantification. Representatives of Delian Corporation provided interpretations of various questions and supplemented the methodology. In total, approximately two man-years of effort have been applied to this program.

2.5 Plant Description The Shoreham Nuclear Power-Station (SNPS) was designed by Stone &

Webster. It is a single unit 846 MWe power plant with a General Electric Boiling Water Reactor (FWR-4) and a Mark II Pressure Suppression Containment. Long Island Lighting Cor.pany (LILCO) is the owner and operator of the Shoreham facility. The Shoreham site is located in the Town of Brookhaven, Suffolk Country, New York, on the North Shore of Long Island approximately 50 miles east of New York City. Construction of the plant it complete and a five percent power license has been granted by the NRC, Fuel load commenced in December of 1984 and initial criticality occurred in February, 1985. Five percent power testing was completed in October, 1985. Full power licensing has been delayed pending resolution of the emergency pisaning issue.

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The normal and safety related systems at Shorehar. are designed to fulfill four primary functions: reactor shutdown, prinary syster 1

pressure control, coolant injection to the RPV, and decay heat reeeval. The systees available to perfore these functions are described below. -

Reactor Shutdown Several systems combine to provide redundant and diverse r.eans of inserting negative reactivity into the core: the Reactor Protection System (RPS), the Alternate Roc Insertion (ARI) System, the Control Rod Drive Systen (CRD), and the Standby Liquid Control System (SLC).

The RPS generates a rapid automatic scram signal in time to prevent excessive fuel damage following abnormal transients or accidents.

The ARI system provides a diverse backup to the RPS. Both systens function to vent the scram air header which open the air operated l

scraa valves on the CRD Hydraulic Control Units (HCUs), allowing for l

rapid insertion of control rods into the reactor. In the unlikely event that a sufficient number of control rods cannot be inserted, the SLC system is manually initiated. The system is diverse to the CRDs and brings the reactor suberitical by the injection of a liould poison (sodium pentaborate) into the reactor.

! Primary System Pressure Control i

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Eleven safety relief valves (SRVs)are mounted on the main steam lines inside containment. These valves have a combined capacity l

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large enough to prevent excersive pressure in the primary system during any abnormal transients.

Coolant Injection to the RPV The autcastic systems available for restoring the RPV water inventory during abnormal transients include the Feedwater/ Condensate System, Reactor Core Isolation Cooling (F.CIC) and the Emergency Core Cooling Systems (ECCS).

The feedwater/cordensate syster provider coolant makeup over the full range of resetor. pressure. The feedvater pumps are turbine driven while the cendensate pumps are powered by the pJant norral

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electric power systen. The power conversion system (PCS) has a 251 bypass capacity.

The RCIC system provides rakeup water to the reector vessel when the vessel is isolated. The RCIC system uses a stean-Criven turbine pump unit and opera:es automatically to esintain adequate water level in the reactor vessel for normal reactor shutdownc. The RCIC a

system electrical requirements are supplied by the 125 VDC system, i

The ECCS is comprised of four systems that maintain adequate core cooling in the event of a loss of reactor coolant or other transient demands. The syrtens are:

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! o ~.High Pressure Coolant Injection (HPCI) l l

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o Automatic Depressurization Syrtem (ADS) o Core Spray (CS).

o Low Pressure Coolant Injection (LPCI), an operating mode of the Residual Heat Removal (RNR) system.

~

The EPCI systes"provides and maintains an adequate coolant inventory inside the reactor vessel to limit fuel temperature which may result froe postulated sr.all breaks in the primary system. A high pressure system is needed for erall breaks and isolation transients because the reactor vessel depressurires slowly, preventing low pressure systems from injecting coolant. The HPCI system includes a purp and booster pump which cte driven by the same turbine, powered by reactor stear. The systeri is designed to accomplish its function on a short-term basis without relfance on plant auxiliary pcwer supplies other than the 125 VDC power supply.

The ADS rapidly reduces reactor vessel pressure in situations where the high pressure systems fail to maintain the reactor vessel water level. The depressurization provided by the system enables the 3cw pressure ECCS to deliver cooling water to the reactor vescel. The ADS uses seven of the eleven esfety relief valves. The ADS valves open ,after a 105 second time delay if the water level in the reactor vessel falls below a pre-selected value (Level 1) and a low pressure ECCS pump is operating. This is to ensure that adequate coolant 1

i i

2-9 l

l l

will be available to r.41ntain reactor water level af ter the depressurization.

The CS system consists of two independent, pump loops that deliver cooling water to spray spargers over the core. The. system is actuated by conditions indicating that a breach exists in the primary system, but water is delivered to the core only after reactor vessel pressure is reduced. This system provides the capability to cool the fuel by spraying water onto the core.

LPCI is an operating mode of the RHR system but is discussed here because the LPCI mode acte as an engiticered safety feature in conjunction with the other emerger.cy core cooling r:ystems.. LPCI uses the pump loops of the RHR to inject cooling water into the reactor vesse3. The syster. is actuated by conditions indicating a breach in the primary syster., but water is delivered to the core only after reactor vessel pressure is reduced.

Decay Heat Removal The RHR syster. is capable of several Podes of operation, one of which is LPCI (discussed above). Four of these operating modes are for the purpose of removint decay heat from the reactor and containment: the suppression pool cooling mode, the steam condensing mode, containment sprays and the shutdown cooling mode. The RER system consists of two independent loops. Each loop has two pumps 2-10

end en2 hert exch:ng2r cooled by ths Rsacter Euilding Servico Water System.

The suppression pool cooling mode is used to reduce the tr.1perature of the suppression pool following discharge through, any of the SRVs or e 10CA. Suppression pool water is circulated through the RER heat exchangers and returned to the pool. .

l Steam condensing is a mode of RER where reactor steam is directed from the HPCI turbine supply line to the RPR heat exchangers where l

it is cendensed and returned to the reactor via the RCIC systen.

l l

l Tor post-accident conditions, the containment spray mode pumps water from the suppression pool through the RER heat exchangers and into the spray headers located in the drywell and suppression charber areas.

The shutdown cooling rode is used during reactor shutdown when the primary system pressure drops below 135 psig. Reactor water is circulated through the RER heat exchangers and returned via the recirculation system piping to the RPV.

Electric Power i

The Shoreham electric power system censists of two independent off-site power sources; three on-site emergency electric power 2-11

divisions, each supplied by its own diesel generator; and three corresponding 125VDC divisions, each with redundant. battery supp1fes. The successful operation of any two emergency diesel

, generators and either division I or !! of the 125VDC system is adequate for suppling pewer for all safety functions to bring the reactor to cold shutdown. The refety systems at the plant are electrically separated in such a way that redundant components designated "A" and "B" are powered by the division I and 17

~

electrical systems, respectively. The divisien 111 power supplies are used in those systems where there are more than two redundant

, components, such as the RPR or service water systems.

Service Water System (SWS) 1 The Reactor Building SWS is the reans by which all heat loads from primary and secondary containn.ent are transfatred to the environment. The system consists of four motor-driven, centrifugal pumps, four motor-operated strainers, and necessary piping, valves, and instrumentation. System piping material is generally copper-nickel for compatibility with sea water.

Each pump, located in a separate bay in the intake structure, has a capacity of 8,600 spa at 63.7 psi and takes a suction from the I screenwell downstress of the traveling water screens. The capacity

,of each pump is 50% of the required flow during a " Design Basia ,

Accident" and 33% of the required flow for normal operational and shutdown conditions.

2-12 1

The common discharga hPcdsr is provid:d with two motor-sparcted valves which are automatically closed upon receipt of a LOCA signal to isolate the header into two sections. The separation ef the headcr into two rections splits the service water into two independent trains, each with two pumps. Each train supplies i

redundant nuclear safety-related equipment, ensuring that if a i single failure in the service water system were to occur, at least one complete set of redundant nuclear safety-related equipment will be supplied with the necessary service water flow.

The two redundant supply lines leave the intake structure and pass underground to the reactor building where they indeperdently penetrate the secondary containment. Prior to entering the secondary containment, each line branches to deliver service water to the diesel generator rooms and the control room building.

Inside the secondary containment, each service water line branches

- to supply one of two reactor building closed cooling water heat exchangers and one of two residual heat removal heat exchangers.

1 Each service water line also provides a source of er.ergency service  !

water to the ultimate cooling connection and the spent fuel pool.

The service water discharge lines are monitored for radiation indicating heat exchanger leakage. A control room alarm will generally result in operator action to manually isolate the affected heat exchanger in order to prevent an excessive release.

s 2-13

Reactor Building Standby Ventilation System (RBSYS)

The RBSYS is designed to assure that the reactor building is maintained at substacepheric pressure and channels building exhaust through a series of filters. In this way, radionuclide releases through the secondary containment can be minimized. The subatmospheric pressure assures that any leakage flows inverd, preventing an uneonitored release, f

other Features In addition to the safety systems described above, Shereha= includes several design features which enhance the plant's capability for accident sitigation. Specific items which have been considered in the IPE avalection include the fo12cwing:

o Turbine Buf1 ding / Reactor Building Service Water System (SWS) crosstie header e Ultimate core cooling connection from the SWS o Water Fire Protection System connection to the RER/LPCI syster i

o Analog Trip System (ATS) for reactor water level instruments 7

2-14

• o ADS parnissiva en low rccctor watcr levo 3 culy (high dryv211 pressure not required) o Alternate Rod Insertion (ARI) and Recirculation Pump Trip (RPT) o Nitrogen supply for control valver inside containment o on-site " black-start" gas turbine o Symptos based energency procedures o Reacter Pedestal /CRD Room design (affects Appendix T ef the IPE).

2.6 Systee Dependencies The evaluation of system dependencies was perfermed as described in Appendix C of the Individual Plant Evaluation methodclogy. The dependency of initiators upen support systers, of front line systems upon support systems, and of support systere upon other support systems are exhibited in tabular form in Appendix D of this report.

4 2-15

i 3.0 DOMINANT CORE MELT ACCIDENT SEQUENCES 3.1 Overviev l The dominant core melt accident sequences for the Shoreham IPE' arc i

! primarily associated with anticipated transient initiators, i.e.,

turbine trip, loss of condenser vacuum, loss of off-site power and Inadvertent Opening of a Relief Valve (IORV) plus Stuck Open Relief Valve (SCEV). These transient initiators and the loss of feedwater ATWS, in conjunction with the associated sequences account for 67

^

percent of the total core melt frequency.

Percentage Sequence of Total Core Initiator Frequencies Melt Frequency Turbine Trip 2.1E-5 25 Loss of Condenser Vacuum 1.3E-5 15 Loss of Off-Site Power 1.1E-5 13 10RV and SORY 6.1E-6 7 ATVS with Loss of FW 6.0E-6 7 67 Each initiator can lead to several different types of RPV and containment conditions dependent upon subsequent system failures.

As an aid, the event trees utilized for the Shoreham IPE are 1

( presented in Appendix E of this report.

3-1 i

r.

p.

3.2 rescription of Accident Sequence Classes.

The methodology presents five accident sequence classes. Class I represents a transient with coolant makeup unavailable. Class II represents a transient with less of containment heat removal.

Class III represents a LOCA with loss of adequate inventory makeup.

' Class IV represents a transient with failure to scrar. and the unavailability of effective SLC injection and Clase V represents a LOCA outside containment with c failure to isolate and loss of ECCS, Classes I, Il and III are further divided into subclasses. See Tables 3.2-1 and 3.2-2 for further clarification.

The IPE binning method is identical to the Shoreham PRA.

See Table 3.2-3 for a summary of the dominant accident sequence frequencies by initiator and the accident sequence classes.

3.3 Frequercy of Dominant Secuences Contributors by Initiator to Each Type and Importance.

The accident sequences which are calculated to lead to core melt cover a broad spectrum of possible events. These very 3nw frequency sequepces can be summarized both by the type of accident sequences and the type of initiator. The following summary identifies the distribution of core melt frequency among accident sequences.

4 3-2

TABLE 3.2-1 ACCIDENT SEQi)ENCE CLASSIFICATION ACCIUtni REpitESENTATIVE Mf751 CAL BASI $ SYSTEM LEVEL CLASS CONTRIBUTING EVENT SEQUEIICE SEQUElICE FOR CLASS DESIGNATOR FOR CLASSIFICATION Fuel will melt rapidly if cooling Transients involving loss of Transient with coolant

! Class I (Cg ) makeup unavailable systems are not recovered; contain- inventory makeup; smeII LOCA events ment intact at core melt and at involving SRV actuation with isss initially low pressure; highest . of inventory makeup; transients  ;

1

- probability release pathway is f' rum involving less of scram function' the vessel to the suppression pool and inability to provide sufficient

- coolant makeup Transients or LOCAs involving Toss Transient witia. loss of

'. Class 11-(C2) Fuel will melt relatively slowly of containment heat removal; residual heet-receval due to louer decay heat level if '

cooling systems are not recovered; in advertent SRV opening accidents

' containment is breached prior to with inadequate heat reaeval

' Y core melt; highest probability capability '

l " e release pathway is from the vessel to the_ suppression pool _

Large LULn with loss Large and tiedium LUCAs with Class III (0 3) Fuel will melt rapidly 1f cooling insufficient coolant makeup; small of los pressure LCCS systems are not recovered; contain-

/ ment intact at core melt, but at and medium LOCAs with failure of initially high internal pressure; the SRVs to actuate and long-term involves a release from the vessel loss of inventory makeup; #pV to the drywe11 failures with insufficient coolant makeup ruel wfil melt rapidly f f cooling Transients involving loss of scram Tronstent with fa11ere

Class IV (C 47 function and loss of contalmeent of RPS and* failure of systems are not recovered; contain- heat removal or all reactivity SLCS ment fails prict to core melt due

' l to overpressure; highest probability control; transients with loss of -

release pathway is from the vessel scram function followed by rapid ,

to the suppression pool depressurization Fuel wHl mit rapidly if cwHng s u tside containment with m fa meta steam Class V (C57 l systems are not recovered; contain- insufficient coolant makeup to lines with failure of core; interfacing system LOCAs with NSIV closure and loss Iment failed from initiation of insufficient coolant makeup of ECCS accident due to equipment failure; involves a release pathway from the vessel which bypasses the L__ lcontainnent_

i ,

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' TABLE 3.2-2

SUMMARY

OF THE ACCIDENT SEQUENCE SUBCLASSES i

(PLANT DAMAGE BINS)

'AGGIDENT EXAMPLE SUSCLA$$ OEFINITION Of NATOR TQUA A Accident 5equences Involving Loss of CLA55 I Inventory Makeup in which tw Reactor Pressure Remains Nish T gQUV 5 Accident 5equences Involving a Loss of Off-Site Power and Loss of Coolant Inventory Makevo TT'CMQu C Accident 5equences Involving a Loss of Coolant Inventory Induced by an ATWS Seavence TQUV D Accident 5equences Invoiving a Loss of Coolant Inventory Makeup in which Reactor Pressure has been Successfully Reduced to 200 psi.; Accident Sequences Initiated by Common Mode Failures Disabling Multiple Systems (ECCS) Leading to Loss of Coolant Inventory Makeuo T Dc2DC3 E

Accident sequences caused by comon Mode D Failures which Result in Multiple Frontline System Failures with the Reactor at High Pressure TW

- Accident bequences Involving a Loss of CLA55 JJ Containment Heat Removal R

A Accident 5tquences Leading to Core CLA55 III Vulnerable Conditions Initiated by Vessel Rupture where the Containment Integrity is not treached in the Initial Time Phase of the Mcident 5 3QUI 5

Accidiiit sequences Initiated or Resulting in Small or Medium LOCAs for Which the Reactor Cannot be Depressurfred AQuv c Accident 5equences Initiated or Resulting in Medium or Large LOCAs for which the _

Reactor is at low Pressure AD p Accident 5equences which are Initiated by a LOCA or RPV Failure and for which the Vapor Suppression System in Inadequate, Cha11eng.

i ing the Containment Integrity _

TCU TM2

- Accident 5equences Involving Failure to ,

CLA55 IV Insert Negative Reactivity Leading to a Containment Vulnerable Condition Due to High Containment Pressure _

CLA55 V

- Unisolated LOCA Dutside containment 3-4 e'

Tchla 3.2-3 SUMMART OF THE DOMINANT ACCIDENT SEOPENCE FREQUENCIES TF.AT LEAD TO CORE MELT (PER REACTOR YEAR) BY INITIATOR AND CLASS Event Initiator Sequence Class Class I Class II Class III Class IV Class V Totals Transients:

Turbine Trip 2.1E-5 1.5E-7 --- --- ---

2.1E-5 Panual Shutdown 6.2E-7 6.1E-7 --- --- ---

1.2E-6 MSIV Closure 3.4E-6 1.8E-7 --- --- ---

3.6E-6 Less of Feedwater 4.3E-7 1.5E-8 --- --- ---

4.5E-7 loss of Condenser Vacuum 1.2E-5 6.9E-7 --- --- ---

1.3E-5 Loss of Offsite Power 1.1E-5 9.6E-8 --- --- ---

1.1E-5 10RV & SORY 5.7E-6 2.4E-7 1.1E-7 --- ---

6.1E-6 Subtotal 5.4E-5 2.0E-6 1.1E-7 5.6E-5 LOCA:

Large LOCA ---

9.2E-S 1.3E-7 7.0E-9 ---

2.3E-7 Medium LOCA ---

3.6E-8 3.9E-7 --- ---

4.3E-7 Small I.0CA 6.9E-7 1.4E-6 7.0E-7 --- ---

2.CE-6 LOCA Outside Containment ---

4.5E-9 --- ---

9.0E-F 9.5E-8 Reactor Pressure vessel LOCA --- ---

3.0E-7 --- ---

3.0E-7 Subtotal 6.9E-7 1.5E-6 1.5E-6 7.0E-9 9.0E-8 3.8E-6 ATWS:

Turbine Trip 2.CE-6 ---

1.3E-9 1.1E-6 ---

3.1E-6 MSIV Closure / Loss of Condenser Vacuum 1.6E-6 ---

1.0E-9 1.8E-6 ---

3.4E-6 Loss of Offsite Power 1.1E-7 --- ---

8.6E-6 ---

2.0E-7 IORY 1.4E-6 ---

4.3E-7 1.8E-6 Loss of FW 4.5E-6 ---

3.3E-9 1.5E-6 ---

6.0E-6 Subtotal 9.6E-6 5.6E-9 4.9E-6 1.5E-5 l Other Trensients:

Caces Involving the Release of Excessive Water 3.1E-6 7.8E-7 ---

1.7E-10 3.9E-6 Cases Initiated by the Loss of DC Power Bus 2.9E-6 1.2E-8 ---

4.4E-6 ---

3.0E-6 Loss of Instrument N y 1.1E-7 3.7E-9 ---

2.5E-6 ---

1.4E-7 Cases Invelving an Upset Condition with the Rx Water Level Measurement System 2.4E-6 1.2E-7 ---

1.9E-7 ---

2.7E-6 Manual Shutdown due to high Drywell Temperature 1.4E-7 --- --- --- ---

1.4E-7 Loss of Service Water Initiated Events 2.1 E-8 5.3E-7 --- --- ---

5.5E-7 Subtotal 8.7E-6 1.4E-6 2.6E-7 1.0E-5 TOTAL 7.3E-5 4.9E-6 1.6E-6 5.2E-6 9.0E-8 8.5E-5

• Note: Totals ray not match due to round off errors.

3-5

For Clast 7: Loss of Coolant Inventory Makeup (86% of the totc1 cort sielt frequency) 29% due to Turbine Trip 16% due to Lors of Condenser Vacuus -

15% due to Loss of Offsite Power 8% due to 10RV and SORV 6% due to Loss of Teedwater ATVS 5% due to MSIV Closure 47 due to Internal FloodinF 17% due to remaining luitiators For Class II: Containment Challenge Prior to Core Melt (6% of the total ccre melt frequency) 297 due to small LOCA 16% due to Internal Flooding 14% due to Loss of Condenser Vacuun 127; due to Manual Shutdown 5% due to IORV and SORV 24% due to remaining initiaters 3-6

e For Class III: LOCA Induced Loss of Coolant Inventery (2% of the total core melt frequency) 44% due to small LOCA l

24% due to mediva LOCA 19% due to RPV LOCA 8% due to large LOCA 5% due to remaining initiators For Clars IV: ATWS Induced Containment Challenge (6 of the total core melt frequency) 35% due to MSIV Closure / loss of Condenser Vacuun 29% due to Loss of Feedwater 21% due to Turbine Trip 8% due to IORV and SORV 7% due to remaining initiators For Class V: Direct Primary Containment Bypass with a Break in the i Reactor Building (0.1% of the total cere melt frequency) i l 100% due to LOCA outside containment l

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l 3-7

the evaluatien has idsntified c nuabar cf instanecs whsre the qurntification of the system unavailability represents an important input to the analyses. Changes to these inputs can result in comparable chenges to the overall perspective on core melt frequency and the distribution asong accident sequence types.. The principal systems which have been identified are discussed below:

Scras System: As identified in the methodology, the scram system represents a single systen with a high level of redundancy, but one -

which also can have a profound effect on the plant response following a transient. The point estimate quantification for this system is highly uncertain; however the use of the mean value tends to make the point estimate appear relatively high. This is a generic ir. sue. LILCO has committed to the NRC rule on ATk'S and will, therefore, incorporate additicnal mitigating features in the event of scram system failure to ensure adequete negative reactivity insertion. These features include an 86 gym equivalent SLC and improvements to the ARI system. These modifications, as well as the existing SNPS RPT design, are were fully discussed in Appendix A of this report.

These design features, in conjunction with the SNPS specific ATWS E0P result in a decrease in the calculated ATWS frequency. In addition, if the scram system common mode failure rate has been conservatively estimated (as believed), then the importance of the Class IV accident sequenecs will decrease, possibly making them non-contributors to the core melt frequency.

3-8

. ADS Inhibit If th3 scrat failura prcb bility is clocaly approximated, then one of the plant fectures which can assist the operator in maintaining adequate ritigatice is the prevention of inadvertent ADS during SLC injection. Shoreham has installed an ADS inhibit switch to prevent steh an occurrence.

9 Containment Ventina: As a last resort accident mitigation measure, Shoreham has included the operation of a wetwell vent to allow containment pressure relief via the wetwell purge lines. This last resort feature can effectively r.itigate long tern loss of containment heat removal accidents (i.e., Class II) or can effectively reduce radionuclide releases for cere melt accidents by providing a " scrubbed" release. CNot applicable to Class IV sequences.)

Diesel Generator: One of the highest calculated frequency accident sequences (1,1E-5/yr.) identified for Shorehau is that re3cted to Loss of Offsite Power and Station B3ackout. For these sequences the diesa: generator's relicbility is a key feature in the mitigation i assessment. Currently, a rather high common mode failure of the diesel Eenerator is being used. This common mode failure probability is difficult to develop and ray prove to be

conservative. In addition, the Shoreham site currently has extensive design features which could provide emergency backup AC

~

power in the event of a complete Station Blackout. These design featuree include:

3-9

o Black Start Gas Turbine o Three new Colt Diesels housed in a separate building from the qualified TDI Diesels o Four 2.5 MW skid mounted diesel set.

l o Connections to the normal buses which can bypass the 69KV l

switchyard.  ;

While the calculated frequency / core melt associated with LOOP and Station Blackout is judged sufficiently low, the above additionci design features, which are not included in the quancification, will also further decrease the caleplated frequency. ,

Batteries: In the event of a Station Blackout, the accident can bc effectively mitigated using the turbine driven RCIC or HPCI systems.

These systems require DC control power and, therefore, will be effective as long as DC power from the station batteries is

-available. With load shedding, LILCO calculates that the batteries are capable of effective operation for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The quantification includes a small benefit for operation beyond 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> into a Station Blackout (i.e., conditional success of 0.5)

High reliability of the battery systems under Station Blackout conditions could result in a reduction in the Station Blackout induced core melt frequency by a factor of two.

3-10 4

0 HPCI/RCIC/Feedwater: The coolant makeup systems which are generally available to mitigate transient induced sequences and small LOCAs are the feedwater, HPCI, and RCIC systema. These rystems are capable of core injection over the whole range of RPV pressures.

The reliability of these systems is influenced by a, wide variety of effects such as:

o Procedures / training o Isolation signals o Maintencoce/LCO requirements e Hardware availability Each of the first three ir explicitly included in the plant specific Shoreham IPE. Hevever, the hcrdware unavailability it based upen generic data because of the limited Shoreham operating tistory.

RHR: Containment heat removal is a relatively long term challenge (approximately 10-24 hours). The redundant capability of the RHR i

and service vater provides a syster with a high degree of

^

ra21 ability. In addition, the extended time over which it can be unavailable allows a significant opportunity for system repair. At Shoreham, there are also diverse containment heat removal options, i.e., the PCS and containment venting.

Service Water: A single system that provides varying degrees of support for many front line systems and other equipment is the 3-11

o service water system. The dependency matrices developed for Shoreham indicate the following:

o Direct dependence of system on SW:

- Diesel Generator .

- Drywell coolers

- Reactor Building local room coolers

- RECCW and, therefore. CRD seal cooling I o Partial dependence:

- LPCI/CS/hPCI/RCIC - These systens are judged operable without service water, using only natural circulation cooling in the Reactor Building Because Shoreham may be less sensitive to the unavailability of service water than other plants, the net result is a relatively small calculated core celt frequency associated with service water i

unaveilability.

CS-LPCI Injection Valve Testing: The testing of the CS and LPCI injection valves is truly a trade-off in the calculation of core melt frequency and public risk. The two opposing beneffes are as follows:

o Frequent testing of the CS/LPCI valves at pewer and pressure would rer.uit in a higher confidence in the waive operability.

3-12 i

I o Less frequent testing, i.e., during refueling outages, would result in a decreased probability that hardware failure or hur.an error would cause overpressurization of the low pressure piping outside of primary containment.

Because of the high reliability of the low pressure ECCS, frequent injection valve testing is judged to be a small benefit. On the other hand, the avoidance of overpressurizing the flow pressure pipe is also found to be a potentially small contributor to core melt frequency, but one with relatively high potential consequences.

Given the trade-off, LILCO has chosen to minimize the probability of the higher consequence events, i.e., Class V LOCA outside containment by designating valve testing during refueling outages.

3.4 Total Core Melt Frequency The overall total core melt frequency has been estimated as 8.5E-5 per year. This is clearly within the 1DCOR range of acceptability and is similar to the more detailed examination provided in the SNPS PRA (5.5E-5 per year). The Shorehaz 7PE total core melt frequency does not represent a significant increase over the IDCOR baseline frequency of 5.8E-5 per year. Table 3.4-1 presents the total core melt frequency broken down by class.

As discussed in Section 3.3, the contributions to the total core melt frequency due to ATWS and LOOP are believed to be conservative.

3-13

)

Table 3.4-1

SUMMARY

OF THE DOMINANT ACCIDENT SEQUENCE FREQUENCIES

• BY INITIATOR AND CLASS Sequence Event Initiator Class IV Class V Totals Class I Class II Class III Class 2.0E-6 1.1E-7 --- --- 5.6E-5 Trannients 5.4E-5 1.5E-6 1.5E-6 7.0E-9 9.0E-8 3.CE-6 LOCAS 6.9E-7 5.6E-9 4.9E-6 --- 1.5E-5 w ATNS 9.6E-6 ---

Other 2.6E-7 --- 1.0E-5 Transients 8.7E-6 1.4E-6 ---

4.9E-6 1.6E-6 5.2E-6 9.0E-8 8.5E-5 Total 7.3E-5 6 2 6 0.1 Percentage 86 of Total

3.5 Summary Examination of both the total core telt frequer.cy (8.5E-5/yr.) and the makeup of the total cora melt frequency in teres of type of core melt accidents (e.g. classes) leads to the coriclusion that neither the total frequency or the character of the accident sequencen represent substantial differences from those examined in the IDCOR evaluction and reported in the Technical Summary Report (1984).

l l

l 3-15 l

4.0 C0FTAINMENT PERFORMANCE f.9SESSMENT .

The Containmert Performance Assessment will be provided in a supplettent to i this report.

l 9

m 9

I 4-1 i

5.0 INSIGHTS DERIVED FTJW THE INDIVIDUAL PLANT EVALUATION 5.1 Introduction The application cf the IDCOR IPE methodology uses point estimate quantification of the system unavailabilities to determine e realistic assessment of core zelt frequency. The items presented in this section may have only small quantitative impact on this evaluation; however, it is LILCC's judgement that they should be resolved to minimize risk to the public cnd the plant. These iters are not censidered " outliers", but rather represent introvements to desigr and procedures as well at enalyses to confire asrumptions which can provide some small incremental increase in plant safety.

The open items conrict of commitments credited in the analysis (5.2), open design items (5.3), open analytical teruits (5.4) and procedural insights (5.5). Each of these items is discussed herein.

5.2 Commitments Credited in The Analysis The Shoreham Euclear Power Station was assumed to be a nature plant (i.e., operating past the second refueling cycle) for the purpose o' f

, event tree quantification using the IDCOR sethodology. Therefore.

l licensing commitments that will be taplemented during the first and second refueling cycle have been credited in this evaluation. These l commitments are listed below:

l l

5-1 i

1

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

1) The Main Steam Isolation Yalve (MSIV) reactor low 3evel isolation setpoint will change from Level 2 (-38 inches) to Level 1 (-132.5 inches) per SNRC 816 and 893 (letters sent to the NRC on the Shoreham docket).

2) A manual initiation capability and seal-in logic will be provided for the existing Alternate Rod Insertion Syster per LILCO letter, SKRC 1205.

3) The Standby Liquid Control System will utilize two pump operation (86 spm, equivalent) to confore to the finel ruling on ATWS (10CFR50.62) per LILCO letter, SNRC 1205.

4) The High Pressure Coolant Injection (HPCI) exhaust check volves will be changed from the swing check design to lift check valves. This modification is schaculed for irplementation during the first refueling cutage. 71.e HPCI system unavailability was not increased for the HPCI check valve failure identified in Licensee Event Report 85-051.

5) The Core Spray System injection valve low pressure permissive switch will change from differential pressure across the injection valve to reactor pressure per LILCO letter, SNRC 925.

5-2

5.3 open Design Iter.s Open design items are assumptions that were made regarding system design capability during the event tree quantification. These assumptions were necessary due to the unavailebility of required data (within the time frame of this study) to verify system operability under certain conditions er planned design changce, not yet implemented. Assumptions and open iteer are listec below:

1) The MSIV accumulators can keep the HSIVs open for approxitately 30 minutes followinh en isolation of the niticgen supply system on a LOCA signal. In addition, the accurulators are considered to be sufficiently leak tight to allev FSIV reopening within this time frame. Review leak testing requircL.ents.

2) Primary Containment venting vill be done by crening 4" and 6" purge and vert lines in the Suppression Chamber, if Drywell pressure reaches or exceeds 60 psig (according to the SNPS draf t l emergency procedure). Confirm final procedure venting

, requirements.

3) The hypochlorination system will be modified and/or bot water treatment will be utilized to effectively prevent heat exc;ianger fouling and other effects due to mussel intrusion. Confirm syster rodifications that are presently ongoing or planned.

5-3

4) Inferr.ation Netice 83-08, which describes a potential probler

, pertaining to the premature degradatior or failure of safety-related DC control corponents, caused by elevated DC control voltage, will be formally addressed. A preliminary review of this issue did not indicate any poten.tial problems at Shorehen. Confirm that review is completed.

5) Although a calculation is available that demonstrates a station battery life of 24 heurs during a station blackout ($50), the lent shedding assumptione therein do not appear to be completely reflected in the SB0 emergency procedure. LILCO use/ the more conservative battery life quar.tificatico estimatec of the PRA.

The battery life calculation will be reviewed in conjunctien with the acergency procedure (Procedural Insight No. 5) te develop an integrated estinate of battery life. .

The abcVe open items vill be closed by LILCO in a time fracc that is consistent with the IPE methodological assumption of a nature plant, i.e., prior to the end of the sceend refueling

outage.

5.4 open Analytical Results 9

l Open analytical results pertain to estimated plant environmental effects on emergency syntes operability. The following assumptions were made in the quantification because calculations were not evailable (or could not be confirmed as applicable) to desenstrate s

5-4

i systes operability for certain design scenarios that are beyond the desigt. basis of the plant. Again, LILCO vill confirm these i assurptions before the end cf the second refueling outage.

1) Following a comp 3cte loss of all AC power, the RPCI and RCIC systems will remain available and will not isolate due to their high area leak detection temperature setpoints being exceeded.

This is considered reasonable based on the open design of the SNPS Reactor Building that allows natural circulation.

2) Prinary Containment venting does not cause adverse environmental effects on the low pressure emergency core cooling equipment located in the secondary containment. This is believed reasonable because venting from the wetvell airspace is hard piped to the upper levels of the Resetor Building (el. 103' 10" and 168' 11"), far removed from the ECCS.

3) Sufficient forced ventilation exists in the Secondary Containment to maintain the operability of the ECCS during a loss of service water event.

4) The primary containment pressure decrease caused by venting it l not espected to cause steam binding of the ECCS pumps.

l I

! 5-5

l 5.5 Procedural Insights A number of procedural insights have been developed. These insights principally address the implementation of the Emergency Procedure Guidelines (EPGs) on a plant specific basis or the way operators are trained and generally confirm the intent of the Emergency Operating Procedures (LOPS). The procedural insights are not areas of regulatory non-compliance or risk outliers; they simply represent opportunities for improvement in overall safety. The SNPS IPE quantification assumes that these procedural insights will be addressed. Unless otherwise indicated, LILCO intends to incorporate these insights into the station procedures or operator training l

program prior to the end of the second refueling outage. Each insight and its basis is summarized below:

i i 1. Overview The ATWS procedute requires the operator to control vessel water level near the top of active fuel (TAF). The Main Steam Isolation Valve (MSIV) closure setpoint is presently at Level 2 4

and will be changed to Level 1 during the first refueling i outage. Lowering the water level to TAF without bypassing the 1.ov RPV water level MSIV interlocks effectively isolates a significant heat sink. A caution to prevent MSIV closure would reduce this likelihood. Addittenally, procedural instruction is necessary for NSIV reopening.

5-6

Detailed Summary Currently SP29.024.01 requires the operator to maintain wrter level above the top of active fuel following the initiation of the Standby Liquid Control System. This action may renuit in reducing water level below the Level 1 MSIV closure setpoint

(-132.5 inches) since the setpoint is at a higher elevation than the top of active fuel (-158 inches). Loss of the ability to reject heat to the condenser will ensue.

Update Station Procedure SP29.024.01 Transient with Failure to Scram, or Operator training to maintain reacter water level above the Level I setpoint until the low level interlocks for any open MSIVs are bypsened. This will enable the MSIVs to remain open and maintain the condenser as a lient sink. Ir.

addition, procedures should call for reopening as soon as practical.

l l

l 2. Overview i

l It would seen prudent to allow some operator flexibility regarding the use of feedweter as an injection source, if the l

sain condenser is available and the SRVs are closed.

l 5-7

l i

Detailed Summary Currently, the operator is instructed to " place the ADS Inhibit Switch to inhibit and terminate all injection into the RPV with

- the exception cf CRD, RCIC or EPCI...", following the manual initiation of"the Standby Liquid Control System. This action will result in the operator trippiry the feedwater pumps, if this system was still in operation. Station Procedure SP29.024.01, Transient with Failure to Scram, or Operator traininF should be changed to enable the use of the Feedvate.r System during an ATWS transient.

3. Overview .

Instructions to reestablish the nitrogen supply to the MSIV accumulators, given an isolation signal, would be advantagecur.

to integreted plant operation ir. certain accident scenarios.

4 Detailed Summary i

Procedures or training should be available to the operators to override the nitrogen supply systes LOCA signal isolations. On a LOCA signal, high drywell pressure (1.69 psis) or low reactor water level (-132.5 inches), the nitrogen supply to the Safety l

Relief Valver (SRVs), inboard MSIVs and long term accumulatets s

5-8 i

I in the secondary containment is isolated (IP50*MOV-113A B closure). In addition, two valves open on the LOCA signal (IP50*MOV-114A,5) and allow the long term accumulators to supply a backup source of nitrogen to the SRVs. However, the inbeard MSIVs are isolated on a LOCA signal from this backup nitrogen supply (IP50*MOV-105A B close). The capability exista in the

~

valve logic to override the LOCA signal isolations using av override switch and the individual valve control switches. This action is recommended to keep the inboard MSIVs open if the short term accunulators become insufficient (open IP50*MOV-105A,5). Similar action is advisable to utilize normal nitrogen makeup or emergency makeup (e.g., emergency truck connection) to open or keep cpen the MSIVs and SRVs (open IP50*MOV-113A B).

4. Overview A high suppression pool tarperature or a Station Elackout sequence requires manual PPV depressurization to approximately 110 psig. HPC1/RCIC operability has not been demonstrated for a vessel pressure this low. In addition, both systems have an administrative limit regarding the minimum RPM of the turbine.

These requirements must be reviewed to resolve potentially conflicting instructions.

1 5-9

Detailed Susanary The pressure requirement in SP29.023.03, Containment Control, which states, "Do not depressurize the RPV below 110 psig unless motor driven pumps, sufficient to maintain RPV water level, are running and the systems are available for injection", should be changed from 110 psig to 135 psig, if so indicated by a plant specific review. The basis for this proposed change is to ensure that the pressure fellowing depressurication is in the range of HPCI and RCIC operability testing as defined by the Technical Specifichtiens.

The Less of all AC Power emergency procedure (SP29.015.02) directs the operator to maintain RPV pressure between 100 and

! 150 psig by cycling SRVs. This procedural step should be I similarly reviewed and if feasible, revised to refJact the lowest range of HPCI and RCIC technical specification operability testing (at 135 psig) and to avoid the HPCI low steam line pressure isolation setpoint (at 100 prig).

5. Overview I

~

Procedural direction is required during a Station Blackout (SBO) to specify additional loads that can be shed from the DC buses as well as the steps required to implement this load reduction.

5-10

Detailed Summary The Loss of all AC Power emergency procedure (SP29.015.02) should be revised to further define which DC powered loads should be shed from the bus to prolong battery life.

SP29.015.02 states that "the betteries are designed to maintair voltage for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />", bovever Stone & Webster calculation E-70 demonstrates that battery life can be extended to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by load shedding.

6. Overview Currently, taking manual centrol of EPC1/RCIC injection to avoid unnecessary s* / stem challenges is optional.

Detailed Summary The station operating procedures and/or trafning for High Pressure Coolant Injection and Reactor Core Isolatten Cooling System oparation should instruct the operator to take manual control of the flow controller of one system to maintain reactor water level between +30 inches and +40 inches on increasing veter level to prevent the bish level trip setpoint (56.5 inches) from being reached. The other system should be left in auto to maintain an sutomatic initiation capability in the event 5411

of cparator crr:r. Th2 rectirn ep: rating prae:duro for RCIC system operation (SP23.119.01) states that the operator may take manual contrcl of the flow controller, however, a more explicit recommendation should be incorporated. The HPC1 procedure (SP23.202.01) contains no instructions for the operator to take manual control of the system.

7. Overview The EPGs take credit for injection of SLC during periods when coolant injection is not available by normal means and the plant must reply upon "last ditch" systems. The station procedure allows SLC initiation for reactivity control purposes only.

This limitation should be removed to allow use of SLC as a "last ditch" coolant injection system.

Petailed Summary i

Change the caution statement in the startup section of station procedure SP23.123.01, Standby Liquid Control System (SLC).

which states, " injection of the sodium pentaborate solution shall be done only when the reactor cannot be made or kept suberitical with control rods", to be consistent to the SLC initiation provisions in SP29.024.01, Transient with Failure to Scram, and SP29.023.04, Level Control. The ATWS emergency procedure requires SLC initiation "if reactor power is above 6%

5-12 l

, or RPV level cannot be maintained, or suppression pool temperature reaches 110'F". The Level Control emergency procedure directs the operator to initiate SLC when water level l cannot be restored using the normal fr.jection systems (e.g. ,

EPCI, Core Spray, etc.). -

.j

8. Overviev The ATWS and the Containtient Control procedurcs are at odds in terms of the recourendation for sequences where the containment design pressure is approsched. It is appropriate for these procedures to be reconciled so that the operator knows clearly which to follow.

Detailed Summary The requirement for maintaining reactor pressure between 800,ar.d 900 psig in SP29.024.01, Transient with Failure to Scrse, should be reconciled with the steps in SP29.023.03, Containment Control, that instruct the operator to depressurite based on plant conditions such as high suppression pool temperature or high drywell pressure.

I.

5-13

I

9. Overview Currently, the low pressure pumps are throttled to avoid cavitation due to Net Positive Suetien Head (NPSE) problems.

Procedures should allow the continued operation of low pressure pumps, even with NPSH problems, in situations when long term inventory is at risk.

Detailed Summary The BWR Owners' Group (BWROC) is investigating ECCS pump operation with inadequate NPSH for sequences where no other viable means of coolant injection exists. After Owner's Group resciution and NRC approval,111.C0 will incorporate the revised guidance into the Shoreham E0Ps. A completion date cannet be deterrined at this time.

4 4

10. Overview Frocedures should be revised to give the operator consistent i

instructions for initiating Containment Fprays.

I l

D'e tailed Summary Differences in the amount of time before the Containment Spray l

' ' can be initisted need to be resolved between SP29.023.03, I 5-14 r, i

Containment Control, and SP23.204.01, Low Pressure Coolant j

Injection. The Containment Control procedure directs the operator to initiate Drywell Sprays based on high drywell pressure or temperature, after assuring that LPCI diversion vill not preclude adequate core cooling. However, the Low Pressure Coolent Injection procedure states that Drywell Sprays cannet be initiated until after 10 minuten of injection. This restriction is based on a worst case LOCA analysis with a conservative single failure assumption that requires LPCI injection for at least 10 minutes to assure. acceptable fuel cladding V

tempera titres. This limitation should be revised to conform to the containment control guidance. This will allow'more titely spray initiation for those sequences where adequate core cooling is estrblished relatively quickly.

Additionally, steps in the Centainment Control emergency procedure directing the operator to initiate Containment Sprays

• should reference SP23.204.01, Low Pressure Coolant injection.

The LPCI procedure contains instructions for using the override switches necessary to initiate Drywell Sprcys.

11. Overview Presently there are no instructions to indC ate that RHR heat exchanger operation can be certinued, despite high radiation indications at the service water (SW) ectlet.

5-15

Detailed Sensary .

I A procedural change ic r.ecessary to allow coneinued use of a LER heat erchanger, despite high radiation at the service water outlet, if this action is necessary to prevent further core degradation or containment failure.

l

12. Overview Although detai3ed operator instructicns are available to nitigate a ficoding incident in the Reactor Building, a sferic, consolidated procedure is not currently available.

Detailed Summary An event specific erergency procedure should be developed for Reactor Building (RB) flooding to conselidate the informacien that is currently available in the alarm response and sterion procedures regarding operator action to identify and isolate a secondary containment leak. This procedure should also contain the postulated disabled heights of equipment located on the 8 foot elevation from Appendix G of the Shorehan FRA. Additional operator guidance should be given for control of high drywell pressure isolations of the reactor building sump pumps and the suppression pool pumpback system isolation valve.

5-16

l

13. Overview Luring a station blackout the operat;c has no indication of the status of many plant parameters. Procedures need to be revised to more clearly define what operator action is required during a i

station blackcut and after AC power restoration.

Detailed Summary Plant cundition information is needed to assist the operator in making decfcions and taking action in the event of a loss of all AC power. Further information should also be provided to the operators regarding ECCS operability following AC power restoration. Specifically, the possible drain down of infection lines due to inoperability of the Icep fill syster. and possible water hammer upon ECCS rer,toration should be addressed.

14. Overviev Procedures need to be modified to instruct the operator to evaluate the status of DC bus given a battery charger trouble alarm. This would assure determinatio~n of whether or not the DC bus is available.

t 5-17 m.-

l Petailed Summary I l

Additional steps should be incorporated in the Battery Charter Trouble Annunciator Response Procedures (ARP 200,201,202),to direct the operator to check DC bus voltage on the .

voltmetersprovidedinthecontrolroomandemergencyswitchgest I rooms. Presently, the operator may only check the battery chargers even though the alarm can also be caused by the Icss of P

the entire DC bus.

15. Overview After a LOCA, the reactor building service water and turbir.e building service water are isolated from each other. A method to bypass the isolation signal should be incorporated into procedures for cases in rhich this is required.

Detailed Summary A method to cross-connect the Turbine Building Service Water System to the Reactor Building Service Water System should be' available in the event of a concurrent loss of service water and 14CA signal. The loss of RBSW could lead to loss of dryvell cooling and, ultimately, cause a LOCA signal to be generated.

The direction given to the operators could be to either 4

5-18

electrically bypass the LOCA signal closure interlock en the cross-connect valves (IP41*MOV-35A,5) or to 'open the manual bypass valve around the motor operated cross-connect valves.

16. Overviev ,

4 The capability to bypass 69kV switchyard should be incorporated.

Detailed Eummary A 69kV feeder has been installed which bypasses the 69kV switchyard and is dead ended at the Reserve Station Service Transformer (RSST). Jumpers are stored on-site to connect this feeder to the RSST. This cable is connected to the 69kV grid upstream of 69kV switchyard breaker 640. This should be noted in the loss cf offsite power emergency procedere.

17. Overview The HPCI and RCIC suctions are currently switched from the

. condensate storage tank to the suppression pool on low level in

the condensate storage tank or high level in the suppression f

pool. In the event of a station blackout it would 'be' appropriate to transfer HPCI and RCIC back to the condensate storage tank for long term operation.

5-19

Detailed Summary In cases where the suppression pool is no longer a viable seurce of makeup veter due to high temperature following an event such as a loss of all AC power, censideration should*be given to evitching HPC1/RCIC pump suction from the suppression pool back to the condensate storage tank (CST). This action may require instructions to bypase electrieel interlocks for taking HPCI and RCIC suction from the suppression pec3 on high suppression peol level or low CST level.

The BWROG is current 3y investigcting this issue. After resolution and NRC approval of the revised EPG LILCO will modify the SNPS procedures. A specific completior date cannet be determined at this time.

18. Overview Revise procedures to assure that the operator restorec the suppression pool water level on a suppression pool level low alarm.

Detailed Summary Revise Alara Response Procedure 1366, Suppression Pool Level Low to allow the suppression pool level to be returned to nortal using the RPCI, RCIC or Core Spray systems.

5-20

6.0 CONCLUSION

S The Individual Plant Evaluation Method developed by 1DCOR has been applied to the Shoreham Nuclear Power Station. The results are as follows:

o The IDCOR generic conclusions are appifcable to Shoreham. The likelihood of a core damage event is very low. The Shoreham calculated total core melt frequency is 8.5E-5 per year. This is not considered to be a significant increase over the IDCOR beseline frequency of 5.8E-5 per year.

o The application has resulted in the identificatire of a era.

procedural insiF hts which can be effectively addressed to imprave overall safety. These are not areas of non-compliance with regulations or arear of serious risk outlier findings. They are simply opportunities for improvements in overall safety.

4 Other conclusions deal with the methodology itself. These are as follows:

o The methodology does a good job of highlighting insights from previous PRAs for review and focuses the assessment on important dependencies 3 o The review process is thorough and is likely to identify useful plant l

insights l

6-1

o The method requires approximately two man years of effort for a plant with a PRA, assuming the PPA is not used as a surrogate for the rethod.

l c The quantification ir post difficult to follow for non-PRA personnel.

Efforts to simplify this part of the process would be most helpful.

r O

e 6-2

l i

APPENDIX A '

t.

i

Summary of Plant Specific Probabilistic Reruits Used in the IPE Metrod

• This appendix provides a system specific discussion of the input modifications to the IDCOR baseline unavailability estimates. These changes can be primarily '

attributed to the use of Shoreham-specific system information and/or modifications dictated by the responses to the IPE Appendix D questions. Each subsection of Appendir. D is addressed below, in conjunction with a discussion of any changes to the baseline quentification.

Reactivity Control The primary melhod for the insertion of negative reactivity in the boiling water a

reactor is by control rod insertion via the Reactor Protection System (RPS) and the Control Rod Drive (CRD) system. The Alternate Red Insertion (ARI),

Recirculation Pump Trip (P.PT) and the Standby Liquid Control (SLC) systers are available to mitigate any failure in the normal reactivity control systems.

The Shoreham RPS is the some as the baseline IDCOR design of two separately powered, normally energised, independent trip systems. The baseline RPS unavailability function (C) is 3E-5/desiand from NUFIG-0460. This can be subdivided into an electrica3 component (C E) of 2E-5 and a mechanical componert i

(qg) of IE-5. In. selected sequences (i.e., large LOCA) for esse of calculation and identification of dominant sequences, the quan':ification includes only the

dominant contributors to scram system unavailability, such as a common mode A-1

sechanical failure. The IPE Appendix D questions regarding the scram systst did not alter the IDCOP baseline unavailability values, which are used for Shoreham. l The Shoreham RPT (R function) utilizes the Monticello logic whereby two out of twa low level signals (Level 2) or two out of two high pressure sipals will energine the associated RPT breaker trip coil. Two RPT breakers are arranged in series between each MG set and the associated recirculation pump motor. Orly one of the two breakers must actuate to cause e pump trip, which quickly lowers

~

reactor power by voiding the core.

The ARI system (K function) provides a separate diverse backup in the event of RPS failure. The system is enerr.ized to operate and shares some logic (analog trip units and several relays) with the RPT. The system is initiated by high reactor pressure (1120 psig) or low reactor water level (Level 2) which are beyond the normal RPS initiation points. The AR1 signal opens two solenoid pilot valves on the CRD scram air header. Depressuritation takes approximately 7 seconds, whereupon the scram inlet and outlet valves open to scrar the ,

j reactor. The total elapsed time for control rod insertion is approximately 12 seconds. Based on the requirements of the ATVS rule, 10CFP50.62, LILCO has committed to several ARI modifications, including manual initiation and a seal-in feature. These modifications are scheduled to be incorporated during the first refueling outage.

l The IDCOR RPT and.ARI Appendix D questions were reviewed. No modifications were necessary to the R and K baseline values.

l A-2

l In the event the ARI system cannot successfully cause control rod insertion, the SLC system would be manually initiated to bring the reactor suberitical by the injection of an aqueous sodium pentaborete solution. The SNPS design currently consists of a 43 gpa injection capacity which is provided by one of two SLC pumps. In response to the ATUS rule, LILCO has committed to upgrading the-system to an 86 spe equivalent injection rate by operating both pumps '

simultaneously. This represerts a reduction in risk because the higher .

, injection rate allowe approximately ten additional minutes to successfully initiate SLC. The IDCOR IPE methodology has developed system unavai.1 ability-catimates (C2 ) r several SLC injection options. The event specific baseline tumbers for the SNPS design were taken from IDCOR Table D.1-6 and were not modified by the responses to the Appendix D questions.

A potential conservatism in the Shoreham IPE is that no credit was taken for the increcsed likelfhood of success for ATWS scquences with the combined injection

.cf two SI.C pumps and RCIC, Pressure Control Pressure control consists of two functions, pressure relief (M) and SRV recI6's'e 1

.(P). At Shoreham these functions are performed by eleven Target Rock two-stage j SRVs. These valves are divided by actuation setpoint into three groups (1115, 1125 and 1135 psig). In response to NPC open issue II.K.3.16, " Reduction of- -

A-3

Challenges to the SRVa", LILCO has made the following rodificaricns or commitments to reduce the likelihood of SORVs:

o " Low-lov set-equivalent manual action" procedural changes were made to require operator action to ranually control RPV pressure to prevent SRV walve cycling.

o Fifty percent of the SUPS SRV topworks will be bench tested for recalibration of setpoints, pilot leakage determination and refurbishment during each refueling outage, o Design chenges have been implemented to the nitrogen supply to prevent overpressurication of the SRV operators.

In addition. LILCO has joined the BWR Owner's Group High Setpoint Drif t Committee and expects to implement the improved pilot valve disk, when hardware availability and plant scheduling censiderations permit.

The IPE questions did not require any adjustment to the baseline unavailabilities.

High Pressure Coolant Makeup l The high pressure coolant makeup function (U) consists of feedvater (FW),

l l EPCI/RCIC and the CRD Bydraulie System.

i A-4 l

l The Shoreham feedwater system is similar to the IDCOR baseline and consists of two 67% capacity turbine driven feedvater purps, two high pressure feedvater heaters, and associated piping, valves, control, and instrueentation. The

\ ,

reactor feedwater pumps discharFe Pressurized, heated water through common parallel high pressure feedwater heaters and then into the nuclear boiler syster through feedvarer spargers located outside the core shroud. The feedwater turbines utilize either high pressure stear from main steam, downstream of the i

Main Steam Isolation Valves (MSIVs) or low pressure steam from the main errbine, downstream of the moisture separators. The exhauct steam fror the feedwater turbines is discharged to the main condenser.

The review of the Appendix D questions resulted in several changes to the baseline FW quantification. In addition, baseline values were ad'pted c with certain procedural and design assumptioes rhich wi21 require future verification. The details are discussed below:

o In lieu of actual operating experience, the feedveter recovery probabilities for turbine trip (.9), MSIV closure (.7), sed the loss of feedwater transienta (.86) were taken from the SNPS PRA. These are similar to the IPE values in all cases.

o Feedvater is assumed unavailable for all loss of service water initiators. The MSIVs will isolate on high main steam tunnel temperatur soon after the unit cooler is lost, due to lack of reactor building service water.

A-5

o As discussed e.ere fully under the instrument air section, the nitrogen supply to the inboard MSIVe will isolate due to high crywell pressure events (LOCA signal). The estimate of feedwater availability is based on secumulators that are sufficiently leak tight to maintain the valves in the open position for approximately l

30 minutes (and te permit reopering, if c3esed in that time frame) and/or the operators will de-isolate the accumulators. See the Open

! Desige Items and Procedural Insights sections of this report.

! o MSIV closure requires de-energizing ore DC and one AC solenoid pilot l

j valve. The logic is arranged so the valves will close on loss of AC power; however, the lose of one DC bus will not in and of itself cause MSIV closura. Although MSIV closure is not a direct result of the loss of two DC buses, a .5 feedwater unevailability was choser to account for instrurentation losses and possible operator ac, tion.

i o It is assumed that the operator will allow continued feedvater injection for the turbine trip and ATWS transients. See the Procedural insights Section for more information.

The HPCI and RCIC systems are very similar to the IDCOR baseline. Each system basically consists of a steam turbine assembly driving a constant-flow pump and associated system piping, valves, controls and instrumentation.

9 A-6

A review of the Appendix D questions highlighted several departures from the baseline system quantification which, in several instances, resulted in changes:

o Shorehas experienced a rupture disk failure during EPCI system testing, which is reflected by an increase of .01 in the HPCI and RCIC system unreliability. However, since this event was caused by a random pinhole leak in the rupture disk and not a design flaw, the common mode unavailability of RPCI/RCIC was not increased due to the potential high area temperature isolation of both of these systems.

o The HPCI system has approximate 3y 18 single instruments that could cause system isolation. The systen unavailability was increased by

.01 to reflect the increesed probabi3ity of system isolation.

o Both HPCI and RCIC have technical specification LCOs that allow system unavailability up to 14 days versus 7 days used in the beseline. Thic results fr c maintenance unavailability of .02 per system.

o SNPS has experienced exhaust check valve failures in both the HPCI and RCIC systems during low flow conditions. RCIC lift check exhaust valves have been installed. RPCI lift checks are scheduled for installation during the first refueling outage. The lift check valves are expected to resolve this problem. Therefore the baseline A-7

was not modified for this issue. In addition, several oper procedural and open design items were identified that could conceivably influence the syster quantification. These items are discussed in detail in the Procedural Insights and Open Design Itesc Sections. -

The alternate injection systems consist of the Control Rod Drive (CRD)

Hydraulic and the SLC systems. The SNPS CRD Rydraulic System injection to the RPV is normally limited to leakage past the CRD seals (approximately 50 gpm). The operator can increase this rominal injection rate to approxirstely 180 spa by flow centrol station valve r.anipulation. The IPE evaluation takes some credit for the CRD Hydraulic System for lonF term vessel makeup (10 - 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />) for selected sequences.

Although the.SLC injection rate will be increased to 86 spa, and the SNPS Level Centrol Emergency Procedure allows injection, this additionel injection pource was not considered in this evaluation.

Depressurization The IDCOR depressurization section primarily addresses the Automatic Depressurization System (ADS) and manual depressurization. The system, as described, closely resembles Shoreham, with regard to the number of SRVs (11),

ADS valves #7) and the dual solenoid design of the ADS valves. The system differs in the pneumatic design. SNPS has soft seat accumulator check valves.

However, the instrument nitrogen avstem has two long term accumulators that will A-8

for.ction to pressurire the individual SRV accumulators during syster f rolation from the normal nitregen source. The system uravailability due to accumulator check valve 3eakage was not changed becaupe the SNPS design was considered equal to the baseline in this regard.

The review of the IDCOR questions did require a rignificant adjustment to the baseline quentification to account for a lack of procedural restrictions regarding the use of the ADS inhibit switch. A 1.0 unavalittility was assumed

-for the automatic initiction logic to reflect the possible use of ADS inhibit for non-ATWS sequenecs. The increased duration between operational tests (18 sonths) increased the hardware unavailability by a factor of two. However, thir was insignificant because operator action dominated the ADS unavailability estimates. A postulated common rede bleed down of the nitrogen supply which was identified by the team, required a 1E-4 addition to the depressurization fault tree. Shorehat has a long term nitrogen supply and procedures exist to cernect this supply to the SRV preumatic system. Since the baseline value for this failure mode is already very low, the improvement in risk arcociated with this long term nitrogen supply did not affect the overall baseline assesseent.

Low Pressure Injection The IDCOR Low Pressure Injection Systems include Low Pressure Coolant Injection (LPCI), Core Spray (CS), Ccndensate Pumps, and alternate systems. The Shoreham LPCI, CS and Cond'ensate systems represent the baseline plant. The RER (LPCI) system has two loops, each with 2 pumps and one heat exchanger. The CS system has two loors, each with one pump. Each CS/RHR purp has a dedicated suction A-9

line and each loop has a minimum flow line. The RHR/CS cystems initiate on a LOCA signal and inject after receiving a RPV low pressure permissive. The systems will isolate only on loss of the low pressure permissive. The RHR system uses reactor pressure; the CS utilizes differential pressure for the low pressure permissive. However, the CS dp instruments are scheduled to be replaced with pressure switches during the first refueling outage. Although there are local vibration monitors for the RHR/CS pumps, this was not included in the quartification since they do not read out in the Control Room or automatica13y trip the pump. The condensate pump isolates or.ly on undervoltage.

For the analysis either one RHR, CS, or Condensate pump is assumed adequate for low pressure cooling. Shorehani is consistent with the IPE methodclogy regarding the use of the cendensate pumps for mitigation of a large LOCA, in that a l

proportion of these events may deplete the hotwell and result in inadequate condensate injection to the PJV. However, with water management and makeup from the Condensate Storage Tank or Demineralised Water System, the remaining spectrum of breaks larger than the 6 inch 0.D. equivalent can be effectively sitigated.

The following are some key observations regarding low pressure ECCS operation:

o The PRR/CS pumps are designed for pumping 212'F water for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and do not require seal coolers when the suction is not lined up to the RPV. Given the anticipated suppression pool temperatures it was assumed that the pumps will not fail. Cciculations have shown that there is adequate NPSH (Net Positive Suction Head) for the pumps A-10

with the suppression pool at elevated temperatures. The procedures address operation of the pumps at higher than expected temperaturec and, require throttling the pumps depending on temperature. However

. the procedures do not provide guidance when the temperature exceeds

,. the acceptable flow rate vs. temperature curves. The analyses assumed that the operator would continue to operate the pumps at the higher temperature (see the Procedural Insights Section). If suppression pool temperature or level is unknown because AC power is lost, the procedures again do not provide eperator guidance. The analysis was not modified to reflect this and further investigatien is required (see the Procedural Insights Section).

d o The reactor building is not compartmentalized and room cooling is J

assumed to be cdequate. Supplemental analyses to quantify the heatup effects are discussed in Section 5.4.

o The suction piping for the RER/CS purps rises above the normal water level and penetrates the containment 14 feet above the pump

, elevation. NRC documentation does not identify steam binding as a

-. problem. However, if the dryvell is quickly depressurized, by

( containment venting, steam binding is a consideration. The l

quantification assumes that the RRR/CS system operability is not impaired. This is identified as an open item in Section 5.4.

o The RER/CS injection valves are tested every 18 months. Therefore the system unavailability was increased to reflect the increased testing intervals.

j A-11 l

l i

o Wher. considering large LOCA sequences the jet pump hold dowr. beam design was reviewed. Although the hold-dowr. beams are not of the new improved design. IE Bulletin 80-07 was addressed and increesed l inspection and reduced bolt torque were implemented. The quantification was therefore r.et adjusted. -

In the quantification some credit has been taken for alternate systems, as the procedures identify alternate methods of low pressure injection. The systems included in the emergency level restoration procedure are fire protection, condensate transfer system and service water. These systens are tested and may be a relicble alternate.

Containment Control Functions i

The IPE methodology was subdivided into two functions: Containnent Pressure Control (decay hest removal) and Containment Temperature Control.

l l

Containment pressure control consists of several safety and non-safety systems that can be utilized in various configurations to remove decay heat frcr. the containment. These modes include suppressien pool cooling, steam condensing, contingency methods of pressure control and the PCS as discussed below:

o Credit has been taken for the continued use of RRR suppression pool cooling for ATWS and LOCA sequences, despite high radiation indications at the service water outlet of the heat exchanger. This is discussed more fully in the Procedural Insights Section of Chapter 5.

A-12 l

l I

o LILCO has prohibited the use of the stear cundensing mode (SCM) r during normal plant. operations, pending further analysis of pcssible submerged structure, piping and support loads during RER heat

' exchanger relief valve actuation. The valves used in the SCM are administrat'ively controlled to preclude inadvertent. operation.

However, the steam condensing mode is available during station

'lackout, b when all other means of core / containment heat removal have been exhausted.

o A procedure has been developed to use venting as a means of centainment pressure cortrol via existing conceinment purge valves and piping. Credit is taken for this mode of containment control for all applicable sequences except station blackout.

o The Power Conversien System (PCS) represents the most readily available source of decay heat removal. The primary concern with regard to long term decay heat recoval via the condenser is the ability to maintain (or re-establish) condenser vacuum and to keep the MSIVs open or to raopen as necessary. Shoreham has a procedure to enable the operator to establish condenser-vacuun with the steam

~

jet air ejectors using the station auxiliary boiler. The re-opening f of the MSIVs is discussed in the Procedural Insights Section.

l Th$ Containment Temperature Section explores the plant specific iritistfor probability of the containment sprays, the reloading of the drywell coolers and RPV depressurisation to control drywell temperature. A conditional failure A-13 l

probability of 1.0 was assigned to the dryvell sprays for all requences to account for restrictive operator guidance regarding the use the drywell containment sprays. Tha quantification did, however, take some credit for the use of the suppression chamber sprays in accordance with the Shorehar.

containment control procedure. The design of the SKPS drywell coolers includes provisions for automatic reload cnto the emergency buses during a loss of offsite power. In addition, there are procedural instructiove to re-establish dryvell cooling during containment pressurization events. Again, the SKPS design is the same as the baseline quantificatfch.

The sequence specific depressurizatien failure prcbability during containment heatup events has been modified to reflect SEPS operator training in the use of this method of containment temperature control. This beceline unavailability was increased by a factor of five for station blackout to account for the dryvell temperature instrumentation dependency on AC power.

]

Vapor Suppression The Shcreham Nuclear Power Station is a GE BWR 4 with a Mark II concrete containment. As in the baseline plant, the drywell floor is detached from the surrounding containment wall. The drywell floor seal maintains an air tight seal between the drywell and the wetwell air space. The drywell seal consists of two independent inflatable seals that are pressurised by the nitrogen cystem.

This seal prevents suppression pool bypass which could result in post scefdent containment failure. Depending on the initietor, the vapor is rou<so to the The suppressier pool by either the SRV discharge line(s) or the downconers.

A-14

11 SRV discharge lines utilize T quenchers for vapor suppression. All SRVs have 6" piston check vacuum breakers to reduce the potential for waterhammer.

l

! Six of the 88 dcwnconers have dual disk swing check vacuum breakers with testing l ,.

provisions.

Based on a review of the IPE questions and the SNPS design as described abovt, I

the plant specific vcpor suppression baseline failure probability was developed.

.c The deviation from the IDCOR baseline can be attributed to the following Shereham specific desipr. and procedural features:

o For SORV with a SRV discharge line break, calculations indicated the I '

containment design pressure (48 psig) was reached in approximately ten minutes. This respited in an estimated vapor suppression failure estirate of IE-6.

o Stress analysis of the SRV discharge lines generally ir.dicate the f

"most" highly stressed points are in the wet well airspace.

Powever, there is sufficient margin between the maximur. calculated r

stress and the ASME allowables to justify the use of the baselfr.e value.

o JW engineering evaluatien determined that the suppression pool could conceivably be drained below the quenchere by long term operatier. of the fuel pool cooling system in the suppression pool cleanup mode.

This failure mode was incorporated in the pressure control fault i

tree.

A-15

I o As previously stated, the SNPS design incorporates dual (redundant) disks which results in an approximate order of magnitude increast in reliability. However this is counterbalanced by a similar penalty because the units have an air operable test feature.

Coolant Injection Followina Containment Cha11 ente Following a containment challenge, secondary containment environmental conditions will not prevent continued core makeup. Injection capability is sequence dependent and could include the CRD pumps or the condensate, core spray or LPCI pumps in conjunction with the SP.Vs.

S. Levy Inc. had previously analyzed the reactor water leve) measurement system and determined that the reference les vertical drop was acceptable with respect to flashing, as long as indicated level was maintained above Level 2. The procedurec address fir.shing and instruct the operator to depressurize and flood the vessel when the containment temperature near the reference 3eg reaches the RPV saturation limit and the indicated level is below Level 2. The operator is trained to monitor level following a reactor scram end there are radiation monitors which are rensitive enough to detect fuel failure.

The quantification assumed that there were no temperature effects on the drywell floor seals, electrical penetrations, or SRV/MSIV solenoids below the maximum anticipated drywe13 temperature without a core melt. A previously performed l ILRT has not indicated an excessive leakage problem.

A-16

Steam binding due to lowered containmert pressure was not assured to affect the RHR or CS pumps. However, this item needs further investigation and is listed as an open item in Section 5.4.

Support State Event Tre'e 7unctional Events '

This IPE subsection reviewed the potential irpacts on front line systems due to the Icss of selected support systems. These include both safety related and non-safety related systems as discussed below.

Offsite Power

. The IDCOR loss of offsite power (LOOT) initiator is comprised of two components. The first is the probability of offsite power loss due to

. load rejecticn at the time of the transient. This component is based on data from EPP.1 NP 2230 and other sources which show that in over 470 reactor years of operation there have been no recorded cases of a loss of offsite power'being induced by a nuclear plant trip. Assuming one postulated event and nine ' transients per reactor year (EPRI NP 2230), the baseline probabilit'y of this event was calculated to be 2.4E-4 per reactor year.

The second contributor is'the probability of Icaing offsite power during the first 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> after a s5utdown. This event may test plant systees in a manner similar to a LOOP. LILCO has developed a plant specific loop frequency based on actual grid data. This evaluation is discussed in Appendix B, " Development of Plant Specific Data or System Availabilities".

A-17

DC Power Supply The IDCOR DC Power Supply system is based on the Shoreham design. Each DC division et SNPS is energized by its own battery and charger.

The chargers era capabic cf carrying the normal DC system load and at the sene time supply.ing sufficient charging current to restore the batterier from the designed minimum charge state to the fully charged state within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The battery chargers are supplied from separate 480 V HCCs that are powered by independent 480 VAC buses. Each 125 V DC battery bank has sufficient capacity without its charger to independently supply the required locds for a minitcum of two (2) hours, assuming no nanual load shedding.

As in the baseline design, Shoreham has three independent DC power systems, corresponding to the three AC power divisions. However, Division III is not syssetrical in its loading and cannot independently shutdown the plant.

A-18

(

h A review of the IPE questions resulted in the following quantificction changes and insights: '

'\

o. The elevated DC bus voltage issue (IE Bulletin 83-08) is currently beingkormallyaddressed.-The'preliminaryanalysisindicatesthir is net a concern at Shoreham. No quantification chanFes will be made; the completion of the engineering evaluation has been designated as an open design iten.

o The SNPF TRA DC batte'ry unavailability estinstes have been adopted for this effort. Although battery life has been calculated to be i

approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />'. specific procedural load shedding instructions are not aisilable. See the Procedural Inrights Section for a more detailed discussion.

o Operability testing of the battery systems is performed at refueling outages (every 18 months). The conditionel failura prcbability of these systems has been increesed by 1.5 in accordance with the IPE guidance. --

o SNPS has battery charger trouble:alarma in the Main Control Room which also alarm on ivu DC but voltage. A procedural insight has been generated to change the alarm response procedure to instruct the operator to check DC bus voltage after a charger trouble alarm (the meter is on the same cection of the control board, just belov A-19 ,

i

\

N.ealarmwindcvs). This, in conjunction with the Idss of starious t

' Control Room indicaticns, is considered to be suNficient to alert )'

t '

6 i

' the operator to a loss of a DC bus; therefore, no quantificat'ce change was made.

t Service Water / -

D f .w k

l' _

s .

~

/ A pla sp:cific'serytes. water model was not constructtd since the service t ~

swater and circulating veter systems presented in the'IDCOR baseline ,

.) ,

i duplicstes the Shorehar systems. There are 4 reactor building service i vate'r (RBSW) groups, 3 turbine building service water (TBSW) pumps and 4 s i

circulating water puwps. All 11 pumps are located at the same intake tructure and there ere no other water sources. Due ,t.o trouble with tbc

) \ c'hlorinatice system, mussel intrusion has occurred in the SW system.

There is .no hot water system presently in use. Modifications to make the f

i

).

chlorindrion system more reliabledare underway. The quantification has

\

i taken advantage of these future improvements and a belief that this will

/

substantia 11,y reduce tYe potential for cosanon pode f ailures.

b

?. ,

s(

s L

The fourth pump does not Three RBSW pumps start on s LOCA signal.

automatically start because it is administratively placed in the " pull to lock" position due to thy 3300 KW load limitation on each emergency diesel s

', s  !

. generator.I This pump may be manually started after the diesel generator

' ,x f load is managed. The quantificatfor was not adjusted for this becs.use I

common mod <t failures dominate and there is sufficient time for the '

opetetor tc, start the fourth qamp. The LOCA signal will split the four

, / )

~

' e

', N p.-20 ,4 1.

pumps into two independent loops. The fire protection diesel driven pump can be crosetied to the RBSk' syster and limited credit is tairen for this injection scurce after approxImately two hours. The TBSk' systen'may siso be crosstied to RBSW as discussed in the' Proce' dural Insights biection.

b TheRBSWpumpsrunduringnormaloperationandEavea3'dafte'chnical speciffration outage time. Because the pus.ps are nor'mally running, no

~

penalty was given for having operability' ' testing' once eve' y'1'8r.onths.

r

• ~

s Presently, the RBSW is actually itelated fror. th'e RHR' Neat eycliangers on a high radiction signal per procedures ~. However,thereareneadtomatic

( interlocks for the cervice water system and a procedural insigh't was l

l l

developed to prevent heat exch'angtr isolation if it would cause'further core degradation or containmen't failure. A quantification change was not deemed necessary.

Roon Cooling The baseline reactor buf1 ding coeling syster is b'a2ed on the Sh' ore.har design. Room cooling is normally accorp1'ished byReacNr Build'ng' i Normal Ventilation System (RBNVS). On an accident signai, ti.e Reactor Building l

l Standby Vent 11stion System (RBSYS) will initiate. Cdoling water will be

~

l provided to Reactor BuildicF unit coolers by the RBSYS7CRAC Chilled Water System. The RBSYS recirculation flow in addition to'the lack of reactor building compartmenta31:ation, will adequately cool the Reactor Building

( and maintain ECCS operability.

A-21

l l

l l

k'ith the exception of the drywell coolers, no credit is given for non-safety related HVAC as it can be isolated by high dryve13 pressure or RF7 Level 1 and cannot be easily restored.

Instrument Air The IPE bepeline Instrument Air / Nitrogen System is similar to the Shoreham design.

At Shoreham, instrue.ent air is supplied by three non-safety related centrifugal compressors located in the turbine building. Each compressor includes a prefilter, a silencer, an intercooler, an aftercooler, an air receiver and automatic controls. Air for the instrurent air systen is taken from the discharge header and filtered, dried, and filtered again before it is distributed to the various plant instrueent services.

Normc11y, one compressor supplies the instrument and service air with a second compressor on automatic standby to cor.pensate for large swings in

, load. The third compressor is used during maintenance and for backup.

l l

l The instrument air system is dependent on non-safety related turbine building support systens ?ct compressor cooling and the normal plant (offsite) power supply. In the event of compressor unavailability the system capacity is reduced to the volume centained in the air receivers and the instrument air header. The instrument air system supplies varicus plant systems including feedvater and the outboard MSIV accumulatore.

l A-22 l

4 A portion of the instrument system has been modified to use' nitrogen from the normal nitrogen supply in ordar to preclude the addition of orygen to the inerted containment atmosphere durius plant operations. However, the~ l' I

espsbility exists to realign valves (administrative 1y controlled) to the instrument air system. .

. <a:

The instrument nitrepen system enters the reactor building' t'hrour,hth'e' truck lock and splits into two trains prior to entering con'ainne'nt.'

t A' crosstie inside containment with two valves in serie's con'dec~ts the"two trains. '

.T

^

Following a TOCA, (or high drywell pressurization event) ritor ope' rated 'l valves will automatically isolate the crosstic between train Ai#and B, isolate the normal (nonsafety-related) nitrogen supply, and align two large redundant secumulators to their designated groups of individual SRV ,

accurulators. This will 16c3 ate the inboard MSIV accumulatore.

i Following a loss of train A normal nitrogen supply pressure. ;the traih A' i

normal supply motor operated valves will automatically irolate the train A normal nitrogen supply pressure. If no further loss of nitrogen p'ressure occurs in the system, the train B normal nitrogen supply. vill feed both the train A and B sides of the air header. Loss of train B'nerm~a'l'

nitrogen supply pressure will operate the same as above.

When both the norpal supply and the crosstie valves for each respective train are closed, the system will automatically align the two large accumulators to their designated group of individual SRV accurulators.

a A-23 e

• The IPE baseline quantification for the instrument air /nitrogos system is used for this evaluation. This is based on an oper design iter. that assumes both the inboard and outboard NEIV accumulators are sufficiertly 1esk tight to keep the valver open for 30 minutes or permit reopening in that time frame. Additionally, a related procedural insight concerning operator instructions to de-isolate the instrument nitrogen systen must also be addressed.

Onsite AC Power The Shorchar. onsite emergency AC power is the ssze as the IPE baselint design. Presently, onsite AC power consists of three independent -

divisions each powered by a TDI diesel with a qualified rating of 3300 Kr.

DC loads have been allocated to ensure that any two diesels are sufficient to bring the plant to a sale shutdown.

The distributien system of each division consists of a 4 KV emergency bus, a 480V load center, several motor control centers (MCCs), and low-voltare distribution panels. Instrumentation, control equipment and wiring are segregated into three separate divisions, designated Divisions I, II, end i III. The electrical systems are designed such that the failure of a single component will not disable more than one division.

l (For discussions of enhancements to the onsite AC system which were not included in the quantification, see Appendix B).

A-74

.1 The TDIs have'their own airstart systwms, which are capable of a minimum

- of 5 unsuccessful ctarts. The starting circuits are designed such that the unit will lock-out when its accumulators reach a pressure of 150 psig.

After the lock-out, the operator can only start the engine manually. In this mode, air vill only be injected for 3 seconds on each atteept.

The TDI fuel oil system was examined to determine the potential for common mode failures. Since there are no common valves that could affect multiple diesels, the common mode failure probebility was decreased by 2E-4.

DC test and maintenance procedures contain a " Final Conditions" section that requires the system to be returned to normal status. The Watch Engineer reviews the Maintenance Work Request (MWR) and specifieF what post work testing is required to demonstrate system operability. On this basis no quantification adjustments were made.

Miscellaneous Plant Specific Input Appendix D.10 of the IPE methodology provided guidance regarding the 1

generic sequence limitations in the form of questions that were designed to emphasize plant specific deviations from the baseline plant. The section considered plant specific operating data, procedural guidance and design considerations. All questions were addressed; the following is a synopsis of the results.

A-25

Shoreham presently has a low power license, pending the resolution of the emergency planning issue and therefore any operational data has limited use. In seneral, operational occurrences were used only to increase the baseline failure probability, not to justify reductions to the generic quantification. For example, SNPS has an analog trip system that is expected to redece the frequency of spurious challenges to plant systems.

Novaver, due to our limited operating experience, the IPE baseline nusber t' was not modified.

A Shoreham specific lors of offsite power initiator has been generated using LILCO grid data. An estimate of the time required for effsite powcr recovery was also developed using more applicable data for the New England area from the Northeast Power Coerdination Council. A detailed derivation is presented in Appendix B of this report.

The small LOCA initiator has been modified to acceunt for the Intergranular Stress Corrosion Cracking (ICSCC) issue. Shoreham has used Induction Heating Stress Improvement (INSI) on the majority of all accessible welds. Twenty-four welds were not treated, primarily because the lines were too sacil for the available equipment. In accordance with the IPE recommended actions, the small I.0CA initiator has been increased to .24/ year. However, based on the existing ISI program, the relatively small propertion of untreated welds and applicable industry experience, LILCO believes the methodology overstates the risk of a small break LOCA.

A-26

l 1he flooding issue as a contributor tc core vulnerable statc5 is extrece2y t

deperdent on plant design. The elevation 8'0" flooding potential has been previously examined in the Shoreham PRA and is incorporated into this evaluation, as directed h," the IPE methodology. Appendix B provides a summary of the floodint issue. -

The methodoleFy requested an evaluation to verify that a single instrur.ent failure in conjunction with the loss of a single DC bus would not result in a scran. Although LILCO believes SNPS is not subject to e scram under these circunstances, it requiree an extensive study to document all possible instrument permutations. The small incremental benefit does not warrant this effort; therefore the baselfre initiator frequency was used.

LILCO used the Shoreham PRA to quantify the reactor water level reference line break initiater frequency. The IPE questions were considered, however they did not affect the PRA quantification. Appendix B provides a discussion of this issue.

O A-27

2 APPENDIX B Development of Plant Specific Data and Syster Unavailabilities Loop Initiator The IDCOR baselipe plant uses a value of .08/yr for the LOOP initiator. This nurber is taken from the SNPS PRA which uses LILCO grid data from 1/1/65 through 12/31/01. A review of LILCO grid data through 12/31/85 revealed ne additionel losses of off-site power to any power stations; therefore, the updated data is 4 outages in 81.5 plant years.

ccurren es + hypothesized incipient failure TE=

years plant experience TE- g

= .06/yr From IDCOR Appendix D.9, the probability of a LOOP induced by a nuclear station trip is 2.4E-4/ transient. The LOOP frequency is .06/yr or 6.9E-6/hr. Should the LOOP occur during the first 10 hre after a shutdown, the frequency will be 6.9E-6 x 10 cr 6.9E-5/ shutdown.

The total unavailability of of fsite power is therefore 2.4E-4 + 6.9E-5 =

3.1E-4/ demand, as' compared to the baseline value of 3.3E-4.

B-1

The calculated value of 3.lE-4 was used in the c,uantification proceCF because it best reflects the local grid characteristics updated through 1985. The Brookhaven review of the SNPS PRA sttppested using a much higher number which was based on Northeast Power Coordination Council (NPCC) data. Again this data was not specific to the local area, in f act it cevered a good part of the northeast and was therefore not considered.

Recovery of Offsite Power The IDCOR probabilities of offsite power recovery are listed below:

Cumm.

Prob. To Conditional Time Time Recover Failure Phase (Hrs) OSP Prob.

I 0-2 .48 .52 II 2-4 .72 .54 All 4-10 .77 .82 IV 10-24 .94 .26 These values are derived free EPRI-NP-2301 which uses the entire L'S nuclear station population as a data base. The Brockhaven review of the SNPS PRA suggested using updated data from NSAC-80. Thic data is more current than the EPRI data and is also more geographically specific (NPCC data); consequently, it was used in the quantification process. These probabilities are listed below:

O B-2

1 1

Cumm.

l Prob. To Cor.ditional i Time Recover Failure Phase OSP Prob.*

I .63 .37 II .81 .51 III .88 .63 -

IV .93 .58

• I= P=P(I)=(1 .63)=.37 II = P=P (II/I)=(1 .81) /(1 .63)=.51 .

III = P=P(III/II)= (1 .88) / (1 .81)=.63 IV = P=P (IV/III) = (1 . 93) /(1 . 88) =.58 Battery Life The quantification for battery Jife after a station blackout is based en the SNPS-PRA data for time phases I, II & III (0-10 hours af ter the start of a statien blackout). Limited credit was taken for battery life beyend 10 hourc which is consistent with the assumptions of the Shoreham PRA.

Other AC Power Considerations The Shoreham quantification does not take credit for certain enhancements to the onsite AC electrical system. Three nuclear safety related 4150 KW Colt diesel generators, one per electrical division, will be connected to the existing emergency buses during the first refueling outage. This addition will give the operator the flexibility to choose a lead engine, Colt or TDI, to pick up load after a LOCA and allow a live transfer from one angine to another. LILCO has also installed four 2.5 MW non-safety related diesel generators which can B-3

provide power, through the non-safety related 4kV buses. Any twn of these diesels can safety shut down the plant. Once a safety evaluation is prepared and approved, these dieselc will be periodically tested to assure continuing operability. In addition, an onsite 20 MW gas turbine with black-start capability is available (via the 69 T.V switchycrd) to power all safety related loads.

These enhancements will reduce the probability of losing AC power and increase the probability of restoring it in a timely w.anner. An inherent conservatise hac therefore been introduced into the core melt values that are AC power dependent.

Water Level Indication Contribution A detailed, plant specific study was perforn.ed for the reactor water level system at Shorel.cr. Therefore, the PRA assessment of water level reasurer.ent instrumentation centribution to core vulnerability was used. The Shoreham PRA uses the term " core vulnerable" to reflect the impairment of core cooling or primary containment which could lead to core degradation. For the IPE, the terms core vulnerable and core melt frequently are considered equivalent. The FRA evaluated both reference les flashirr due to high drywell terperatures, and reactor water level piping failures. The initiators considered in the break analyses also included leaks and valve misoperation. The drywell temperature initiators were both loss of drywell cooling following other initiators and the loss of drywell cooling initiator.

3-4

The plant, se the analyser describes, has the following cheracteristics:

o Feedwater 3evel control is normally controlled from the side A instrument. (This is the same side as 2 of the 3 feedwater high level trip transmitters.)

o Surveillance testing on the nuclear boiler instrumentation racks is prohibited during power operations.

o The level reasurement system user analog trip units.

o The high drywell pressure permisrive is no longer required for i

automatic ADS initiation. This permissive has been eliminered since l developernt of the PRA. The PRA assumption is, however, conservative.

The calculated frequency of those sequences requiring depressurization for successful mitigation will be lower.

o I.cvel signals are validated once per shift.

o Any work performed or nuclear boiler instrurentation requires written sign-off by the technician and independent ver'ification.

The FRA has concluded that 1) the safety system setpoints are not significantly affected by increased drywell temperature; 2) flashing errors are limited and, in the worse case, there is adequate core cooling when the level is maintained 1

B-5 1

ebove Level 2 as dictated by proce.ieres; and 3) line breaks / leaks plus a ringle failure require operator setion to assure long term inventory in some cases.

These conclusions resulted in lov esiculated frequencies of core melt for such sequences. Nevertheless, LILCO has coenitted to add four new RCIC/HPCI level transmitters by the second refueling outage to eliminate any operator action following a break and single failure. The PRA quantification is, therefore, 1.

more conservative because of this change.

}

t The PRA quantification of refercree line break or leak ham added 2.7F-6 events per year. Most of this added risk is asscciated with Class I sequences. Loss of dryvell cooling has added 1.4E-7 events per year. High dryvell temperature during safety system challenges has added 1.3E-6 events per year and all other wcter level instrument failure modes, including random f ailures and miscalibrations, has added 1.07E-6 events pcr year. The total risk attributable to the veter level measurement system is 5.2E-6 eventr per year.

Internal Flooding The Shoreham PRA event trees for internal flooding events were used in the IDCOR methodology to identify dominant sequences. The Shoreham analysis censidered the effects of floodinF on safety related equipment located on the lovest elevation in the reactor building (elevation 8'0"). This large annuler area i

contains all the ' pumps of the Shoreham F.mergency Core Cooling Systaan. t.1though this arrangement provides the benefits of personnel access, and the capability i

for natural circulation ventilation, there is a potential for a common-mode event disabling all equipment in this compartment.

i B-6

l The detailed Shoreham analysis identified initiating sources and the potential paths which could lead to the accumulation of sufficient water in the reactor building to disable the equipment on Elevation 8'0". The water level would have to reach 3'-10" above the f3cor before all ECCS equipment could be rendered inoperable. Maintenance and pipe failure initiators were considered for the RCIC, RPCI, CS, LPCI, Service Water end Fire Protection systems. Event trees were developed for each initiator taking into account factors such as vulnerability of equipment and automatic and operator action in response to the postulated flood. The results from these initiator event trees were suemarized and then applied to event trees for contrclled nanual shutdown, turbine trip and MSIV closure.

B-7

The calculated core vulnerability frequency for these events is summarized below:

Calculated Frequency -

Event (Per Reactor Year) _

a) Manual Shutdown with 1.2 E-7 greater char. 3'-10" of water in RB (Source f Other Outside Water Sources - Suppression Pool. Service Water or Fire Suppression) b) Manuel Shutdown with greater 6.3E-9 than 3'-10" of water in RB (Source @ CST) c) Turbine Trip with greater 7.7E-7 thar 3'-10" of water in RE (Source (5 Other Outside Water Fources) d) Turbine Trip with greater than Not Significant 3'-10" of water in RB (Source 6 CST) e) MSIV closure with greater than 2.2E-6 3'-10" of water in RB (Source f Other Outside Water Sources) f) MSIV closure with greater than 7.9E-7 3'-10" of water in RB (Source e CST)

Total = 3.9E-6 A

B-8

The FNPS PRA cencluded that the total core vulnerability frequency for internal ,

flood events is a small fraction of the total Shoreham frequercy based upon the following:

o Fath non-safety and safety grade level alarr.s in the Control Room provide the reactor operator with an early warning of potential flooding hazards, o Alarm response and station procedures that instruct the operator to determine the source of leakage either by a walkdown or selective isolation of suspect water sources from the Control Roor..

o A procedural requirement to deenergize boundary valves between Elevation 8'0" and large sources of water when ECCS, Fire Protection or SW systers are undergoing extensive raintenance.

In addition, the flooding sequence does not represent a risk outlier even if all ECCS injection in assured disabled. Other sourcer of makeup sticluding the CRD pumps, condensate system, fire pumps or the service water system could be utilized to assure contfrued core cooling.

l 4

B-9

3 l

APPENDIX C Plant Specific Thermal-Hydraulic Studies As a result of the application of the Individual Plant Eva!uation rethod, no additional thermal-hydraulic studics were perforned. Those available in the PRA, FSAR, generic BPR studies, ar.d calculation files were relied upen exclusively.

+

C-1

APPENDIX D System Dependencies This appendix examines the interdependency of initiators, front line systems and support systems er well as the interrelationships of the support systems themselves. As stated in Section 2.6, these dependencies are summarized in the following tables and were used in the IPE evaluation to assess the potential for common cause failure events.

O l

D-1

--,+w -

- - , - ---w ----- -m - ---9,--w- - ,-e-- + - -w - - -- m --r- ,

l!lll)

/

_ U CS

_ W RM B B C B C R B C B C B C C C C N

R A C B C B C C C C y

a B C B C B C C C C Wr Dp S A C B C B C C C C s

r e B C B B C B C Wl Do o A C B B C B C C

B C C C V

R S A C C C B B C P S

S D E A A B C B I

C N B C B B C C B C C E D D R )

F C 6 F N (

P I A C B B C C B C C E A D R )

S T 8 EM W (

NE 3 f 5

1 C C C I. ST 1 S M

1 Y M

- TS E Dk T I B C B C l i

C C OT S C ERE Y P LFC S L A C B C B C C B P ARP E TOU N FS I B C B B C L

XN S I O T C R N A C B B C T O A R M F C ) )

I 9 9 M C ( (

A R C C B C N

E R

O I ) )

H C 9 9

(

S F (

H C C B C

) )

C 3

(

3

(

L S C C C C S

D O

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r C e p w ) )

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(

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bC C R R

i A

l R B oo O I A D I t C( T RC SUPPORT SYSTEMS ch

TABLE D-1 (Cont'd)

A = Inter-d;p f:;.t (3) = Loss of Div. I or Div. II (6) = Scram en loss of air.

B = Complete dependence will reduce flow by 50% to C = Partial or delayed dependence 4 3 gym. (7) = System car run w/o instr; however, a painiosi level of No Entry = No dependence (4) = Turbine Building Service instr. in desirsble.

- Water (TBSW) can he cross-(1) = Assumes Less of Offsite tJed with RBSW. (F) = See discussion in Sect. 5.

Power (LMW)

(5) = The Fire Protection System (9) = Loop level pump is AC powered (2) = Assumes loss of Reactor (FPS) can be alir.ned to the

• Building Service Wster RESV.

(RBSW) .

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S E )

I R 6 C I ( C A I

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F P T 5 5

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O( B (D D M (4 I A C( FS R 2i t

TABLE D-2 (Cont'd A = Inter-dependent (1) = "C"s Assume ability to power (5) = W/0 emerg., AC rod pon.

B = Complete dependence from Dnerg. Bus. indication, Rx water C = Partini or delayed dependence level, & Reactor pressure No entry = No dependence (2) = Assinees LOOP has occurred. indication are available.

. (3) = Batt. required for DC start. (6) = Instrument Na Systes Each DC has its own battery is pertially dependent.

for rtarting.

(7) = Fire Protection Systes (FPS)

(4) = Each diesel draws SW frou can be used to supply RBSW.

both loops.

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Page 5 of 5 CENERAL TRANSID:7 NOTES

1) All feedwater components are powered from normal AC power except for the following valves and pumps:

(a) 1821*MOV-035A(B) - Feedwater Inlet Shutoff Valve - 1118 (1128)

(b) IN34-P-164A(B) - RFPT Standby 011 Pump - NCC 111B (112D)

(c) IN39-TG-0028 - B RFPT Turning Gear - MCC-112B (d) IN34-P-165A(B) - RFPT Energency Oil Pump - 1R42-PNL-A3 (B3)

(e) IN21-PS-166A(E) - RFP Suction Pressure - 1R42-PNL-A4 (B4)

2) RTPT Trips:

(s) Manual fror rain control board or local trip (b) Turbine overspeed (108 : 1% rated)

(c) Turbine exhaust cacing level high (2 Ft. - 4 in. below centerline of turbine)

(d) Turbine bearing oil pressura low ( 4 psig)

(e) Feed pump bearing oil precsure low ( 4 psig)

(f) Turbine exhaurt vacuum low ( 20 in. Hg Vac.)

(g) Feed pump suction pressure low (250 psig - 30 second tin.c delay)

(b) Reactor water level hfFh (vessel level + 56.5 in.)

(i) Excersive active thrust bearing wear ( 13 psig)

(j) Excessive irective thrust bearing wear ( 13 psig)

(k) Turbine high vibration ( 5 mils)

3) Abbreviations:

! (a) CAI - Continue As Is (b) CS - Change State (c) S&R - Start and Run (d) O/C.U/V - Overcurrent, Undervoltage D-10'

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! DIE 1011ErtW3GfrATim IDIAVA11ABILTIT 119tDC REntAHD SEVIPF MEIDPNr SGN4RIE ]

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eNtalGtACTIW RR(tTHtm i sgrlG' SMG(R MBER MECrTC! PFN) afr IECATIGf 1MIII BffB m DENHtAlly (1)Marmt Rage IB21*LT- 120 VAC Imel Tranesdtter NA - Ihysfally 1ct:sted Verify cri Dill *19EAiO3  ! Ibector lhter 154A IC71-MEr01 for IB21*LTS-154A on 1H21* REAM (Conttol Roan) tint Ime] (IB21-MMERA) OtrS) IC3M.1-emla,B C indicate l

             &'- W'                                                                                                           nomal weer level. If i                                    IB71*LIS-      120 VAC          (1) Reactor Auth                  (1) IH21*f9Er101A       IC32*LT-40flA,B C are not 154A           IC71-Marc 1           trip logic (Relay                 Contrul Poca -     tending nonmal toter level (IB21-561BA)   Remetor               ItnA)                             C M 1ew. 63'       deterudne if tie possible Protection       (2) Q input to                    (2) Arvamelator 1207    cause is ese to a Ices of System (RPS)          the 16 logic for                  Rx Vessel lo Imel  coolmut accident or a           ,

closing the following Trip Fesubaner (PW) ami/or IV Crtup 5 svul 17 valves (3) Conyuter Ibint Control systen am1functini. . Giote: Valve grtage D519 - Peactor If this is the cane, follow  ! t/ are defined in Section low level duminel m ". e SP 29.010.01,

          $                                                              3.6 of the Shordvin               Al                 Smergency Shutdrum and          l Teciviical Specifications)                           SP 29.023.01, Imel Control.

(a) NR Rustdoun Coolirs If one or more chaumets are i Valves IEll89fN47 & 48 famperelde, tabe the follouing l (b) IHI-head Spray Line to actions required by the IGR lEll8PGM)S3 & 054 tedsdad Specifications.

(c) 15R Injection Line to (1)ltth the msber of Rectroslaticsi systm operable dimmels per trip Return srysten less then required IEll890HIBIA,F by the Minimu C5erable . (d) PASS Reactor Saiple Ovrumis per Trip Systemi  ! IBil*SOV-313A,B tvupstrument for one trip (e) PASS Stu91 e Retum system, place the inor-17 ll*S(V-160,169 etabic chsresel(s) mul/or (f) PASS D/W Arm. Seple that trip syster. in the IT48*S W-126A,B tripped condition within (g) PASS SippreHF1Cn I hour. Over+er Atm. Se ple (2)With the number of IT48*RW-127A.B Cperable civmels Issa

741e D-12 Phee 2 of 26 TIE IDPN11FIOtrIGi (F IY7119trIAI. VUUetAB11.ITI1!S RE 10 IN5110errATI(N IMAVA11ABil.1TI NRING ITEIUIATID SEVIPE MEIDPNr SGMARIOS IleICATIGI 3 SwNm S=xm rana aM nG. mn im ImrIm won mun a mmmx ! Murrow Rage (h) PASS Sippreurfte thei requital by the j Ranctor hter Oweber Atsi. Seple Mirdse (Werable Oumela 1mel IT48hSOF-1294,R per Trip Syste rapdrumurt Omtinued (1) PASS Atm.Sampic for both trip systese, place

Retum at lamst one trip evstama IT48* SIN-130 in the tripped enntlitfori

! (j) PASS Primary within I hotar or be in Omtairment Seple Hot Sluitdone within 12 Retum hourn. IT48*SOF-131 (3) Iruitcation T 1R21*t.T- 120 VAC lael Trarvenitter NA - Phystrally S 154B IC71-ntr01 for IF21*f.IS-154B located cm IH21*tMd4 (1821-#0EWB) (RPS) i

m21*t.Is- 120 VAc (1) nascent Auto- (1) til21-nt,-10ln

! 1548 IC71-PIER 01 trip logic Control Rnca - G l (B21-N6f05) (RPS) (2) Prorip inpit Elev.63' ! to MS 1cpje for (2) hmunciator 1207-l closing grasp 5 ed Peactor Vesec1 lar { 17 valves Weer lael hip - l (3) Iruffentim (3) Cataiter Point D520 kn-Iar kter imel Trip Onnnel B1 1R21*t.T- 120 VAC level Travedeter NA - Physically 154C IC71-IMr01 for 1R21*I.1S-154C located tv IH21*IM r05 (B21-N0FOC) (RPS)

l T4le D-12 , Page 3 cf 6 ) i 1 TIE TimffIFICNTIf18 0F PUFRfilAL VUUERAlm.ITI1!5 IN 10 DGImerlW!TGE INVAIIABILTlY IER110G PtymtRnD SEVHtE M1CIDRfr M25tMGi ] lleICKrlm seemt seem poun Puerrfs Ree our IrrArrGI WWM TARS OR DEFHtAIU Ihr m e Rage IB21*L15- 120 VAC (1) Itasctor Auto 4rran (1) IH21*REr101C Tf water level cemet le Rametne eter 154C IC71-RErOf triplogic(Pelsy6C) IIelay Itacan - CB detemined proceed to \ .i Imel - (B21-IEEC) (IIP 5) (2) LA e irgut to Elev. 44' SP 29.023.04 Invel Ce ttmund to IE Icric for (2) Aninaciator 1191- Itestoratim closingt gmg 5 sul Reactor Vesnel Im 17 valves Icvel Trip (3) Irmliestion (3) Caputer Point D521-Reactor Iow Invel hter Trip l j Ovsmel A2 i l 1B21*LT- 120 1RC (1) Ramrtar Arete 4crm (1) IH21*REr10lD Relay 1he 154D IC71-RErCl trip logic (2) Arummefator 1191-Ramreer f

                    "                         (B21-4ENB)        (IIPS)              (2) p a imput to                            \W Imrimel Trip j                                              1821*L15-154D                                  RS Ingic for closing          (3) rami =*-r Ibfot D527-(B21-4068tB)                                   gmg 5617 valva                      Remetor Im hter Level l                                                                                                                                 trip char == 1 B2 i                                                                                     (3) Indicatien Ilmrnar Rage   IB71*LT           120 IlllC           Transmitter                            flA - Physically             11erify law remeter Reactar lhter  15 %              Instnummt            for 1821*LYS-15%                      located on                   water level m I                                                                                                                                                                                          '

level (It21-4 Elf 5A) Flouer lH21*RErO4 1C32-LI-008A(IEC) i Omtinued 1R358MEcR1 on litt1*REr403 arul 125 %DC (Caittel Itoemi). If 11142*RErA2 low useer level is confi ned, proceed to 1B21*L75- 120F AC (1) Im fevel Perudasive (1) IH21*REr]O3A SP 29.010.01. - .r.-y 15 % Innensynt for NE logic (Relay Pelay Recut - G Shutdnun nul (B21-41695A) Pouer K304A) Eley. 44' SP 29.023.01, level IR35*RErR] (2) Indication (2) Arstwjator 1348- Contml. If unter 1cvel and 125 VDC Reector Syst e canime be detemined 11142*1M.-A2 A lev Irvel mter SP .#.023.04 Cmfirmed level Rectoration.

I l T ele D-12 Page 4 of 24

w iterrrrrcArIm or forarrrAI. vulMABILITIES I

IM 10 IIE11DerTKrim IMAVAIIMILTIT IRRING 10 Situ.17D SEVFRE /EIDerr SDlWtIm i (FBIAIGt MTIGE RRFIIGD S1prRM SR83 MWDt 1UCTIm PE E Gff I K ATIGt 18EN FAIIE W IIEPHIAME l ! ADS Imr Imel Pee- . Iterunt Range IB21*LT 120 VAC Trammitter for NA - Physically located udesive channels are , l Ammeter lhter 159B Inctnsumt IB21*LIS-15aB on IH21* Intr 26 imper 41e, declare l Tevel - (B21-M0955) Power M E inoperable per , i continused 1R35sRErB1 the tedetml l sent 125V DC specificatims IM2*REr82 1  : 1R21aLIS- 120 VAC (1) lar Imel Perudasive (1) IH21*REr1038 159B Instement for ADS logic (ReLsy Pleimy Enra - G 1 (B21-19958) Power 1006B) Elev.44' ! 7 1R358MErB1 (2) Indicatfort (2) /rvumciator j O and 125 VDC 1349 - Remeter j IM2*PlteB2 Systems B Inr lael Corifirmed l IC32-LT thifnter- Tresummitter for NA - Trasuedtter Try to deterudne actual

                         -41084        nsptible         IC32-IS-00AA                       is phynfcally located       tuter level. Ifteter (C32-NiO6)  Phaer                                                ori IH21*IN04               level camot be Sigyly (UPS)                                                                     deterudned enter SP 29.023.04. Imel Hestoration.

IC3M S- 12D VAC (1) Main 1brbine and NA - located m OMA Vital Bus RFPr trip (56.5") IHi1*I W 612 (C32-5524A) (IPS) (2) Iliah level trip alarm (3) Signal to A or B Feedunter icvel Serror neiertal r (4) FW Firw Contrul l

Table D-12 , Page 5 of 24 11E 1DFNTIF10tf1Gi 0F M7119fffAT. DUDIDtABil.ITIFS tE 10 IIEmpfMIKITGI IWAVAllABII.I1T DURINC 70Sil1UQ1D SIMBF NETDIET SGMARI0tt GTRKi1R ACflGi RDCL'IRfD SWFIG8 SR5tR REER RNCITfM REM Gfr 1&ATIGI iMIN FAIIJD (R IIEFIBANF. Ihrma 1 hey IC3 M .1- IWuteri- Inlicatim Control Rbcm -

Rasctor w :r 00m rigtible IHI1*IM 4 03 Imel (C3MidiO6) Pbuer C m fasad surply (UFS)

T l Nurma Rage IC32-7R- 120 VAC Norrrw and Wide Control Roan - l 1hter Imel 006 (lar-mal K) Pagee Irwifcation 1Hil*fM A 03 (C3NidOB) i7 IC32*LT- 125 TDC (1) thin 'Rabine sul Contml h - E 001B Ram M2 RFPT Imel A trip IHil*fM403 1C32eU- (2) High 1m el Alarm 00 5 (3) A or E level selectal (4) Racirmlation ficv lindters i (5) FW ficw crmttel I (6) Highfuw alam (7) Indication i IC3HT- 125 VDC (1) Main 'Ibrbine sw! Control Roan - 0(BC Bus N1 RFFF level 8 trip IFil*fMM03 . IC3M.I (?) High Imel alarm 000C (3) Indication - Wide Ragge IB21*LT- 120 VAC (1) High feel Relay Room - if water Icvel camot le Imel 157A (IR355sMcRI) Trip to RCIC IH21*IM.102A detemined proceed to Irdicatimi (B21-M091A) ml 125 VDC (F303A) . (Control Bldg. SP 79.023.04. Twel

    -15(T' - +6Cf'   1821*l.1S-   (IR42*fMcA1)       (2) Irv!fcatim                       Elev.44')            Nestoratim 157A7.

i T41e D-12 Page 6 of 24 i w Uswrrriocrim w amwrrAr.1ormanHms mes so nenesNrATlm IMVAHMH,m itRDC nEltUTPD SEMF /0CIINNr SCMgtRE Tl e IC Nri m swwN suost Must nucrrm em arr irrATIM HEN MHB m MMRARE Mde Rage Insel IB21*IJS 120 TE (1) AIWHtPr Trfp Relay h an IvuHeatie 157Ar (In35mRErRI) (2) EIC Trip Inter- lit 21*ntr102A l G at.inued (B21-4492A) mul 125 IDC face (-38") (Im2eritrA1) (3)Indfestion IW1*LIS 1201RC 0) AIE Trip ratact Relry naam 157AK OR35*RErRI) (-132.5") IH21*IMel02B (B21-4891A) and 125 IDC (2) Cere Spray Trip O m 2 antra 1) Gantact (-132.5") (3) Indicatim Y i g la21*LT- 120 vac 0) icic high relay nom 157s . Un3saRecal) level trip IH21*1u e102s (n21-uG9Is) and 125 voC (2) Indication  ; IB214.IS- (Im2*RtcB1) ' 157E (a21-se935) la21*Lis- 12cr Ac 0) Im,Im1 to nein Room 15m OR3sanacal) KIC (-38") IH21*Mr102B i (n21-se92s) mai 125v 1C (2) An6-ARI and i Om2aRecal) e r erfp . ts21*Lis- (3) Irvtfcation 15 M ,' 1s21*Lis- 120 vac 0) 1 , vel I to Als nelay Roe 15nct OR35aneral) (2) fevel I afsn1 to 1H21*Mr102R (B21-M69fB) mul 125YDC Core Spray (in42*ntral) (3) indicatim ] i

Tale Ik12 Phee 7 of 24 11E 1E8fr!PI0trfm 0F 1MHfrIAL 4t!UEltARTIJTIES RE 10 II5flE9BIDtrIm IMATATIABILITY IMtINC !YETitJMD SEMEtE MI'IDRtr S0515105 (FIWCT3t ACTIS IIIgrIRID i S9FIGE SBSGt 7GER PUCTIS ItIW) (Ur IIDtrifN HEIt FAIlst cit IIEFU5 TARE l Wide Ru y insel IB218CF- 120 1st (1) Imel 8 afspal May Bom ' l Isuficatima 157C (IR398HEr41) for ICIC trfp IH21*19Er102A ! Qwinn-i (321-4W910) mul 125UDC (2) Irufication i IF21*EJS- (III42eng,A1) l 15n. l (B21*IW93C) 1321 6 120 WC (1) ICIC Invel Relay Rom

157cr (Im3MIEr4t]) 2(-3s") Inft. lH21*f9E.-102A Oi21-4eF)C) and 125WDC (2) Kns Sigpal l for IIFT trip i (11142*RErA1)

!7 (3) Irrlication

  $                                                              (1) Imel I trip                     Relay Rnre IB218tJS-      120 W C                                                                                                                  ,

1570[ (IR358MErRI) to MS mul IH21*REr10?A 0121-4991r) mui 1255DC Cnre Sprww (11t%2ana,A;) (2) Indicatim .i l 182180r- 120 W C (1) Insel 81CTC Relay Rnan 157D (IIOS*RErB1) Isolation Ill21*REr102B . (B21-4109tD) mai 1255DC (2) Trulimtion 15218t25- (1342*fWral) , 157tz (321 IW93f) IB21stJS - 120111C (1) PCIC Imel 2 Relay lloom 157Dr (110S*f9ErBI) Initiation 1H21*I9Er102P. (B21-4492D) arwl 125YDC (2) RIWS Sisrel (III42*fM4l1) for Alti sul RPr (3)Trulicatim

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

1 } t Tatue B-12 Page 8 of 24 ] TIE INIfrIFf0trIGE OF IUI11FTIAL WINItABILIT115 1~ nts 1011empelmrTIm IMVAHMILTtY IRRING FGmLMD SEVNtE MEIE8tr SmtMOUS TIefoirim einem Acr1Gr Raymn . suew seemt nsam 7Gerim see mr IrrArIS WW FAHS Gt MTHWWEE l Wide Rage 1mel IB218L5- 120 W (1) Imel 1 sipruil Relay Norm Indiastian 157sE (1R358HErBI) to JES auf CS IH21*I W 102B nuetsmed (H2HW91D) and 125WDC frdtiatim logic j (IIE2efWr81) (2) Indicatim  ; I. i 1321 ALT- 20 W (1) Imel 2( ~NI") Cont ml Feon If water level ausut I 5% RPS) fryue to N54 Icgic IH21*f h 101A he W procent E2H4BIA) for imlatirig Kif. to SP 29.023.04, Imel i B21stJS- Inol and Drain V1vs., Restoration. 55A Reactor werer Se ple 321-581A) Volvnn, PM11 Valve tje sul initiatirgt RIEVS ] (2) ktimmtwo Aruanciator j (3) Truticatim i i 1521* 120 W 1ruliastian Cnntrol Room ! 15H106A Ir5 IHil*fMr401 l ' l ! 1821*LI- 120 imC Iruffastian Contaol Ronr.  ; GE WS IHil*f9EA02 1321882- 120 W (1) ta el 2 MS4 Crntml llore .  ; 135B ItPS tripa(c.f.II-155A) lit 21*fW101B . (B2H4 BIB) (2) Actuates muuseiator l 18218825 1308  ! 1555 (3) Irvlication (B21-568110 , i 1P21*t7- 120 E (1) Inel 2 NS4 Relay Room  ; 155C RPS tripn(c.f.I.T-155A) III21*lW10!C  ; (B21-NORIC) (2) ktuates anertater j IB21*LIS- (3) Iruficatim , 155C006RIC)  !

I Tale D-17 *' Phne 9 of 24 11E IDI9frIFIGITffM OF IWIBfl1AI. WitJMt/SILITIES IRE 10 IIEf1EDGffA11GI IMAVATT ABII.11Y ItRING 10SItt#1TD SEWW NI:IDI9fr !E7MAIGtE (FBRKItR ACritM RB$ FIRED SgrIOC SI981R RMR RBCTI(N RFA GK IllCRTI(N nMiti FAIUD Gt 1!EffitAIEE nede mageinel 132183- 120 VAC 1m!!catim Omerollloom fadication - 0063 RFS IHil*FIEMol g Omtbund . 171218LT- 12011RC (1) Inci 7 IE;4 Relay Room 155D RPS tripn(c.f.LT-155A) lH21*fM r101D l ] IB21eL15- (2) Actuates arumnciater i 155D 1309 (3)Inlicatim IB21*LI- 120 VAC Truitration Control Rmm j f CMD RFS liti1*19EA03 i IE21* LIT- 120 vifC Iruficatim Errete 9medcun If tater Jewel annot 0068 (lim *FpteR2) Pawl be deterufned proceed 1061819EAtSP to SP 29.023.06, (521-4EI268) 1061-LT-006 RB Elev. 63' Imel Festoration. (C61-1E)10) 1061* LIT 120 VAC Irufication Remote Shutdoun Panel 107 Instnsumt IC61*1M cRSP Pouer RB Elev. 63' Phel Zone 1821817- 120 VAC Irulication omtrol Room If water level esmot i Imel 007A (IR35*fMcRI) Ulil*f9E401 le detendned proccert to , Iruticatim (B21-IEK37C) SP 29.023.06,Im e.1 l

  -31(f' to -ll(f'        (B21-IJIWD7)                                                                                     Restorati m.

(B21-3615) )

l

                                                                                                           ;t                  : i D     z                                       y 4

2 Me I t c n f o yi r e g B p 0 1 N si n ehu f r l J. el i e g a ma i T t d rt u e1 ,a w P c0 Ks r 0.f o i s E N pa n p1 a u 0. == h r t R xu e9* u a - E l i 2* r mS9s P= c Wta E f t 0 W m S r o r r r r t W I o r n1A

           !          t                                                                            B E          r      n1 a0                          n0 s1 u0 c

sK t f o6 lo1r o1 R Ec aE rt O R . l E l l E l

r. S m o1 9 o1 9 oI 9 nF y r r* r* r*

E t1 t1 n2 t1 n2 eS e1H nl l A t oF D P CI CI OI mT tA it vi r A .M 2r rR 1 B 1 e G DnnE

                                                              )                                                  l g                       r                           er l

br ear t I os t pro i et r t f o a o t cr S: e i ro mineti aoY ! i 3t c l rt T mL r n4 i 0 upac p (1 u T -s m m u aou nI gPaOc p e m r ra iI i m f ps r i n s c O51 ml s n sic r 6 mA rm t aH a et:o5 e aA s i o et r o5 1 es t Dr e s i t m r A t r n r u l' TtDrl Pet e t a u1 Pt a mV ce o s seS tt mn c uBt t a c rN r eI R i t a c gi PRInbUOA1 rP e n (i g r e6i u ut c2 0l r T v eS pi st 0f rP nbtic2 PRIl unhu6i A1 rT u mm i d ) ) I I

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l r n 1 ( ( 7 3 ( 4 ( 1 ( (

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( 4 ( mx i r I e m i r e n Cf W i t C C 0 1 e R8 15 3 J V A V t u m 0R 2I 1 0S 2F 0S 2P n 1(B 1 R 1R

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                                    )D                            )A              4                      W 7

3

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m T-  ! I- 1 M-r- r RS I 6 r-P f 4r e L e E 4 L- e AH1* AI F N- 8 4

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. e s 1 5 1-272272 1 1 1 262262 1 B1 1 8 26226 3DB803 R5BB5B I 1( I 1( R5B55 I 1( 1 1 1 0(1 0( l a e c w i

-                            a                                 t a

m l i t u eet s s eu m) r mc= ii u s e an= ei n u mn s i se lit ed bne em _ 1 I C r P7 mC

                                                                              ?$

l llijl  !

   !j        > ;   j                    l ilIlil                   )llII]

I I Table D-12 Page 11 of 24

                                                'ITE INBfrIFICNrim ff Pr!TNTIAL 1REMPMILITT75              -

i IEE 10 llE1MMBFDUTm 19EVAIIDILITY IRRINr: PfEIttAITD SEWHtE NY2Effr SCFNAk15 l NUWGGtACrlW ER)fINID syytet seem voingt Tucrim les avr IOCRTim WFM FAIIB m INM5 WEE , (1) Pressene sispel tn HelseInnrug

Pressure 1321897- 120 VAC i immenmanitation 156C EPS IIPS A2 Irgic IF21*Ftte101C l (Ilmseter) (F21-4EF39C) (2) Input to Craputer Continued IB21*PIS Pbint-D517-Femetor ISAC Hiph Pressure Qiamel A2 (3) Actuates assasiciator 1190 I

(4) Irdicatim IB21*fr- 120 VfC (1) Pressure nissial to Relay lloom 'o RFS R2 logic IFll*19EclOID O. 156D ITS i (B21-4E!72) (2) Input to Orsputer 1521* Pts Ibint D5114-Iteactor 15e attsb Prwine our=1 r:2 (3) Actuates muusittator

 !                                                         1190
!                                                   (4) Indicatim l

IB218FF- 1201MC (1) PS151mI(310 peig) PIrlay Rom l i 1581L (IIU58MErill) fa) Auto close recire. lH21*f98.1034 . (B21-4IDF7A) mal pump disdi. valve i lE21*PS 125V DC on IDCA n*ppel 15SAE (IR42*FIErA2) mal low pressive (E21-lEStE) (b) Indication IB21*PS (2) PS 158AY( 33R pnip) j 158Ar (a) IJCI inj. valve Ot21-4165tW) perudasive j !B21*PS (b) Iruficatim l 15AAX (3) IS158AF( II20 psig) a (B21-N697A) (a) A1Mi sippal to j ARI mul RPr logic i (b) Tru'icatim - _.

I i Tele D-12 Pese 12 d 26 i its nsserriocrim w neurTn.wueuen.rrres EEE 10 BBUEMwDtr!W t*AvnI1ABIt.ITY ttRDer: Reft 1JtrID SEstE MEIDftfr SGIWWINE W5utIM ACTE 38 NFITIRID ] SDPRBt MIEER 7GR RMCTIM REM (Ifr IDutr1Gi 15 Elf IgGUD (R BENMARE 1 I l Ptussure IMleFr- 120F AC (1) F5-15ft R(310 psig) . Relay norme Inst w ien 15 5 (IR35*MEr81) (a) Ansto cicae recire. lH21*ME.103 \ (Rnacter) (B21-IEPMB) seul 125WDC gamp dindi.volve Qwiread IB21*P5- (IM28MErB2) on IDCA s*. pol sul 15FR Iow pressure (B21-445tr) (b) Inefestim i ! 13218F5- (2) PS-I5EBr( 3E psig) i 15e7 (a) 17CI injecticri j (321-M53) valve penalsefw l IMief5- (b) Isufication !? 15dm (3) FF-15fEK(ll20I *fa) , {$ (a) JtI15 signal to ' (321-W975) Ar.I malNPT1egic (b) Isutication 15218F7- 120 imC (1) FS151K2(310 psig) Relay Norm 15flC (IR358MErRI) (a) Auto cicae recire. lH21*f9Er103A 1 Ot21-4Wp?C) mul ytmp disch valve IMI*FS158 125 B C m IDCA sisym1 mal C (IM2*11 era 2) low pmusure (MI-45500) (b)Irulicatjeri IE21ap5- (2) 15158CT ( 32 peig) . l 150Cr (a) 17CI injecticvi (B21-4E50C) valw pemissive ! IM1*PS- (b) Indication 150CX (3) PS 1580K(ll20 pair) (R71-6697C) (a) JtI15 ste al to Aft! mi Hrr logic (h) Iru! cation i

t T4le D-12 Page 13 af 24 l llE BRITIT1mr!GI fY IUt1NTIAL VLIMitSTI.1TIFS ! ITE10 EWINSGIDtrls IMMM1 ABILITY IMtDC N1S1 TEA!1D SBetE AEINiff 53NWOW WINUtB ACrim ER$TDED j snelGt m Ment FtstrIGE e W T If o trif18 naet FMIJD m lisyntARF. Fumaeuse IMl*FF- 12015C (1) PS 15 FEE (310 pds) j Issausmutaden 15 3 (13t35snErst) (a) m clame roeire. i Glenctor) (B7HWMD) a mi 1255 tic peg v' isch valve e i Cet1sesul IMieP5- (IR62engrM) Ifita sip el mui I m ! 15sr. prammwe { (Wi-4E5tst) (b) Iruticacian IWi*FS- (2) PS15mr ( 3'E reis) ! 153r (a) IJCI tri%im i j (B2HEMB) tulie peamissfie i IWieF5- (b) Indiention I l' 15m (3) PS15fER(ll20 peig) I E (El-4WWD) (a) AnEE sig al to j AltI med IET Icgic (b) 1r4Hestien l l IC3&ff- 1201gIC (1) TruH a tisse Control ltone Tf hisk remeter preamste is OlB thulatma - (2) h lilll*MEr603 shse to amin tusbine BC , j (CIMHf5) reptible water 1245 fallese, verify or tansfer j IC3HS- 7 beer W Preusse to the badmy prounse 4 003 Segyly Itlpb(Trip 1025 psig) regalater using petumiere . N) (IFS) (3) r- p a r 7btat SP 23.657.01. 7br a singste 161V M32 fi- B0lfr4teactor Pressure h1meism, ruesce power to , I GF3 assure that further161V , 1 (C3HIO5) imistless are not r=ma4 ] by hist seem line fim i 4 l l IB21*PN04A 12D 11AC 1bsustf tter fw < F11104A (1R35aMErRI) IB21*PI-006 mui PR i (n21-4e55A) la21*:7-m6

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! SWWIGE INESIR 7GBR PGICTIS RUD Ctfr InutrIGI 18EI8 PRIIJD C5t IIETf1 AIRE f i h thter IC3HWT- 120 W C 0) Providas a malen ContmlMoss rainwatal for naturated thuinter- stspeal to level IHillMIE403 capulitisse at 1000 psig j 1mel-IWet (105 ruscear vammel pressure, g 4 auge N regtfble controller ifXID7 to i D-lftr' OD6 huur d iste start e 135* stryuell toyeraturir. (C3 M lW) Sagply volwn ILV-0071 & Y If ==e=r level coast be (155) (2) Instication detssudnrut proceed to SP 29.023.M. level l Eastcrutine i i i Sgyuumsim Phol 1M1-17 120 W C (1) Actuate m uunciator Contml Ikan if !hypressian 7bol } l 1heer level 013 (lit 3HIEr51) 1%dWingprecim 11811*19E401 level - be i 1M1-15 mai 7bol Isvel Im ==f=e=f==d above the 013 (lit 3HIEr4f2) (2)lsalientim Must Capacity Insel  ! )

• Imi-LI IJset(Fisese 5 -

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                                                                           ~

segre=e==d below the i i - myyrussism pool lead  ! ! 1enda (Pipse 6 - sr 29.023.m. preened to r l w 29. ors.e5, per sd nov _,- _ = se l I i 1M18t5 125 B C (1) Opasi valve 11%I* NA  ! 092A m u m 2 g es ,- umor, map  ; B2) Suctim frna i

                                                                                                .%,pressim Ibol                                                                                                         !

(2) Actisste arensaciat<v  ! 13R2 - Sgpression  ! Pool Hfph trwel I t _____ ____ - - -~_- .. _ -.

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• Page 17 cf 26 TIE IDRrrD'lotTIG10F FUmfffAI, vtJUEMBII.ITTf5 WE 10 E5tW99mtfRM 19(AVAllABD.ITY It9tDC RE111AIS) SD7FF XI'Iffffr SOIWENE (FlWCTR ACTIM IIB 7910'D Swysy synetR MnER R9CTIm RFM) GUT IDDtTIm W Wf FAH R) GtIIEFI5 NEE

;                      Primary   IC71 M            120 EllC         (1) Proeide sfsyuni to           Control Horse            Verffy en 1Hi!*f9EA01 Quenburst (Kl7A             1CII-FIEA)!           MS Aito-acrum                IH21*f9Ee101A           tium 129)-FI-140 remis Prisere    (C71-atstm)      0FS)                   Icgic (Pelay 4A)                                    mruel pressure sul
                                 ?C71*PIS                           (2) Presse e sfppel to                                    wrify an 1H21-Fit,-

27A 164 for imlatig " 101A, F that , (C71-465fm) the folinnim g mip 1C71*PIS-007A,8 frulicate 0-5 pstg 9,10 mul 11 valws versal prussure. If ' t Geote: Valse ames there's a loss of are defined in molet to the Dryantli T41e 3.6.3-1 of the follow prnr= aire Shardues Tedvifral SP 29.010.01 Pherlyrry l tj' Speciffestfrum) .W. SP 29.023.03, i g (a) Dryuell Inerting Contafruent Omtrol su! i IT24*A0lMJ01A.B SP 29.023.01 Imel (b) s,p.ouder Inertig. contml IT24*AplM)ntA,5 (c) Pt:rEe Air to Drytell mut Supp. Oumber IT24* N (d) Furye air frum DN 1 -d sw.o eer IT46*M11MD9H' . j (e) Vent I.fre DN i IT4MIDIM)78A,B I (f) Vent Line Supp. l O& ITW/H4-U N .B (g) Seple Gelme, i from TJV IB31*NV-ORI.R7 (h) Flrer Drains imn DN ICI19EN-246.747

Tele D-12 Phee IR of M i 1TE IDRrrIF10 trim (F FUf1IfrIN.14UE51ABIIITIES RE10 EEIN999'!NTim IWMAIIABII.I17 It9tDC 706fttJ01D SBYPE KI3DFIlr SGIWElfE DelCMrfs Splem 7tBER FtStrfGt RFm GFr IDCRrim 15EN FIUUD Gt DERBiANE

!            spelet Pttuty                                         (f) Fig. Drains frvm Dhi Gmentsmet                                           IC119EN-248 & 249 Puumene                                        (j) SnapP.Fbol M8'r }erk Quessmed                                            IC119 0 H 19C (k) Sig.1bol C/LI Return 1Gl9EN-3M.R 1                                                        (1) Siw.Phol C/U MW                                -

1Gl90F-MA.R (3) Initiates RIEUS/OtAC i mut TIP withermaal (4) Inutication (5) Actinate sumaciater y 12cs - Primary

• Omtaismant Ri$ Presswe IC71TT 120 VAC (1) Pewide siputi to Control Rorun OC75 WS RPS Mo-Scrm TH21*19Ec101E i

! Cl-5W5tB) lye (May 48) ' ! IC71gIS (7) 16 input for 007B grog 9,10 aruf 11 Cl-555tB) valvens (c.f.*FIS4107A) - 0-5 poig (3) Initiates RE/utAC mul TIP withdraal (4) ktuste monsitiator 12tMYisunry Contain-sent 111$ Prvssure (5) Ir:11catim I l

T41e D-12 .hy 19 of .6 11F TITNt1FIOtTTGt (F FDITFnAl. DLIJWIAETI.ITIF5 ) WEE 10 IISIM9etDtT708 IMWAIIABII.ITY ftFIIC pm114171D SEVBtr. NEIDPNr M351ARME i IISIOtrIGE WIRtim ACTIGI Ritp1RFD SWFNF SBEER 7GER M9ErffR Kpge Gyr 100tTf5 WWIFAlla m N Primary IC71*Fr 120 ific (1) Ptivide sipal Reimy Morza Guth 00 % RPS to RFS Auto-Scran II'llef9te101C 4 Pressure . IC71*FIE lye Glelay 4C) Quitimed GHC (2) 16 imput for gitusp j (0-5 Poip) 9.10 ml 11 waves (c.f.*FI!MITIA) (3) Initiates NEW5 OtAC ml TIP with-draal (4) Actustes assasiciator lT ll h Qv.tain-I$ must Iliph Prempire (5) Inlicatien M71*FT 12D IIIC . (1) Provide stigel to Relay Rotun GUD IFS y Aut H5cnus legic 1H21*19te10TD (C716) (2)16 buyut few greg  ; IC718FIS 9.10 and 11 valves ' 0D2 (c.f.*PfS 4107A) (C71-455tB) (3) Initime== RIEVF/ GWC O-5 psig anri TIF wittuiraal i (4) Achamrass avesuchetor , t I lf"J. " -y Ositain- ' ment itide heemsre (5) Inticaum i I L t i

TWJe D-12 Fay 20 of 24 i llE IDIWrDENrlOf & FUrtgfrfM. MEJWABII,1TH5 IK 10 m INIMAIIABII.ITY ltWDIG IWJ1EArID set'PPE MI"IDFIfr SIEERIGi i WI5WERR ACTIGE IER7!!RFD j SWFR34 m RER RSCFTfW RPN) Gfr IIDtrIGt 15EN FATIJD (R IIGERAIU i 1 l Firtuary 1293fr- 12D W C (1) Prwide prmure Control Room ' \ rwh 14D (IR3HIEAt2) cisput1 to IRF asui IHil'IMr601 j Puummme 129}F5- ad procmss ver i Outsuand 14 0 (IR3 H R -4t3) (Qup. Pt.G7Z2) (12-17 pois) (2) Sipal for  ! N Cantahment Prmure Itide (3) Truffascian [ 1293* 120 E (1) Provides maior Omtrol Rom

• Fr4 EDA.B Div I (A) to process amp ter lHil-fM.-MM 12936 Div II(B) mulPRF aspner FR5DIA B (2) laulicatim

!                          (-5 to 130 l                          F888)

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Imi-Pf- 120 WC Truliantfore ramte 9markan

) 012 Instneunt Panel < 9 (061 MIt7) Pauer R.B. Elev.63' j 12-17 psia i IE119F 120 WC (1) Imel I sient to Reisy Norm 165A (IR3HItrRI) I K I auul Core IH21*fMr102A (Ell 4El9tA) mal Sprav logic 0-10 psig IFl18PIS 125 1EIC (2) IWCT fnf tIatim l MSA (IM2*RErAI) (3) Irulication (El1-IE91A) . l IEll8FT 120 W C (1) Imel I sfpruel to Relay Room I 1655 (IR35*!MrBI) IKI mui Core IH71*IM r!O2B ] ' (El1-H091B) mut Spey logic D-10 psig 1El1*l1S 125 1mc (7) Irdication 165P (IRA 2*MErBI) (3) 1901 Inf tfatjan

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1 T ele !bl2 flee 22 of 24 , 19E INtfrIFIDirIGE & PUmfrfA1. HUE 5WEU.TTD5 IRE 10 B5tRIEfffRTIGI 15tWAIIABIL11Y M1tDIG PETt1AI1B SEWW. MI3Ntfr SEEMitME , W I W tI W t J C TItse p fi i SWRIF S3951R IGER 7t4CTfW FDD Gfr IEDtrf0I MEIt FAIIJD (R IIENHtANF.  : l

Sgysussimi 129F1E 120 WIC (1) Artustos argumcfator Getrol linrm Ibliow sectism 3.1 of q Ibol itutor timer Ilr5 when trayerature IHil*fMrMN SP 29.023.03, Omtatri-l Tmgerature IZ9FTE _ 110*F umet O utrol ,

i 11195T (2) Isulfeatscri at one  ! , IZ9FTE font level I , llM (3) Sfpal to HIF Grymter i ! 129F1E } 1135T

;                                             1293-1515 3Glk                                                                                                                                                                '

(50to25tfF) 7 1Z911E WS (1) Actimates a misiciator Gmttnl Ikxn i 11GEZ OE7 when L4.,4 .rc IHil*I9ErIYP 129F M ll0*F t I 11115Z (2) 6dicaticri i l 1293-1E Nnte: T4 4.se i 11215Z asneed at one foot i 129FTE level l IIEEE (3) Signal to FPE tver-ter 2 IZF11t5 501B . (50to25fF) i t i IZ9381E EPS (1) Actaistes muusrfator Gmtml Doom i 133-135A OMB whm temp. _MPF IHil*PMcITN 12938 DIS-503A (2) Irutication  ; NOIE: Temperature i moed at 2 it. level (3) Sigel to HIF Gmpsiter l , t

Thble D-12 ftge 23 of 24 11E INNrIFIOtrl(W OF MH7FITAL VIIJE!RABD.1THS . NE 10 IIE!IE9ENUTTIGE IMAVAllABILFlY N71NG 70STitJtfED SEVfRF. ECIDFNr SE21WitIOS (FERRIGt JCTRM Ruy'lltFD surny seen EUMBt MMCT!W RF2 (RFr IDCATIOf WWW FAIUD CIL INNTPM Sgyuussion 1283rIE RFS (1) Actisites aruumciator Contml Raum 1%ol Witer 132-1355 0468 de temp. litt !*1MrMM Thuperature IZ93* tits _90*F i contfrased 50 2 (2) Tru'icatim N117.: Taiperature nenned et 2 ft.lew1 (3) Sly:n1 to 15tF Quputer 106181E 120 VAC Trulication Remote 9astdown 022A Instnannt Pau1 1061-T1 1%uer R.E. FJev.63' [ i- " 022A 1R35afIErB2 (50-150 7) Indiention Remote Sandoun / 10618tE 120 VE . M3 Instnsumt Fawl - 10il-T1 1%uer R.B. Eley.63'

!                  022E
!                  1Ent*              120 VAC           (1) Indication                      contiel Rocui TI-152             Instnsent                                              1H11*!Mr601 1%uer                                                                                      ,

IR25FIEr82 Dryuell IT47 120 VAC (1) Prwide signal to Contml Roe Fbilcar sectkm 3.2 Tm.imw 023A Instrument process compiter IH11*IMr601 of SP 29.023.03 170 FT1 1%uer (Qup.Pt.0721) Contairummt Contml 137 (2) Indication l

1 Tetle D-12 hp 24 of 24 11E 1EBir1FICNrim 0F JUIBirIAL MUFRARH.1TTIE EDE 101M5HDENIXrim l91AVAIIABII.11Y DIRDC ITE111AltD SEV5tE ACCTIT)fr TFMARIm DOICATIm SDF10t SHEGt IOist PurTIm READ Oltr ItrATIGt Imst FAIIJD OR 1NnPNtANE e Dryuell IT47-TE (1) Putnride sigpalm to Average Dryuell

     ',-e                     27A-L                                process amputer                Tceperature                                        "

Continued displayed via video grapidcs 18 Rumeter APIDb RPS AER (1) Renetor Pbuer Control Room huer (2) RPS ser m ig ut IEll*fHIdO'l Dryuell IT4 M RS 120 WIC (1) Provide indication Contini Roan Tegerature -020 and Vital Bus for the following lHil*IMe%C2 IT47-TRS (IR3HIEr01) temperature elements tjs -030 (a) IT47-1E21 M e (b) 1T47-7122 M (c) IT47-TE23 M (d) IT47-1E24 hD (e) IT47-TF25 A-D (f) IT47-1TJ6 A-D 1061-1E 12f1 VAC Indication Roote 9estdown 021 Instnment Panel 1061-TE lbuer R.B. Elev. 63' 021 , 50-IS0*F

APPENDIX E Event Treer This appendix presents the plant specific event trees that were utilized during the Shoreham Individual Plant Evaluation. The majority of the sequences were quantified using the IPE generic trees, in conjunction with Appendix D of the methodology. However, two sequences were very plant specific and did not permit the development of generic event trees. As directed by the IPE guidance, LILCO used plant specific event trees for the Internal Floodinp and the Reactor Water Level Instrurent Line Leak initiaters from the SNPS PRA. For completeness, these trees are also reproduced here. E-1

i i i i l 1 i SUPPORT SYSTEMS ACClKMT ! actm cantans . IFFSITE ALL VITAL SERVICE MvaE na SEOUENCE SEQUENCE SUPPENtT 1 INITIAM AC POWER DC BUSES IJATER ""TP STATE l NUMER FREQUENCIES Tv AVAILABLE AVAILABLE AVAILABLE em% g, gg . TanssacNT DSP DC StJ RC Tr 6' A

e T ,- E E +

\ t M i sc.-6 s.9 E - 5

       "                                                                                      T;-StJ                   inansrEn to Loss or stavn:E unita EVEN1 TEE
               ,, g                               2.u c - 9                                   T;-DC       6  E -5 ys EVENT TKE                         L 2.L4 C.y                                                                  l.6 E -3 T,-DSP                   vaansrEw To toss or               <

orrsnt - - J EVENT TKE i j + K ELIGISLE ' 1  ! l k I 1 3 , ) IPE f irjure 4.1-1 Support State Event Tree for General Transients : tiw6% 1. "P .. 2 i

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SUPPORT SYSTEMS ACCIENT

                                                                                                       "*           SEGUENCE         SEGUENCE           NT WFSITE         ALL VITAL SERVICE                 Hvac m TM       AC POWER          DC BUSES      IJATER            "T P                                               STATE g                                                                         NUMKR       FREGUENCIES j                                           cwn        AVAILABLE AVAILAKE AVAILAKE                       em res                      (PER YEAR)

TanssEWt DSP DC SW RC T o 3G ' A E T-RC i + r* SE-6 T-SW 1 B E -G- - To e . or stavam uTn cn  ! I

• EVErff TREE '

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IPE F igure 4.1-1 Support State Event Tree for General Transients : usW cloSoce t

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i i SUPPORT SYSTEMS ACEIK MT , ALL VITAL SERVICE " wva c na SEQUENCE SEOUENCE NT WFSITE , j INITIAT M AC POWER DC BUSES tes we IJATER ""'E su m NUMER FREGUENCIES STATE i ruasu& AVAILABLE AVAILABLE AVAILABLE enrn r es WER YEAR) . Taanss[WT DSP DC SlJ RC _- 3 o.so g c T-RC E + I M l & 5 e -4 T-stJ 5 E-7 inanErEn TD Loss er stavact unita

EVEMi TKE 14c-u T-DC 2 *4 E ~ 5 , ya

          ,,,jy 24 E-5           [VE'" TKE 2 9 e -9                                        T-DSP                       TaansrEm To Enss or a                                                                                                      arrssi[ rotam EVENT TKE l
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i i i l 4 l SUPPORT SYSTEMS ACEIKMT T c, i tFFSITE ALL VITAL SERVICE Smi" SEQUENCE SEQUENCE NT f INITIATM AC PIRKR DC DOSES IJATER

                     %, +
                                                                                     "I fr"C n          NUMER           FREstENCICS                  STATE we,sev                                                           m t

ye AVAILABLE AVAILABLE AVAILABLE m , M58 TNT DSP DC StJ RC l T o.aq g E i Y t T-RC ,

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                     + pre nsa r 1
                                                       * . t 53 + IG- 3)           =  84.4 6-G /Y'      T- SvJ (Q ?. 5 t-3/9 r *          '(5 c. -5 L *** k 'OU Y ' D) R*'d** b'Id"'-                                ;
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{ CD-hat /d vesic.wts b c 5W) , IDE figure 4.1-1 Support State Event Tree for General Transients j i

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                     *5                                             anm enrm as EFFSITE   ALL VITAL SERVICE      uvm: an   SEQUENCE     SEQUENCE         SUPPWT I"]E        AC PERJER  BC BUSES      IJATER  "' E        NUMER     FREGUENCIES          STATE l               %h                  AVAILAKE AVAILAKE AVAILAKE        rnra r"               (PER YEAR) l                    inansstwt          DSP           DC        StJ      RC i

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IPE Table 4.2-3 SupetARY TAR E OF INITIATOR FREQUE KY FOR STATION BLACKOUT StsetATION OF CONTRIOUTIONS TO LOOP INITIATOR FREQUEKY (PER Rx Yr) SUPPORT STATE EM NT TREE 5 N0 DES: (STATION BLACKOUT: TRANSFER IRITIATORS ONSITE & OFFSITE INERT . FREgIENCY I AC POER UNAVAILABLE) = SUPPORT STATE REFEREEE SOURCE BTER EMNT TREES (PER Rx Yr) CONDITIONAL PROBASILITY CONTRIBUTION (SECTION/ FIGURE NO.) LOOP (Figure 4.2-1) es T,.-RC

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, anos a I i I I l . IPE Flysre 4.2-28 (Sheet 2 of 7) Time Phased Event Tree for the Quantification of the  ; Conditional Probability of Sesccessful Coolant injection  ! Following a toss of Off-site Power Initiator i l . l I

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l IPE Figure 4.7-28 (Sheet 3 of 7) Time Phased Event Tree for the Quantification of the

Conditional Probability of Successful Coolant Injection i following a toss of Off-site Power Initiator i

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I Time Phased Event Tree for the Quantffcation of the IPE Figure 4.7-70 (Sheet 4 of 7) J Conditional Probability of Successful Coolant Injection i To110 wing a toss of Of f-site Power Initiator l' l

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 , mismusen, se ser semeses WF-esse ramt a e seer ese a ses = ansa.                                                       -

amasumus, as ser summmes senz M e seus. m m mera m g ye muussa M ECtesetA IPE Figure 4.2-28 (Sheet 5 of 7) Time Phased Event Tree for the Quantification of the Conditional Prohability of Successful Coolant Injection following a loss of OfI-site Power Initiator

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.I  ; IPE Figure 4.2-2!! (Sheet 6 of 7) Time Phased Ivent Tree for the Quantification of the l Conditional Probability or Successful Coolant injection Following a toss of OfI-site Power Initiator i

A K 3141E CEE.9EE M WDf43Y ist Pgest ws a>6 iEBIn niusmit afsnt smKt monase MEOme 754A 3 WP N MPRE33tgIF KMDIEE TESIOtr CLASS W 37310E MEWWEKS KtsvDES 2A153e M3 Meets eta au vet telt pgthK NS LBuG TEms IELY EV 9 W O i' u . .c-<

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IPE Figure 4.2-78 (Sheet 7 of 7) Tiene Phased Event irce for the Quantification of the Conditional Probability of Successful Coolant Injection Tollowinrj a loss of OfI-site Power Initiator

IPE Table 4.2-4

                         $WWERY FLOtt CMART OF THE DS STATES OF EACM LOSS OF OFF-SITE PSER TIE PHASED EVENT TREE

wa in.- - at. I . -5E II -5E III -M. IT T

L955 OF E (9 - 2 MO N S) (2 - 4 HOURS) (4 - 10 NOURS) (10 - 20 IWURS) OFF-SITE FSER FIG. 4.2-2h FIG. 4.2-2h FIG. 4.2-2b FIG. 4.2-2b FIG. 4.2-2c T M5tf Closure RSIV Closure RSIV Closure M5tf Closure I ( b /RI YR) (eae4/RI YR) ( 1 /RI YR) ( L /RI YR) ( c /RI TR)

• Class IR Class IB Class IB Class IR Class II (s.w+/RI YR) (ss-VRI TR) (5.w+/RI TR) (sw.pt YR) N +/RI TR)

Class It es la w /RI YR) b Transfer to Transfers to Transfers to Transfers to Transfers to: Phase I Station Blacteet Phase IM- MPCI Phase IIIA Phase IT TU (Table 4.2-3) er RCIC (4-5/RI TR) ( - /RI YR) (f.wSIYR) (&as-WRI TR) (7.te4/RIYR) O pot-5 YR) (1.ts-5/a4 ya.) Phase ITR Phase ITA Phase ITA - ( ----/RI TR) ( -/RIYR) (tas4(RI YR) Phase 198 Phase IVS Phase IVR b.u-7/RI YR) (uc4/RI YR) bar4/RI TR) TOIAl L_ _

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9sPtytT SYSTEMS I ACCIKMT INITIATDR SMALL AC . E BC SERVICE ",gy SEGUENCE SEQUENCE SUPPDRT M WTER *Tg ", NUNKR FREGtKMCICS STATE BREAK AVAILABLE LOCA AVAILABLE EEEPT 1 AVAILABLE e rm m (PER YEAR) Sp AC BC S1J RC

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l 4 I i IPE F igure 4.3.2-1 Support State Event Tree Diagram for Sequences following a Medium LOCA Initiating [ vent l

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• MEVALDA1ES BASES 19190 MM NLECTMBt FREM Line PRE 8stmE Pters Ang IrtaATNut K WW SYSTEM 10 SDETVE CDISAllWENT DEAT.

      ** NEPWESDW31DE E33851113tA1, PsepasgLs1T y 10E tataVAILAsdLs1T F sgnet                 -

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IPE Figure 4.3.3-1 Support State Event Tree Diagram for Sequences following a large 1.0CA initiating Event

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l l t REACTOR EQUIVALENT EQUIVALENT RPV LEAK WI IN TIE S " C A5 0F TO TO ACCEPTABLE SEQtENCE PRESSURE SEQUENCE REFORE VAPOR POSTULAT[0 l l E l DESIGNATOR RUPTURE SUPPRESSION PE CAPA8ILITY R ING (FREQUENCY PerRxYr) DEGRADED HISSILES E0RE R V D 0 2 I Medless LOCA Breach R 0 7E-0 'I'7' IRA I.E-5/RnVP Large LOCA Breach .. .., 3E-6 R0 "2 . . , RO2 I "1 2.lE-7 Class IIIA M

                       ',                                                                    LOCA            0'1                                                    -
                    ~                                                                        Breach                                                                       "0"2"It      8.0E-8    Class Illa Large LOCA 10-2 Breach          0.3                                          RRRLD                                                         i 021      8.1E-10     Class I110 Exceeds

[CCS 0.1 Capability E "0 2"1LV Class IIID NOTE: The RPV rupture event tree has an additional level of detail beyond that provided l'n WASH-l400 and is meant to provide a f ramework to display the types of pressure vessel failures which may occur and their relative likelihood. This additional level of detail is only to provide a means for property classifying the potential sequences in their appropriate consequence clanc. lin f or-tunately, the amount of evaluated applicable data has not significantly increased from the time of WASH-1400. The net result is that the eveluated frequency of RPV rupture is similar in both evaluations. IPE Figure 4. 3.4-1 Event Tree Diagram Ior Scquences Following a Reactor Pressure Vessel I.tCA

M al M f9900 (M ANO 99W18905 O samtg ime MeaN stest s Ms ,Ng ",h g[,7, I I, Es IMI tsuminAtt f* f* s' y-g ( f* A er . g et 4 ,v' e Syv *f

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• Sequences for which Subsequent Isolation of the Break Occurs Require Contairunent Heat Removal. Failure of Adequate t.ontainment Heat Removal toulri Pesult in long Term loss of Containment Integrity.

IPE Figure 4.3.5-1 Event Tree for Large LOCA Outside Containment (See Table 4.3.5-1 for Quantitative Summary of Intitating frequency)

IPE Table 4.4-la StiretARY TABLE OF INITIATOR FREQUENCY FOR Tl'E SPECIAL INITIATOR: SERVICE WATER UNAVAILABLE

                                                                                                                                             ~

SUP9 TAT 10N OF CONTRIBUTIONS TO LOSS OF SW INITIATOM FREQUENCY (PER Rx Yr)

                                                                                                                                                                                                                                                                                                                            ~~

SUPPORT STATE EVENT TREES SERVICE INITIATOHS WFTER UllAVAILABLE FREQUENCY X CON 0lil0NAL PROBARILITY = SUPPORT STATE REFERENCE SOURCE INITIATOR (PER Rx Yr) (SUPPORT STATE) CONTRIBUTION (SECTION/ FIGURE NO.) Anticipated Trantients Turbine Trip (, . 1 S G -p ~3 4 E-F 4' l A

                                          ~

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Loss of Condenser Vacuum ( 0 39 " ~b 1'D t K 2. e -3 t *E ~5 4 4 E-p q.1 1 b Loss of Feedwater 8.10 56 5.o G I g, 3, g , g-Saull LOCA . t_q s3 e 4 g ,1 g_q q , 3, , _ TOTAL 6 G C -5'

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) SUPPORT SYSTEMS ACCIDENT l i INSTRUMENT RDOM SEQUENCE SEQUENCE SUPPORT IN'FSITE SINGL.E j INITIATOR AC DC POWER FREQUENCIES STATE CIRC A Im COOLING + NUMBER i POWER BUS WATER (PER YEAR) Tsw 0SP DC 1A/CW RC l Tsy 6 ** A

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                        ='L5                               :
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mnm,. s

                        ... s   i.n .e me        e . . e im e.            i.      .e . .                       m-                                                                          L
                             .e         u . a e. = ..us            en..           me,...
                        . s        5 = a e e s.e, i.               . -p ....i. e..-, ..i. .. .

j

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                                     ........aw...........,..............                                                                                                                  ,

e. ... .. u. mi . . ... . .

                                                         *IPE           figure 4.4.1-1                               Support State Event f ree for loss of Scrylce W. iter                 :

Initiating Event

o -- c " "j

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415 E-45

                         ]NITIATOR                            SUPPORT SYSTEMS                                        ACCIDENT

IMSTRUMENT OFFSITE SERVICE RDOM SEQUENCE SEQUENCE SUPPORT NITROGEN AC POWER DC POWER WATER CDOLING NUMBER FREQUENCIES STATE FAILURE AVAILABLE AVAILABLE AVAILABLE AVAILABLE (PER YEAR)

T]A DSP- DC SW RC Tgg 2. s E-3 TaAnsrER To SUPPlutT STATE A C . E teJ'-* TRAnsrER TO Tyg-SW SUPPORT STATE 3 (Tgg)A) um

                                                                                        #                               E
 ' t:                                                                                              TJA-SW-RC                      TRAnsrEn To i                    t.5c-5Av                                                                                                 guPPORTSTATEC
   $                                                         2.qu-4                                                                 gg) ARC) ==

Tyg-DC 6.OE-7 TgANSF g yg z *-9 fPORT iAnc STATE D 1 T,goSe . c..c, e y j FETES O Thes stoport state es Jud0ed to be equsvalent to the plant state Incurred fattousne the LOSP estentor. um Transferred to comparable loss of servsce unter steport state, i l IPE Figure 4.4.4-1 Support State Event Tree for the loss of Instrument Nitrogen i l

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1 IPE figure 4.4.4-2h fvent Tree Diagram for Loss of instrument Nitrogen Coupled with tinavailability of Service Water: Support State 11

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1 i

INITIATENt SUPPORT SYSTEMS ACClK MT I IENtV MSITE SERVICE REM 3M SEQUENCE SEMEEE NT AC N R E NR WTER MIM NUMBER FREQUENCIES STATE TRANSIENT {

                + SINtV                              AVAILABLE AVAR.ABLE AVAILABLE AVAILABLE j                                                                                                                                                                            (PER YEAR)                              '

! T1 DSP K StJ RC I l { Tj W TRAnsrm To ' j StFPERT STATE A E E GLIGI3t.E T j-StJ f. TRAnsrER To ' I 5E-4 SUPPORT STATE 3

                                                 +                                                                  I' M                                                                                                                                  T j -StJ-RC                          r.5G 7            TRAnsrEn to l     *E'
                       'l#/Y"                                                                                                                                                                   SUPPORT STATE C 2%E-9 Ts_ oc.                              3, c, E. s 2 %E -4                                              -

T 3-DSP 3.4G-S TRANsrER 70 l StPPERT STATE 3 1 ,

                                                                                                                                        + TM Nm T.ble 9.u -ia l              +               S==Ma of tow EMiov n{&enced m AfP Al                                                                                                                                                  )

l J i 1  !

IPE Figure 4.4.6-1 Support State Event Tree forSORV Initiator l

l i

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                          ?I ae e     ret e

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                                         =                             z et et
                                                                                                                                                               =     7 5

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                                                                                                                                                                        ~

8 B5W 4

                     >      ?

im t W I s ( o o 2

                                                                                                                                                                         ?

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E y $ q 3 li,dl 18 I I

                     .                                                                                                          a L2 e
                                                                                                                                                                         .i m

M Ed a 91 v E k se ta-R + 9 P" E-52

l JnITIATOR camTamotni CINWANeCNT Cornmot HIGH LOW PRESSURE Rx SEGUENCE SE0lENCE SEeUENCE JORv PitESSURE DR REACTIVITY EDMTROL PRESSURE BEPRES- PRESSURE LDrtG EDDLANT BESIGMAT0f FREcutroCY CLASS l 1 + S(NtV EDNTROL SMuti Ttaps INE CTION SURIZATInn INJECTIDN TERM INVENTORY (PER YEAfD

      'Tv-uf-RC         C            S                                        90                  X           V       W         QUV IBC I

! IBC i 'M -3 t, O i TgWOUV f CLASS ll Tyv ( CLASS I IBC (A E-3 E -

    $                                                                                                                          ..c>

Tg m L RASS El l.% -2 fcC-5 Ty ( MS 1

                                                                                                    ~3 TgGUN         k        class !

l.5 G ~7 ggc ctass 3: 1 C- f. IeO T3 Souv 0 class II:s sc-< TC g egg 33g 3 IPE Figure 4.4.6-2c [ vent irce Diagram for 10RV/SORY Support State C

w E

• H

                                                      ====E w  w

• A

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         '                            =  "

u = = 5h B- wg i a me ea W g - B 5

                #n E

E E ll5 >> 2 a a5 & 9 0 o l -- E a -

                $g#  E                            t lld g l"                 i t.

5 N E 0 > 7 A 315 $ r 1 3 . i AB E M3 x $  !

                  *I                                        .i                                                    :

5 " 9 g 515 $ $  ?

                                                                                                                   =.

l gg

                         -                                       +                                                  e h                                                                                                    h
                       -  o                                                        e w
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                   ' JnlTIATINt              cineralmapst cortfamequet caretant 3DRV                 PflESStatE        HIGH                           LOW                                              FEOLEftCE SEOUEteCE PRESSURE                       Rx                            SCOUDeCC Det   staCTlvlTV CONTftOL          PftES$URE KPftES- PftESSURE                     LDMG                    CDOLANY    K SSEM4101 FRCOUENCY      CLASS 1 + SORY   CONTRtL     sM ati TEsse IMJECT10N SUR32ATanre litJECT10N                   TERM                   INVENTDRY              (Put VEAR) j                   E'C-             C               S               OU                x          V               tJ                     GUV l                                                                                                                                                     m                      _

i

                                                                                                          '4 2E-4                                    E                      ~

f L.0 ) Tsueuv i CLASS Il

                                                                                           ' ' 4 "-

7v3 50 E -T CLASS I nu - Y 3: 9 w -s. m - t.o T3SWOIN f. CLASS II

o.i i.%4 T3SUV T- CLASS I

(. 6G-3 Tgetat 2 4C-F CLASS I

                       %CS Iq 4,                                                                                                IBC                CLASS II l                                                                                                                                      t.O                .

l T3 Sauv f CLASS lilD

lE-5 l Tc i C.

l IPE Figure 4.4.6-2d Event Tree Diagram for 10RV/50RV Support StateE

     ,_Aa         a           .se          ,      a .- .-        e , m   ~          s -a-,w _a _.      ----~a   - - - - - - , - - - - - - - ,,

g [R , . 3 = W

                                                                                                              ]
                                  '2
                                                *

• 2I *I  !

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                                                                                                                                   !=          [I         l I                                                                                                                                31          58         '

et a y;  :.5 {tug . a s s s s s ,a s a g ,, j,j  ! n y 5 hk l

                                                                                                  =
                                                 ,                                                            1                     y *n.9                !

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                                                                                                  .                                   ,i j

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                                                                                                   ..                                 i E-56

IPE Table 4.5-4

SUMMARY

OF THE REDISTRIBUTION OF ATWS INITIATORS (Derived from Figure 4.5-1) (Example) APPLICABLE TRANSIENT FREQUENCY REDISTRIBUTION TOTAL . FIGURE INITIATORS (PER RX YR) FIGURE 4.5-1 NO. Turbine Trip with Bypass & FW

        - High Power      49                       - g , (p          i.S       4.5- t A.t
        - Low Power        g , g-                     ,,__           g,y MSIV Closure
        - High Power          2%                   + .q q             ,;       q,q,. p ,g
        - Low Power-        ,o q                       -
                                                                     ,og Loss of Condenser

, - High Power *%O + **l

• 11 4 5-2A.2.

                                                                     ,oq
        - Low Power       .09                          ._

Loss of FW

        - High Power        s ofr 4 5- ZA.3
        - Low Power                              +Jl                  2.z
                            .02                      ~
                                                                       ,et i

Loss of Off-Site Power . cx, l - , cg,7 4 5-2A.9 ICRV ,o ; "

                                                                       .07     %.5-2A 5 TOTAL Note: To be used during implementation of the method.

e e E-57

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       ..                     .s___________________. . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .                                                           -

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   = u-5 L dh                                                                                                 6 m  -

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i l PRA Figure 3.4-45 Event Tree Diagram for Sequences Following Reactor Water Level

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A ssmis industeist Farum, Inc. 7101 Wisconsin Avenue Bethesda.Mo 20814 4891 Telephone: 0011654 9260 TWX 71082496o2 AToMeC Fon DC John R. Siegel Vice Pees. dent March 13, 1987 Mr. Harold Denton-Office of Nuclear Regulatory Regulation U. S. Nuclear Regulatory Commiss. ion Washington, D.C. 20555 ,

Dear Mr. Denton:

The nuclear industry has sponsored the Industry Degraded Core Rulemaking (IDCOR) Program to ensure that industry insights regarding severe reactor plant accidents were made availabic for use in the regulatory process. IDCOR reports 'are protected by a copyright held by the Atomic Industrial Forum, Inc. to ensure that the rights of program sponsors are protected. Members of your staff have noted recently that restrictions on duplicating .. copyrighted materials may inhibit widespread.use of IDCOR results by persons involved in the regulatory process. Since this result would be counter to the intent of the Program, it is obviously not in the interest of our sponsors to allow concerns regarding use of this material to continue. The Atomic Industrial Forum, Inc. hereby grants the U.S. Nuclear v.k Regulatory Commission (NRC) authority to duplicate copyrighted IDCOR materials as necessary for use by NRC and NRC contractor personnel in carrying o,ut their regulatory mission. This grant of authority, however, does not apply to the Modular Accident Analysis Program (MAAP) or any of its associated documentation. Please contact Roger Huston, of our staff, if you have any additional questions regarding this issue. Sincerely, sf 7 JRS:hlw cc: Cordell Reed Anthony Buhl __. __}}