AP1000 COL Standard Technical Report Submittal of APP-GW ...Westinghouse Westinghouse Nuclear Power...

Westinghouse Westinghouse Electric CompanyNuclear Power PlantsP.O. Box 3 5 5Pittsburgh, Pennsylvania 15230-0355USA

U.S. Nuclear Regulatory Commission Direct tel: 412-374-6306ATTENTION: Document Control Desk Direct fax: 412-374-5005

Washington, DC 20555 e-mail: [email protected]

Your ref: Project Number 740Our ref: DCP/NRC1930

June 11, 2007

Subject: AP 1000 COL Standard Technical Report Submittal of APP-GW-GLR-069, (TR 68)

In support of Combined License application pre-application activities, Westinghouse is submittingRevision 0 of AP 1000 Standard Combined License Technical Report Number 68. This report partiallycompletes and documents, on a generic basis, activities required for COL Information Item 19.59.10-5 inthe AP1000 Design Control Document. Changes to the Design Control Document identified in TechnicalReport Number 68 have been included in Revision 16 of the AP 1000 Design Control Document. Thisreport is submitted as part of the NuStart Bellefonte COL Project (NRC Project Number 740). Theinformation included in this report is generic and is expected to apply to all COL applications referencingthe AP1000 Design Certification.

The purpose for submittal of this report was explained in a March 8, 2006 letter from NuStart to theU.S. Nuclear Regulatory Commission.

Pursuant to 10 CFR 50.30(b), APP-GW-GLR-069, Revision 0, "Equipment Survivability Assessment,"Technical Report Number 68, is submitted as Enclosure 1 under the attached Oath of Affirmation.

Technical Report Number 68 provides an assessment that shows that equipment required to mitigatesevere accidents can perform its severe accident functions during environmental conditions resulting fromhydrogen burns associated with severe accidents. It is expected that when the NRC review of TechnicalReport Number 68 is complete, the assessment and conclusions in report number 68 will be consideredvalid for COL applicants referencing the AP1000 Design Certification.

Questions or requests for additional information related to the content and preparation of this reportshould be directed to Westinghouse. Please send copies of such questions or requests to the prospectiveapplicants for combined licenses referencing the AP1000 Design Certification. A representative for eachapplicant is included on the cc: list of this letter.

Westinghouse requests the NRC to provide a schedule for review of this Technical Report within twoweeks of its submittal.

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/L1t<( :

DCP/NRC 1930June 11, 2007

of 2

Very truly yours,

A. Sterdis, ManagerLicensing and Customer InterfaceRegulatory Affairs and Standardization

/Attachment

1. "Oath of Affirmation," dated June 11, 2007

/Enclosure

1. APP-GW-GLR-069, Revision 0, "Equipment Survivability Assessment," Technical ReportNumber 68, dated May 2007.

cc: D. JaffeE. MckennaG. CurtisP. GrendysP. HastingsC. IonescuD. LindgrenA. MonroeM. MoranC. PierceE. SchmiechG. ZinkeM. Ahmed

- U.S. NRC- U.S. NRC-TVA- Westinghouse- Duke Power- Progress Energy- Westinghouse- SCANA- Florida Power & Light- Southern Company- Westinghouse- NuStart/Entergy- Westinghouse

1E1E1E1EIE1E1E1EIE1E1E1E1E

IAIAIAIAIAIAIAIAIAIAIAIAIA

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ATTACHMENT 1

"Oath of Affirmation"

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ATTACHMENT I

UNITED STATES OF AMERICA

NUCLEAR REGULATORY COMMISSION

In the Matter of: )

NuStart Bellefonte COL Project )

NRC Project Number 740 )

APPLICATION FOR REVIEW OF"AP 1000 GENERAL COMBINED LICENSE INFORMATION"

FOR COL APPLICATION PRE-APPLICATION REVIEW

B. W. Bevilacqua, being duly sworn, states that he is Vice President, New Plants Engineering, forWestinghouse Electric Company; that he is authorized on the part of said company to sign and file withthe Nuclear Regulatory Commission this document; that all statements made and matters set forth thereinare true and correct to the best of his knowledge, information and belief.

B. W. BevilacquaVice PresidentNew Plants Engineering

Subscribed and sworn tobefore me this //.A dayof June 2007.

COMMONWEALTH OF PENNSYLVANIANotarial Seal

Debra McCarthy, Notary PublicMonroeville Boro, Allegheny County

My Commission Expires Aug. 31, 2009Member, Pennsyivania Association of Notaries

Notary Public

00173psa.doc


ENCLOSURE 1

APP-GW-GLR-069, Revision 0

"Equipment Survivability Assessment

Technical Report Number 68

This document includes APP-GW- VP-025 and APP-GW- VPC-020 as attachments.

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AP1 000 DOCUMENT COVER SHEET

TDC: Permanent File: APY:

RFS#: RFS ITEM #:

AP1000 DOCUMENT NO. REVISION NO. SSIGNED TOAPP-GW-GLR-069 Page 1 of 194 W-Sterdis

ALTERNATE DOCUMENT NUMBER: TR68 WORK BREAKDOWN #:

ORIGINATING ORGANIZATION: Westinghouse Electric Company

TITLE: Equipment Survivability Assessment

ATTACHMENTS: DCP #/REV. INCORPORATED IN THIS

A: API 000 Equipment Survivability Assessment, APP-GW-VP-025, Rev. 0 DOCUMENT REVISION:

B: AP1 000 DCD Chapter 19 Appendix D APP-GW-VPC-020, Rev. 0

CALCULATION/ANALYSIS REFERENCE:

ELECTRONIC FILENAME ELECTRONIC FILE FORMAT ELECTRONIC FILE DESCRIPTION

APP-GW-GLR-069 MS Word Text

Rev O.doc

(C) WESTINGHOUSE ELECTRIC..COMPANY LLC - 2007

Z WESTINGHOUSE CLASS 3 (NON PROPRIETARY)Class 3 Documents being transmitted to the NRC require the following two review signatyres in lieuyof a Form 36.

LEGAL REVIEW- SIGNATUWE/DA'Tc'•'

PATENT REVIEW SIGNATURE/,ATEMike Corletti " fJ-/,t7

LI WESTINGHOUSE PROPRIETARY CLASS 2This document is the property of and contains Proprietary Information owned by Westinghouse Electric Company LLC and/or itssubcontractors and suppliers. It is transmitted to you in confidence and trust, and you agree to treat this document in strictaccordance with the terms and conditions of the agreement under which it was provided to you.

ORIGINATORSINTEDAEMostafa Ahmed St/A7 .ORIGINATOR.Robert Lutz "

ORIGINATOR . " ."q",Dali Li... 5 22107REVIEWERS SI URE/DATE,Joan Drexler

VERIFIER: - VERIFICATION METHODMelissa Lucci "-41, o

VERIFIER VERIFICATION METHOD C n"Joan Drexler '' 7 I44 ~~~if$Al$~~ .AP1000 RESPONSIBLE MANAGER S RAPPROVAL DATEDan Fredrick z

Approval of the responsible. manager signifies: thatdocument is complete, all required reviews are complete, electronic Ole is attachedand document is released for use.

APP-GW-GLR-069Revision 0

WESTINGHOUSE NON-PROPRIETARY CLASS 3 May 2007

AP1000 Standard Combined License Technical Report

Equipment Survivability Assessment

Technical Report 68Revision 0

Westinghouse Electric Company LLCNuclear Power PlantsPost Office Box 355

Pittsburgh, PA 15230-0355

@2007 Westinghouse Electric Company LLCAll Rights Reserved

AP1000 StandardAPP-GW-GLR-069 R. 0 COLA Technical Report

1. INTRODUCTION

The purpose of this report is to provide closure of Combined Operating License (COL)

information item 19.59.10-5 by completing the equipment survivability assessment (included

in Attachment A) and transmitting the DCD Chapter 19 Appendix D markup (included in

Attachment B).

1.1 COL Item 19.59.10-5

The completion of the equipment survivability assessment addresses the as-designed

portion of COL Information Item 19.59.10-5.

COL information item 19.59.10-5 reads:

The Combined License applicant referencing the AP1000 certified design will

perform a thermal lag assessment of the as-built equipment required to mitigate

severe accidents (hydrogen igniters and containment penetrations) to provide

additional assurance that this equipment can perform its severe accident functions

during environmental conditions resulting from hydrogen burns associated with

severe accidents. This assessment is required only for equipment used for severe

accident mitigation that has not been tested at severe accident conditions. The

Combined License applicant will assess the ability of the as-built equipment to

perform during severe accident hydrogen burns using the Environment Enveloping

method or the Test Based Thermal Analysis method discussed in EPRI NP-4354

(Reference 19.59-2).

The source references for the equipment survivability assessment document are the

AP1000 Probabilistic Risk Assessment, Appendix D Equipment Survivability Assessment

(Reference 1), the Final Safety Evaluation Report Related to Certification of the AP1000

Standard Design, Chapter 19 Severe Accidents (Reference 2). The AP1000 DCD

Chapter 19 Appendix D markup (Reference 3), which is described in Section 1.2 of this

technical report, was also a reference source for the equipment survivability assessment.

The environmental parameters to which the equipment will be exposed are documented in

AP1000 - Equipment Qualification (EQ) and Severe Accident Radiation Dose (Reference 4)

Page 3 of 194


and Thermal Hydraulic Environments for AP1 000 Equipment Survivability Analyses

(Reference 5).

The approach to perform a systematic evaluation of equipment and instrumentation to

address its survivability for intervening in a severe accident is by identification of

equipment type, equipment location, survival time required, and the use of design basis

event qualification requirements and severe environment experimental data. The

methodology used to demonstrate equipment survivability is as follows:

a. Identify the high level actions used to achieve a controlled, stable state

b. Define the accident time frames for each high level action

c. Determine the equipment and instrumentation used to diagnose, perform and

verify high level actions in each time frame

d. Determine the bounding environment within each time frame

e. Demonstrate reasonable assurance that the equipment will survive to perform its

intended function within the severe environment.

For the equipment used for severe accident mitigation that has not been tested at severe

accident conditions, a thermal lag assessment of the as-built equipment (hydrogen

igniters and containment penetrations) will be performed to provide additional assurance

that this equipment can perform its severe accident functions during environmental

conditions resulting from hydrogen burns associated with severe accidents. This

assessment is performed prior to fuel load and is required only for equipment used for

severe accident mitigation that has not been tested at severe accident conditions. The

Environment Enveloping method or the Test Based Thermal Analysis method discussed

in Large-Scale Hydrogen Burn Equipment Experiments, EPRI NP-4354 (Reference 6)

will be used to assess the ability of the as-built equipment to perform during severe

accident hydrogen burns. Any as-built part of the COL information item 19.59.10-5 will

be provided prior to fuel load as stated in AP1000 as-built COL information item APP-

GW-GLR-021 (Reference 7).

Page 4 of 194


The equipment survivability assessment evaluates the availability of equipment and

instrumentation used during a severe accident to achieve a controlled, stable state after

core damage under the unique containment environments. Severe accident phenomena

may create a harsh, high temperature and pressure containment environment with a

significant concentration of combustible gases. Local or global burning of the gases

may occur, presenting additional challenges to the equipment. The equipment

assessment is provided in APP-GW-VP-025, Attachment A to this report (Reference 8).

Open Items:

There are four open items associated with the AP1000 Equipment Survivability

Assessment report in Attachment A. They are listed below:

1. Two of the documents referenced in the AP1000 Equipment Survivability

Assessment are not final and are not of numerical revisions. Final

assessment report will only refer to references with numeric revisions and

applicable at the time of issuing the final assessment report. This open item

will be removed upon completion of the equipment survivability assessment in

a new revision of this report.

2. Tables 6a, 6b and 6c in the AP1000 Equipment Survivability Assessment

report are compiled based on the current AP1 000 plant design. The

equipment listed in these tables will be reviewed and revised to reflect the

final AP1 000 plant design prior to plant's installation. This open item will be

removed upon completion of the equipment survivability assessment in a new

revision of this report.

3. The thermal lag assessment of the as-built equipment required to mitigate

severe accident (hydrogen igniters and containment penetrations) that has

not been tested to severe accident conditions will be performed prior to fuel

load.

4. Thermal hydraulic environments included in AP1000 Equipment Survivability

Page 5 of 194


Assessment will be compared, with environments included in PRA report to

confirm that existing assessment in the PRA report continued to be valid.

1.2 DCD Chapter 19 Appendix D Markup

This report also provides a markup of the Design Control Document (DCD) for AP1 000

Chapter 19 Appendix D Markup (Reference 3). The changes were made because of two

reasons:

a. the Severe Accident Management Guidelines (SAMG) for AP1000 (Reference 9)

were developed to provide more detailed information on severe accident mitigation

actions, and

b. the actual design of certain systems is better identified compared with the systems

which were identified when the PRA was completed.

During the development of the SAMG for AP1000, requirements were defined for

accident management after the onset of core damage (i.e. Time Frames 2 and 3). For

example, previously unidentified methods of injecting water into containment were added

(e.g., providing makeup to overflow the In-Containment Refueling Water Storage Tank

(IRWST) by the Normal Residual Heat Removal System (RNS)). Also, the use of

containment spray was identified as a several severe accident strategy (e.g., injecting

water into containment and containment heat removal). Also, another method of

depressurizing the RCS was identified (e.g., reactor vessel head vent).

Following the finalization of certain systems for AP1000, the equipment and

instrumentation associated with those systems was updated. For example, the

finalization of the alternate steam generator feedwater systems resulted in the

elimination of low pressure steam generator feed systems (i.e., service water,

condensate water).

Finally, changes in the identification of the equipment and instrumentation were made to

update the naming convention for AP1000. Changes were also made to update the list

of references to the latest document available. The DCD Chapter 19 Appendix D

Page 6 of 194


Markup is included in APP-GW-VPC-020, Attachment B of this report (Reference 3).

The new list of equipment and instrumentation reflects the AP1 000 design as of the date

this document.

Open Items:

There are two open items related to DCD Chapter 19 Appendix D Markup in

Attachment B. They are listed below:

1. Identification of equipment and instrumentation for prevention of core damage

(e.g., Time Frame 0 and Time Frame 1) was not completed because the Emergency

Operating Procedures (EOPs) are still in development. Upon finalization of the

EOPs, the equipment and instrumentation used in those procedures can be

identified and considered for equipment survivability assessments. This open item

will be removed upon completion of a review of the equipment and instrumentation

following completion of the EOP development.

2. The Structure, System and Components (SSCs) required for containment isolation

are not completely identified. It has been determined that a survivability assessment

is required for environment electrical penetrations, as identified in the DCD mark-up.

However, it has not been determined whether mechanical penetrations and hatches

(e.g., gasket materials) also need to be included in the environmental assessment to

ensure containment integrity.

2. TECHNICAL BACKGROUND

2.1 Severe Accident Management Goals

The goal of severe accident management is to achieve a controlled, stable state

following a beyond design basis accident. Establishment of a controlled, stable state

protects the integrity of the containment pressure boundary. The conditions for a

controlled, stable state are defined by APP-GW-GL-027, Framework for AP1 000 Severe

Accident Management Guidance (SAMG) (Reference 10). The three goals are:

(1) to return the core to a controlled, stable state, (2) to maintain or return the

Page 7 of 194


containment to a controlled, stable state, and (3) to terminate fission product releases

from the plant. These three goals are discussed in detail in the attached report

(Reference 8).

2.2 Equipment Survivability Time Frames

The purpose of the equipment survivability time frames is to identify the time span in the

severe accident in which specific equipment is required to perform its function. The

phenomena and environment associated with that phase of the accident defines the

environment which challenges the equipment survivability. The equipment survivability

Time Frame definitions are summarized in Table 1 of the attached report (Reference 8).

There are four time frames considered as listed below.

2.2.1 Time Frame 0 - Pre-Core Uncovery

Time Frame 0 is defined as the period of time in the accident sequence after the

accident initiation and prior to core uncovery. Equipment survivability in Time

Frame 0 is covered under the design basis equipment qualification program for the

primary accident management strategies.

2.2.2 Time Frame I - Core Heatup

Time Frame 1 is defined as the period of time after core uncovery and prior to the

onset of significant core damage as evidenced by the rapid zirconium-water

reactions in the core. This is the transition period from design basis to severe

accident environment. Equipment survivability in Time Frame I is evaluated to

demonstrate it is within the equipment qualification envelope except for

components inside the RCS pressure boundary.

2.2.3 Time Frame 2 - In-Vessel Severe Accident Phase

Time Frame 2 is the period of time in the severe accident after the accident

progresses beyond the onset of rapid zirconium-water reactions and prior to the

establishment of a controlled, stable state (end of in-vessel core relocation), or prior

to reactor vessel failure. The onset of rapid zirconium-water reaction of the fuel rod

Page 8 of 194


cladding and hydrogen generation defines the beginning of Time Frame 2. Over the

period of Time Frame 2, the initial, intact geometry of the core is lost as it melts and

relocates downward. The in-vessel hydrogen generation and fission product releases

from the fuel matrix occur during this time frame.

2.2.4 Time Frame 3 - Ex-Vessel Severe Accident Phase

Time Frame 3 is defined as the period of time after the reactor vessel fails until the

establishment of a controlled, stable state. The AP1000 reactor design and the

AP1 000 EOPs provide the capability to flood the reactor vessel and depressurize

the RCS to prevent reactor vessel failure in a severe accident. This severe

accident Time Frame 3 is predicted to be a very low probability event. Molten core

debris is relocated from the reactor vessel onto the containment cavity floor which

creates the potential for rapid steam generation, core-concrete interaction and non-

condensable gas generation. Severe accident management strategies

implemented in Time Frame 3 are designed to monitor the accident progression,

attempt to re-establish a coolable core configuration on the containment floor,

maintain containment integrity and mitigate fission product releases to the

environment.

During Time Frames 1, 2 and 3, the equipment in direct contact with the core and the

RCS could experience environmental parameters that exceed the parameters

associated with the plant's design basis. Also, during Time Frames 2 and 3, the

containment environment is expected to be more severe than the design basis pressure

and temperature conditions and may include additional hydrogen burning. The severe

accident environmental parameters and equipment survivability assessment is

addressed in the attached report (Reference 8).

2.3 Definition of Active Time Frame

Equipment only needs to survive long enough to perform its function to protect the

containment fission product boundary. The time of active operation is the time during

which the equipment must perform its function. In cases of some items, such as valves

or motor-operators, the equipment function is completed when it changes state (e.g.,

Page 9 of 194


closes). For other items, such as pumps, the equipment must operate continuously to

perform its function.

2.4 High Level Action to Achieve a Controlled, Stable State

Framework for AP1 000 Severe Accident Management Guidance (Reference 10) defines

the high level actions required to mitigate the severe accident, achieve a controlled,

stable state and terminate fission product releases. The high level actions relative to

severe accident management goals are summarized in Table 2 of the attached report

(Reference 8) and serve as the basis for identification of the equipment required to

mitigate the accident.

The equipment and instrumentation required to be available in each time frame for the

high level actions are summarized in Table 3 of the attached report (Reference 8). The

subsections which follow recap the high level actions and the equipment,

instrumentation and associated active operation times needed to provide reasonable

assurance of achieving a controlled, stable state.

2.4.1 Injection into the Reactor Coolant System (RCS)

The injection into the RCS will be achieved in three stages:

a. RCS at operating pressure

b. RCS at reduced pressure

c. RCS at containment pressure

2.4.2 Injection into Containment

The injection into containment will be achieved in three ways:

a. Injection into containment from IRWST

b. Injection into containment from containment spray

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AP1 000 StandardAPP-GW-GLR-069 R. 0 COLA Technical Report

c. Injection into containment via overflow IRWST

2.4.3 Decay Heat Removal

The decay heat removal can be achieved via two ways:

a. Passive Residual Heat Removal (PRHR) Heat Exchanger (HX)

b. High pressure injection into steam generator

2.4.4 Depressurize Reactor Coolant System

The depressurization can be achieved via three ways:

a. Depressurize via Automatic Depressurization System (ADS)

stage 1, 2, and 3

b. The Reactor Vessel Head Vent

c. Depressurize via ADS stage 4

2.4.5 Depressurize Steam Generators

The steam generator Power Operated Relief Valve (PORV) and main steam

bypass valves are used for depressurizing the steam generators.

2.4.6 Containment Heat Removal

Containment heat removal is provided by the Passive Containment Cooling

System (PCS). PCS water is supplied to the external surface of the containment

shell from the PCS water storage tanks. The fire protection system also provides a

containment spray function used for severe accident management.

Page 11 of 194


2.4.7 Containment Isolation and Venting

Containment isolation is provided by an intact containment shell and the

containment isolation system which closes the isolation valve in lines penetrating

the containment shell. Containment venting to the spent fuel pool is available

through Normal Residual Heat Removal System (RNS) hot leg suction line Motor

Operated Valves (MOVs).

2.4.8 Hydrogen Control

Hydrogen control in AP1000 is provided by hydrogen igniters.

2.4.9 Control Fission Product Releases

A non safety-related containment spray system is provided in AP1000 to scrub

aerosol fission products from the containment atmosphere.

2.4.10Accident Monitoring

Sufficient instrumentation should exist to inform operators of the status of the

reactor and containment at all times.

2.5 Equipment and Instrumentation

The equipment and instrumentation, used to diagnose, perform, and verify high level

actions in each time frame, are selected based on Table 3 of the attached report

(Reference 8). The instrumentation chosen allows the operator to confirm and trend the

results of actions taken and provides adequate information for those responsible for

making accident management decisions (Reference 2, 19.2.3.3.7.1).

The equipment and instrumentation used in achieving a controlled, stable state following

a severe accident, the action required to operate in each Time Frame, and equipment

location are summarized in Tables 5 and 6 of the attached report (Reference 8).

Page 12 of 194


The detailed description of equipment and instrumentation are summarized as follows:

2.5.1 Equipment Located inside Containment

2.5.1.1 Differential Pressure and Pressure Transmitters

2.5.1.1.1 Passive Core Cooling System (PXS) IWRST Water Level

2.5.1.1.2 Reactor Coolant System Pressure

2.5.1.1.3 Steam Generator Wide Range Water Level

2.5.1.1.4 Containment Pressure

2.5.1.2 Core-Exit Thermocouples

2.5.1.3 Resistance Temperature Detectors (RTDs)

2.5.1.3.1 Hot Leg RTDs

2.5.1.3.2 Cold Leg RTDs

2.5.1.3.3 Containment Temperature

2.5.1.3.4 IRWST Water Temperature

2.5.1.4 Hydrogen Monitors

2.5.1.5 PXS Radiation Monitors

2.5.1.6 Solenoid Valves - Vent Air-Operated Valves (AOVs)

2.5.1.6.1 PXS Core Makeup Tank AOVs

2.5.1.6.2 PXS PRHR AOVs

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2.5.1.6.3 Containment Isolation AOVs

2.5.1.6.4 Chemical and Volume Control System (CVS) RCS Boundary

AOVs

2.5.1.6.5 Containment Spray AOVs

2.5.1.6.6 Containment Atmosphere Sampling Function

2.5.1.6.7 Reactor Vessel Head Vent AOVs

2.5.1.7 Motor-Operated Valves (MOVs)

2.5.1.7.1 PXS Accumulator MOVs

2.5.1.7.2 PXS Core Makeup Tank MOVs

2.5.1.7.3 PXS Recirculation MOVs

2.5.1.7.4 ADS Stages 1, 2, 3, and 4 MOVs

2.5.1.7.5 Containment Isolation MOVs

2.5.1.7.6 CVS Charging and Injection MOVs

2.5.1.7.7 Normal Residual Heat Removal System (RNS) IRWST MOVs

2.5.1.7.8 RNS MOV for Injection from Cask Loading Pit to RCS / PXS

PRHR MOV

2.5.1.7.9 RNS Hot Leg Suction to Spent Fuel Pool

2.5.1.8 Squib Valves

2.5.1.8.1 IRWST Injection

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2.5.1.8.2 PXS Containment Recirculation

2.5.1.8.3 Fourth Stage ADS

2.5.1.9 Valve Position Sensors

2.5.1.10 Hydrogen Igniters

2.5.1.11 Electrical Containment Penetration Assemblies

2.5.1.12 Cables

2.5.1.13 PXS Containment Water Level

2.5.2 Equipment Located Outside Containment

2.5.2.1 Steamline Radiation Monitor (SG Radiation)

2.5.2.2 Steamline Pressure Transmitters

2.5.2.3 Passive Containment Cooling System Flow and Tank Level (PCS)

2.5.2.4 Containment Atmosphere Sampling Function

2.5.2.5 Makeup Pumps and Flow Measurement

2.5.2.6 RNS Pumps and Flow Measurement

2.5.2.7 MOV and Manual Valves from RNS Hot Leg Suction Lines to the Spent

Fuel Pool

2.5.2.8 RNS MOV for Injection from Cask Loading Pit to RCS

2.5.2.9 Main Feedwater Pumps and Valves

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APP-GW-GLR-069 R. 0AP1000 Standard

COLA Technical Report

2.5.2.10 Startup Feedwater Pumps and Valves

2.5.2.11 Fire Water, Fire Pumps, Valves and Flow Measurement used to provide

Containment Spray and Backup Containment Cooling

2.5.2.12 Steam Generator PORVs and Main Steam Bypass Valves for

Depressurization

2.5.2.13 PCS Recirculation Pumps and Valves and Fire Water Pumps and Valves

for Containment Heat Removal

2.5.2.14 Containment Isolation Valves (Outside Containment)

2.5.2.15 Auxiliary Building Radiation Monitor

2.6 Bounding Containment Environment

The bounding containment environments during severe accident have been determined

in References 4 and 5.

2.6.1 Radiation Accident - Severe Accident

Section 9.1 of the attached report (Reference 8) is an extraction from

APP-SSAR-GSC-507 (Reference 4). The fraction of the core inventory released

to the containment atmosphere has been revised from the original PRA Appendix

D (Reference 1).

Page 16 of 194


2.6.2 Thermal-Hydraulic Environments

The bounding severe accident environmental envelopes for equipment locations

inside containment are provided by Thermal Hydraulic Environments for API000

Equipment Survivability Analyses (Reference 5). The thermal hydraulic

conditions facing the equipment to be evaluated for equipment survivability was

developed using the MAAP4.0.4 code. Bounding conditions are provided for the

separate containment regions for each of the equipment survivability Time

Frames established for the analysis.

2.7 Assessment of Equipment Survivability

2.7.1 Approach to Equipment Survivability

Section D.8.1 of Reference 1 states that the approach to a systematic evaluation of

equipment and instrumentation to address its survivability for intervening in a

severe accident is by identification of the equipment type, equipment location,

survival time required, and the use of design basis event qualification requirements

and severe environment experimental data.

2.7.2 As-Designed Assessment

The as-designed assessment of equipment survivability is contained in Section D.8

of Reference 1. This approach was reviewed and accepted by the NRC (Reference

2, Section 19.2.3.3.7.3, Basis for Acceptability) as stated below.

"The staff performed this evaluation and concludes that the equipment and

instrumentation identified by the applicant in DCD Tier 2, Tables 19D-3

through19D-5, and the applicable environments described in Appendix D to the

AP1000 PRA supporting document, meet the above guidance of SECY-93-087 and

10 CFR 50.34(f), as delineated in Section 19.2.3.3.7 of this report. The

environmental qualification ITAAC and completion of a COL action item provide

reasonable assurance that the equipment and instrumentation identified in this

section will operate in the severe accident environment for which they are

intended, and over the time span for which they are needed. Specifically, the COL

Page 17 of 194


applicant referencing the AP1000 certified design will perform a thermal response

assessment of the as-built equipment used to mitigate severe accidents to provide

additional assurance that this equipment can perform its severe accident functions

during environmental conditions resulting from hydrogen burns. This assessment

is COL Action Item 19.2.3.3.7.3-1."

2.7.3 As-Built Assessment

Thermal lag assessment of the as-built equipment used to mitigate severe

accidents (hydrogen igniters and containment penetrations) will be performed prior

to fuel load. The purpose of the assessment is to provide additional assurance

that this equipment can perform its severe accident functions during environmental

conditions resulting from hydrogen burns.

2.8 Conclusion

This report examined the AP1000 severe accident design features and the systems and

equipment required to mitigate the accident parameters. Based on the examination, lists

of systems and equipment inside and outside containment have been generated.

Accident progression was also evaluated and identified to progress in four Time Frames.

Actions required to mitigate the consequences of severe accidents were identified for

each Time Frame and lists of equipment required to successfully complete the required

actions were also identified. The equipment locations, floors, rooms and buildings were

also identified to aid in performing the equipment assessment. In parallel with this

evaluation, an analysis of the severe accident scenarios and resultant severe accident

environmental parameters was conducted using MAAP4, Reference 5. In addition, the

radiation doses associated with the severe accident were also computed for inside and

outside containment. The results of the analyses are documented in References 5 and

4, respectively.

Assessment of equipment in severe accident environment was performed for the

equipment in Reference 1 and accepted by NRC in Reference 2.

The only remaining portion of this study is to perform the assessment. The assessment

will be conducted as follows:

Page 18 of 194


1. Completion and documentation of the environmental qualification ITAAC

2. The thermal lag assessment of the as-built equipment required to mitigate severe

accident (hydrogen igniters and containment penetrations) that has not been tested

to severe accident conditions will be performed prior to fuel load in accordance with

Reference 7.

3. REGULATORY IMPACT

The FSER in Subsection 19.2.3.3.7 (Reference 2) discusses equipment survivability of

equipment used to mitigate severe accidents. Accident scenarios and the equipment used to

mitigate the accidents are identified. The FSER in Subsection 19.2.3.3.7.3 provides

conclusions about equipment survivability that are based in part on an as-built thermal

response assessment of equipment used to mitigate severe accidents. The thermal

response assessment includes the effects of a hydrogen burn.

The applicable regulations and criteria are described in Section 2 of the attached report,

APP-GW-VP-025, Rev. 0 (Reference 8). The requirements for equipment survivability differ

from those for equipment qualification. Equipment qualification requires that safety-related

equipment, both electrical and mechanical, must perform its safety function during design-

basis events. The level of assurance provided for the equipment operability during design-

basis events is called environmental qualification or equipment qualification.

The environmental conditions resulting from beyond design basis events may be more

limiting than conditions from design basis events. The NRC has established criteria to

provide a reasonable level of assurance that necessary equipment will function in the severe

accident environment within the time span it is required. This criterion is referred to as"equipment survivability."

Beyond design basis events can be divided into two classes, in-vessel and ex-vessel severe

accidents. The applicable criteria for equipment, both mechanical and electrical, required

for recovery from in-vessel severe accidents are provided in 10 CFR 50.34(f) and

10 CFR 50.44(c). The applicable criteria for equipment, both electrical and mechanical,

required for mitigating the consequences of ex-vessel severe accidents is discussed in

Section Ill. F, "Equipment Survivability" of SECY-90-016 (Reference 11).

Page 19 of 194


The NRC recommends in SECY-93-087 (Reference 12) that equipment provided only for

severe accident protection need not be subject to 10 CFR 50.49 equipment qualification

requirements, the 10 CFR 50 Appendix B quality assurance requirements, or 10 CFR 50

Appendix A redundancy/diversity requirements. However, mitigation features must be

designed to provide reasonable assurance they will operate in the severe accident

environment for which they are intended and over the time span for which they are needed.

Section 19.2.3.3.7 of Reference 2 (Equipment Survivability) identifies that these regulations

collectively indicate the need to perform a systematic evaluation of all equipment, both

electrical and mechanical, and instrumentation to ensure its survivability for intervening in an

in-vessel severe accident. The sections of SECY-90-016 and SECY-93-087 on equipment

survivability discuss the applicable guidance for mitigating the consequences of ex-vessel

severe accidents.

Completing the equipment survivability assessment does not alter the design of the

components and systems used to mitigate severe accidents and is considered in the

thermal lag assessment. There is no change to the design function of components or

systems. Completing the equipment survivability assessment does not involve a change to

a procedure that adversely affects how the design functions of the components and systems

are performed or controlled. The methodologies associated with evaluation of equipment

survivability and the thermal lag assessment of these components and systems are not

altered. Completing the equipment survivability assessment does not involve a test or

experiment. The DCD change does not require a license amendment per the criteria of VIII.

B. 5. b. of Appendix D to 10 CFR Part 52.

Completing the equipment survivability assessment change does not impact the design of

features associated with mitigation of severe accidents. The methodology and requirements

for the thermal lag assessment are not altered. The subject change does not require a

license amendment based on the criteria of VIII. B. 5. c of Appendix D to 10 CFR Part 52.

Completing the equipment survivability assessment does not alter barriers or alarms that

control access to protected areas of the plant. Completing the equipment survivability

Page 20 of 194


assessment does not alter requirements for security personnel. Therefore, the completing

the equipment survivability assessment does not have an adverse impact on the security

assessment of the AP1000.

4. DCD MARK-UP

A separate mark up of DCD paragraph 19.59.10.5 is provided in APP-GW-GLR-021

(Reference 7) and defers the performance of thermal lag assessment of the as-built

equipment to prior to fuel load by the license holder.

Markup of DCD Chapter 19 Appendix D is included in Attachment B of this report

(Reference 3).

Page 21 of 194


5. REFERENCES

1. AP1000 Probabilistic Risk Assessment, Appendix D Equipment Survivability

Assessment, APP-GW-GL-022, Rev. 1

2. Final Safety Evaluation Report Related to Certification of the AP1000 Standard Design,

Chapter 19 Severe Accidents, NUREG-1 793, September 2004

3. AP1000 DCD Chapter 19 Appendix D Markup, APP-GW-VPC-020, Rev. 0

4. AP1000 - Equipment Qualification (EQ) and Severe Accident Radiation Dose,

APP-SSAR-GSC-507, Rev. 3, CN-REA-02-16, Rev. 3 (Proprietary)

5. Thermal Hydraulic Environments for AP1000 Equipment Survivability Analyses,

APP-GW-GER-010, Rev. 0, CN-CRA-02-47, Rev. 0 (Proprietary)

6. Large-Scale Hydrogen Burn Equipment Experiments,

EPRI NP-4354, Final Report, 1985

7. AP1000 As-Built COL Information Items, APP-GW-GLR-021, Rev. 0

8. AP1000 Equipment Survivability Assessment, APP-GW-VP-025, Rev. 0

9. AP1000 Severe Accident Management Guidelines, APP-GW-GJR-400, Rev. A

(Proprietary)

10. Framework for AP1 000 Severe Accident Management Guidance,

APP-GW-GL-027, Rev. 0, WCAP-16335, Rev. 0

11. Evolutionary Light Water Reactor (LWR) Certification Issues and Their Relationship to

Current Regulatory Requirements, SECY-90-016, January 12, 1990

12. Policy, Technical, and Licensing Issues Pertaining to Evolutionary and Advanced Light

Water Reactor (ALWR) Designs, SECY-93-087, April 2,1993

Page 22 of 194

AP1000 StandardCOLA Technical ReportAPP-GW-GLR-069 R. 0

ATTACHMENT A

AP1000 EQUIPMENT SURVIVABILITY ASSESSMENT

(APP-GW-VP-025, Rev. 0, Reference 8)

Page 23 of 194


This Page Is Intentionally Left Blank

Page 148 of 194


ATTACHMENT B

AP1000 DCD CHAPTER 19 APPENDIX D MARKUP

(APP-GW-VPC-020, Rev. 0, Reference 3)

Page 148 of 194

AP1000 DOCUMENT COVER SHEETTDC:

RFS#:Permanent File:

RFS ITEM #:APY:

AP1000 DOCUMENT NO. REVISION NO. ýSSIGNED TO

APP-GW-VP-025 Irev. 0 Page 1 of 125 IVV-Jim Winters

ALTERNATE DOCUMENT NUMBER: WORK BREAKDOWN #:

ORIGINATING ORGANIZATION:

TITLE: AP1O00 Equipment Survivability Assessment

ATTACHMENTS: OCP #/REV. INCORPORATED IN THISN/A DOCUMENT REVISION:

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CALCULATION/ANALYSIS REFERENCE:N/A

ELECTRONIC FILENAME ELECTRONIC FILE FORMAT LECTRONIC FILE DESCRIPTIONAPP-GW-VP-025 RevO.doc Word 2002 N/A

(C) WESTINGHOUSE ELECTRIC COMPANY LLC - 2007[ WESTINGHOUSE CLASS 3 (NON PROPRIETARY)

Class 3 Documents being transmitted to the NRC require the following two review signatJwes in lieu,,o Form.36!LEGAL REVIEW _"+. C. .Spwae e"47 CPATENT REVIEW SIGNATURE/DM. M: Corletti

L- WESTINGHOUSE PROPRIETARY CLASS 2This document is the property of and contains Proprietary Information owned by Westinghouse Electric Company LLC and/or itssubcontractors and suppliers. It is transmitted to you in confidence and trust, and you agree to treat this document in strict accordancewith the terms and conditions of the agreement under which it was provided to you.

ORIGINATOR SIGNATURE/DATEMostafa Ahmed lL ./.:9"7

ORIGINATOR SIGNATRE/D TE _//pDali Li/

7

REVIEWER I "RE/DATE

Joan.Drexler. :: .

VERlF-IERMelissa Lucci S3~ G/&ID

*4 ~ --

R.1ý,l(% CJTI)NMTQu* Ooqgf

Vt•rIIR .Joan Drexler C -6 0- 7

L

APIOQO0 RESPONSIBLE.MANAGER PlG NATURE- PPROVAL DATEDan Frederick ~~i~-.________________

* prvloftersosil aae -giistatdcmn sIopee llrqie evesaecmpee lcroi iei atce7n* Approva of the responsible manager signifies that document is complete, all required reviews are complete, electronic file.is attached anddocument is released for use.

AP1000 Equipment Survivability Assessment APP-GW-VP-025 Rev. 0

Westinghouse Electric Company Page 2 of 125

[This page intentionally left blank]

AP1 000 Equipment Survivability Assessment

Westinghouse Electric Company

APP-GW-VP-025 Rev. 0

Page 3 of 125

API 000 Equipment Survivability Assessment

No.: APP-GW-VP-025

Rev. 0

Westinghouse Non-Proprietary Class 3

Copyright 2007

Westinghouse Electric Company LLC

All Rights Reserved

AP1000 Equipment Survivability Assessment

Westinahouse Electric ComDany


Paae 4 of 125

REVISION HISTORY

RECORD OF CHANGES

Revision Revision Made By Description Date

0 Mostafa A. Ahmed Original Issue for May 18, 2007

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I t t

4 4 4



TABLE OF CONTENTS

List of Acronyms and Abbreviations ...................................................................................... 9

List of Open Items .................................................................................................................... 12

1. Introduction ....................................................................................................................... 13

2. Applicable Regulations and Criteria ............................................................................. 15

3. Severe Accident Management Goals ............................................................................ 17

4. Equipment Survivability Time Frames ............................................................................ 19

5. Definition of Active Time Frame .................................................................................... 21

6. Description of Systems Required for Survivability Evaluation ....................................... 22

7. High Level[Action to Achieve a Controlled, Stable State .............................................. 32

8. Equipment and Instrumentation .................................................................................... 44

9. Bounding Containment Environment ............................................................................ 55

10. Assessment of Equipment Survivability ...................................................................... 69

11. Conclusion ..................................................................................................................... 71

12. References .................................................................................................................... 72

Table 1: Definition of Equipment Survivability Time Frames ................................................ 74

Table 2: AP1000 High Level Actions relative to Accident Management Goals ..................... 75

Table 3: Equipment and Instrumentation used for the High Level Actions ........................... 76



Table 4: Equipment Location in Containment ....................................................................... 78

Table 5: Equipment, Action Time Frame, and Equipment Location Summary ..................... 79

Table 6a: List of Equipment Located Outside Containment (TO through T3) ....................... 81

Table 6b: List of Equipment Located Inside Containment (TO and T1) ............................... 86

Table 6c: List of Equipment Located Inside Containment (T2 and T3) ................................. 94

Table 7: Containment Regions with Associated Equipment Locations ................................... 100

Table 8: MAAP4 Event Timing Related to the Equipment Survivability Time Frames ........... 101

Table 9: High Level Action and Associated Equipment Required in Each Time Frame ....... 102

Figure 1: Post-LOCA Gamma Dose and Dose Rate Inside Containment .............................. 103

Figure 2: Post-LOCA Beta Dose and Dose Rate Inside Containment .................................... 104

Figure 3: Containment Gas Pressure - Case IGN ................................................................. 105

Figure 4: Loop Compartments Gas Temperature - Case IGN ............................................... 105

Figure 5: CMT & Upper Compartment Gas Temperature - Case IGN ................................... 106

Figure 6: PXS Compartments Gas Temperature - Case IGN ................................................ 106

Figure 7: Reactor Cavity Gas Temperature - Case IGN ........................................................ 107

Figure 8: Containment Gas Pressure - Case NOIGN ............................................................ 107

Figure 9: Loop Compartments Gas Temperature - Case NOIGN .......................................... 108

Figure 10: CMT & Upper Compartment Gas Temperature - Case NOIGN ............................ 108

Figure 11: PXS Compartments Gas Temperature - Case NOIGN ........................................ 109

Figure 12: Reactor Cavity Gas Temperature - Case NOIGN ................................................. 109



Figure 13: Containment Gas Pressure - Case IVR ................................................................. 110

Figure 14: Loop Compartments Gas Temperature - Case IVR ............................................. 110

Figure 15: CMT & Upper Compartment Gas Temperature - Case IVR ................................. 111

Figure 16: PXS Compartments Gas Temperature - Case IVR .............................................. 111

Figure 17: Reactor Cavity Gas Temperature - Case IVR ...................................................... 112

Figure 18: Containment Gas Pressure - Case GLOB ............................................................ 112

Figure 19: Loop Compartments Gas Temperature - Case GLOB ......................................... 113

Figure 20: CMT & Upper Compartment Gas Temperature - Case GLOB ............................. 113

Figure 21: PXS Compartments Gas Temperature - Case GLOB .......................................... 114

Figure 22: Reactor Cavity Gas Temperature - Case GLOB .................................................. 114

Figure 23: Containment Gas Pressure - Case SL ................................................................. 115

Figure 24:Loop Compartments Gas Temperature - Case SL ................................................ 115

Figure 25: CMT & Upper Compartment Gas Temperature - Case SL ................................... 116

Figure 26: PXS Compartments Gas Temperature - Case SL ................................................ 116

Figure 27: Reactor Cavity Gas Temperature - Case SL ........................................................ 117

Figure 28: Containment Gas Pressure - Case CCI ............................................................... 117

Figure 29: Loop Compartments Gas Temperature - Case CCI ............................................. 118

Figure 30: CMT & Upper Compartment Gas Temperature - Case CCI ................................. 118

Figure 31: PXS Compartments Gas Temperature - Case CCI .............................................. 119

Figure 32: Reactor Cavity Gas Temperature - Case CCI ...................................................... 119

AP1 000 Equipment Survivability Assessment APP-GW-VP-025 Rev. 0


Figure 33: Containment Gas Pressure - Case EVX .............................................................. 120

Figure 34: Loop Compartments Gas Temperature - Case EVX ............................................ 120

Figure 35: CMT & Upper Compartment Gas Temperature - Case EVX ................................ 121

Figure 36: PXS Compartments Gas Temperature - Case EVX ............................................. 121

Figure 37: Reactor Cavity Gas Temperature - Case EVX ..................................................... 122

Figure 38: Containment Pressure Envelope ........................................................................... 122

Figure 39: Loop Compartment Gas Temperature Envelope ................................................... 123

Figure 40: Upper Compartment Gas Temperature Envelope ................................................. 123

Figure 41: Maintenance Floor Gas Temperature Envelope ....................... 124

Figure 42: Intact PXS Compartment Gas Temperature Envelope .......................................... 124

Figure 43: Faulted PXS/CVS Compartment Gas Temperature Envelope .............................. 125

Figure 44: Reactor Cavity Gas Temperature Envelope .......................................................... 125



List of Acronyms and Abbreviations

The following acronyms and abbreviations are defined to allow an understanding of their

use within this document. Abbreviations marked with an (*) are used only in the tables.

ACC Accumulator

ADS Automatic Depressurization System

AOV Air-Operated Valve

ATWS Anticipated Transient Without Scram

Aux* Auxiliary Building

Bldg* Building

CCI Vessel Failure with Long-Term Core Concrete Interaction

CCS Component Cooling System

CDS Condensate System

CIV Containment Isolation Valve

CL Cold Leg

CMT Core Makeup Tank

CNS Containment System

COL Combined Operating License

Cont.* Containment

CV Check Valve

CVS Chemical and Volume Control System

DAS Diverse Actuation System

DBA Design Basis Accident

DC Direct Current

DVI Direct Vessel Injection

EQ Equipment Qualification

EOPs Emergency Operating Procedures

ERG Emergency Response Guideline

ERVC External Reactor Vessel Cooling



EVX Ex-Vessel Fuel Coolant Interaction

FCI Fuel Coolant Interaction

FPS Fire Protection System

FWS Main and Startup Feedwater System

GLOB Large LOCA with Failure of Accumulators and Failure of Hydrogen Igniters

HL Hot Leg

HPSI High Pressure Safety Injection

HX Heat Exchanger

IGN DVI Line Break with Hydrogen Igniters

IRC Inside Reactor Containment

IVR DVI Line Break with Igniters and No Vessel Reflooding

IRWST In-Containment Refueling Water Storage Tank

ITAAC Inspections, Tests, Analysis, and Acceptance Criteria

LOCA Lost of Coolant Accident

LPSI Low Pressure Safety Injection

MCR Main Control Room

MFW Main Feedwater System

MOV Motor-Operated Valve

MSIV Main Steam Isolation Valve

MSS Main Steam System

N/A Not Applicable

NOIGN DVI Line Break with Failure of the Hydrogen Igniters

NRC Nuclear Regulatory Commission

ORC Outside Reactor Containment

P&ID Piping and Instrument Diagram

PARs Auto-Catalytic Hydrogen Recombiners

PCCWST Passive Containment Cooling Water Storage Tank

PCS Passive Containment Cooling System

PMS Protection and Safety Monitoring System

PORV Power-Operated Relief Valve



PRA Probabilistic Risk Assessment

Press.* Pressure

PRHR Passive Residual Heat Removal

PSS Primary Sampling System

PXS Passive Core Cooling System

PWR Pressurized Water Reactor

RCDT Reactor Coolant Drain Tank

RCS Reactor Coolant System

RNS Normal Residual Heat Removal System

RTD Resistance Temperature Detector

SAMG Severe Accident Management Guidelines

SFP Spent Fuel Pool

SFS Spent Fuel Pool Cooling System

SFW Startup Feedwater System

SG Steam Generator

SGS Steam Generator System

SGTR Steam Generator Tube Rupture

SL Small LOCA in the Hot Leg with Full ADS

SWS Service Water System

Trans.* Transducer

VCS Containment Recirculation Cooling System

VLS Containment Hydrogen Control System



List of Open Items

Item Description

Number

1 References 11 and 13 are Rev. A. Final assessment report will only refer toreferences with numeric revisions and applicable at the time of issuing thefinal assessment report. This open item will be removed upon completion ofthe equipment survivability assessment in a new revision of this report.

2 Tables 6a, 6b and 6c are compiled based on the current AP1000 plantdesign. The equipment listed in these tables will be reviewed and revised toreflect the final AP1000 plant design prior to plant's installation. This openitem will be removed upon completion of the equipment survivabilityassessment in a new revision of this report.

3 The thermal lag assessment of the as-built equipment required to mitigatesevere accident (hydrogen igniters and containment penetrations) that hasnot been tested to severe accident conditions will be performed prior to fuelload in accordance with Reference 6.

4 Thermal hydraulic environments in Reference 4 will be compared withenvironments included in PRA report, Reference 1, to confirm that existingassessment in Reference 1 continued to be valid.



1. Introduction

The purpose of the equipment survivability assessment is to evaluate the availability

of the equipment and instrumentation used during a severe accident to achieve a

controlled, stable state after core damage under the unique containment

environments. Severe accident phenomena may create a harsh, high temperature

and pressure containment environment with a significant concentration of

combustible gases. Local or global burning of the gases may occur, presenting

additional challenges to the equipment. This revision of the document only identifies

the equipment and instrumentation for survivability assessment. Future revisions of

this document will be developed to demonstrate, with reasonable assurance, that the

identified equipment and instrumentation used to mitigate and monitor severe

accident progression will be available at the time it is called upon to perform its

intended function. The source references for this document are AP1000

Probabilistic Risk Assessment, Appendix D Equipment Survivability Assessment

(Reference 1) and Final Safety Evaluation Report Related to Certification of the

AP1000 Standard Design, Chapter 19 Severe Accidents (Reference 2). Also,

environmental parameters to which the equipment will be exposed are documented

in AP1000 - Equipment Qualification (EQ) and Severe Accident Radiation Dose

(Reference 3) and Thermal Hydraulic Environments for AP1000 Equipment

Survivability Analyses (Reference 4).

The approach to a systematic evaluation of equipment and instrumentation to

address its survivability for intervening in a severe accident is by identification of the

equipment type, equipment location, survival time required, and the use of design

basis event qualification requirements and severe environment experimental data.



The methodology used to demonstrate equipment survivability is as follows :(note 1)

a) Identify the high level actions used to achieve a controlled, stable state

b) Define the accident Time.Frames for each high level action

c) Determine the equipment and instrumentation used to diagnose, perform and

verify high level actions in each Time Frame

d) Determine the bounding environment within each Time Frame

e) Demonstrate with reasonable assurance that the equipment will survive to

perform its intended function within the severe environment.

Items a through d are presented in this report. Item e will be completed in future

revisions of this report prior to equipment installation. As-built reconciliation will be

completed and issued prior to fuel loading (see Open Item No. 3).

For the equipment used for severe accident mitigation that has not been tested at

severe accident conditions, a thermal lag assessment of the equipment (hydrogen

igniters and containment penetrations) will be performed to provide additional

assurance that this equipment can perform its severe accident functions during

environmental conditions resulting from hydrogen burns associated with severe

accidents. This assessment is performed prior to fuel load and is required only for

equipment used for severe accident mitigation that has not been tested at severe

accident conditions. The Environment Enveloping method or the Test Based

Thermal Analysis method discussed in Large-Scale Hydrogen Burn Equipment

Experiments, EPRI NP-4354 (Reference 5) will be used to assess the ability of the

equipment to perform during severe accident hydrogen burns. Any as-built part of

note 1 Items a and b are taken directly from the AP1000 Probabilistic Risk Assessment, Appendix DEquipment Survivability Assessment (Reference 1). The high level definition for the equipment andinstrumentation for item c is described in Section 8 with detailed identification of the equipment tagnumbers via review of the P&ID drawings. The environmental conditions for item d are taken fromReferences 3 and 4.



information item 19.59.10-5 will be provided prior to fuel load as stated in AP1000

As-Built COL Information Items (Reference 6).

2. Applicable Regulations and Criteria

The requirements for equipment survivability differ from those for equipment

qualification. Equipment qualification requires that safety-related equipment, both

electrical and mechanical, must perform its safety function during design basis

events. The level of assurance provided for the equipment operability during design

basis events is called environmental qualification or equipment qualification.

The environmental conditions resulting from beyond design basis events may be

more limiting than conditions from design basis events. Beyond design basis events

can be divided into two classes, in-vessel and ex-vessel severe accidents. During

the in-vessel events, the core loses its coolability, leading to at least a partial fuel

melt. During the ex-vessel events, a reactor vessel failure is assumed, leading to a

relocation of molten corium (i.e., a mixture of fuel and structural materials) to the

containment. The NRC has established criteria to provide a reasonable level of

assurance that necessary equipment will function in the severe accident

environment within the time span it is required. The criteria are referred to as"equipment survivability."

The applicable criteria for equipment, both mechanical and electrical, required for

recovery from in-vessel severe accidents are provided in 10 CFR 50.34(f):

Part 50.34(f)(2)(ix)(c) states that equipment necessary for achieving and

maintaining safe shutdown of the plant and maintaining containment integrity

will perform its safety function during and after being exposed to the

environmental conditions attendant with the release of hydrogen generated by

the equivalent of a 100 percent fuel-clad, metal-water reaction including the



environmental conditions created by activation of the hydrogen control

system.

* Part 50.34(f)(2)(xvii) requires instrumentation to measure containment

pressure, containment water level, containment hydrogen concentration,

containment radiation intensity, and noble gas effluents at all potential,

accident release points.

* Part 50.34(f)(2)(xix) requires instrumentation adequate for monitoring plant

conditions following an accident that includes core damage.

" Part 50.44(c)(3) states that systems necessary to ensure containment

integrity shall be demonstrated to perform their function under conditions

associated with an accident that releases hydrogen generated from

100 percent fuel-clad metal-water reaction.

* Part 50.44(c)(4) states that equipment must be provided for monitoring

hydrogen in the containment that is functional, reliable, and capable of

continuously measuring the concentration of hydrogen in the containment

atmosphere following a significant beyond design-basis accident for accident

management, including emergency planning.

The applicable criteria for equipment, both electrical and mechanical, required for

mitigating the consequences of ex-vessel severe accidents is discussed in

Section Ull.F, "Equipment Survivability" of SECY-90-016 (Reference 7). The NRC

recommends in SECY-93-087 (Reference 8) that equipment provided only for

severe accident protection need not be subject to 10 CFR 50.49 environmental

qualification requirements, the 10 CFR Part 50 Appendix B quality assurance

requirements, or 10 CFR Part 50 Appendix A redundancy/diversity requirements.

However, mitigation features must be designed to provide reasonable assurance



they will operate in the severe accident environment for which they are intended and

over the time span for which they are needed.

Section 19.2.3.3.7 of Reference 2 (Equipment Survivability) identifies that these

regulations collectively indicate the need to perform a systematic evaluation of all

equipment, both electrical and mechanical, and instrumentation to ensure its

survivability for intervening in an in-vessel severe accident. The sections of

SECY-90-016 and SECY-93-087 on equipment survivability discuss the applicable

guidance for mitigating the consequences of ex-vessel severe accidents.

3. Severe Accident Management Goals

The goal of severe accident management is to achieve a controlled, stable state

following a beyond design basis accident. Establishment of a controlled, stable state

protects the integrity of the containment pressure boundary. The conditions for a

controlled, stable state are defined by APP-GW-GL-027, Framework for AP1000

Severe Accident Management Guidance (SAMG) (Reference 9). The three goals

are: 1) to return the core to a controlled, stable state, 2) to maintain or return the

containment to a controlled, stable state, and 3) to terminate fission product releases

from the plant.

3.1. Controlled, Stable Core State

A controlled, stable core state is defined as core conditions under which no

significant short term or long term physical or chemical changes (i.e., severe

accident phenomena) would be expected to occur. A significant short term or

long term change is one which would require an operator response to prevent a

change in core location, a challenge to containment integrity, or fission product

releases. In order to achieve a controlled, stable core state, two primary

conditions must be met, as summarized below:



* A process must be in place for transferring the energy being generated in

the core to a long-term heat sink

" The core temperature must be well below the point where chemical or

physical changes might occur

3.2. Controlled, Stable Containment State

A controlled, stable containment state is defined as containment conditions

under which no significant short term or long term physical or chemical changes

would be expected to occur. A significant short term or long term change is

one which would require an operator response to prevent a challenge to

containment integrity or fission product releases' In order to achieve a

controlled, stable containment state, three conditions must be met, as

summarized below:

* A process must be in place for transferring all of the energy that is being

released to the containment to a long-term heat sink

" The containment boundary must be protected and functional

* The containment and Reactor Coolant System conditions must be well

below the point where chemical or physical processes (severe accident

phenomena) might result in a dynamic change in containment conditions

or a failure of the containment boundary

3.3. Fission Product Release Prevention, Termination and Mitigation

Some of the conditions may be duplicates of previous conditions for

maintaining a controlled, stable core and/or containment state. They are also

included to reinforce the goal of controlling and terminating fission product

releases during a severe accident. To achieve the goal of terminating fission

product releases from the plant, three conditions must be met:



* The isolation of the containment boundary, including penetrations and

steam generator tubes, must be maintained

* The fission product inventory of the containment atmosphere must be

minimized

* Significant leakage through the containment boundary must be stopped

4. Equipment Survivability Time Frames

The purpose of the equipment survivability Time Frames is to identify the time span

in the severe accident in which specific equipment is required to perform its function.

The phenomena and environment associated with that phase of the severe accident

defines the environment which challenges the equipment survivability. The

equipment survivability Time Frame definitions are summarized in Table 1.

4.1.Time Frame 0 (TO (note 2)) Pre-Core Uncovery

Time Frame 0 is defined as the period of time in the accident sequence after

the accident initiation and prior to core uncovery. The fuel rods are cooled by

the water/steam mixture in the reactor vessel. The accident has not yet

progressed beyond the design basis of the plant, and hydrogen generation and

the release of fission products from the core are negligible. Emergency

Operating Procedures (EOPs) are designed to maintain or recover the borated

water inventory and heat removal in the reactor coolant system to prevent core

uncovery and establish a safe, stable state. Recovery within Time Frame 0

prevents the accident from becoming a severe accident. Equipment

survivability in Time Frame 0 is covered under the design basis equipment

qualification program.

note 2 T - Refers to Time Frame. In this case, TO is Time Frame 0.



4.2. Time Frame 1 (T1) - Core Heatup

Time Frame 1 is defined as the period of time after core uncovery and prior to

the onset of significant core damage as evidenced by the rapid zirconium-water

reactions in the core. This is the transition period from design basis to severe

accident environment. The overall core geometry is intact and the uncovered

portion of the core is overheating due to the lack of decay heat removal.

Hydrogen releases are limited to relatively minor cladding oxidation and some

noble gas and volatile fission products may be released from the fuel-clad gap.

As the core-exit gas temperature increases, the EOPs transition to a red path

indicating inadequate core cooling. The operators attempt to reduce the core

temperature by depressurizing the RCS and re-establish the borated water

inventory in the reactor coolant system. If these actions do not result in a

decrease in core-exit temperature, the control room staff initiates actions to

mitigate a severe accident by turning on the hydrogen igniters for hydrogen

control and flooding the reactor cavity to prevent reactor pressure vessel

failure. Recovery in Time Frame 1 prevents the accident from becoming a core

melt. The containment conditions are expected to be within the design basis

conditions while the reactor vessel and RCS conditions will be slightly above

the design basis. Equipment survivability in Time Frame 1 is evaluated to

demonstrate it is within the equipment qualification envelope.

4.3. Time Frame 2 (T2) - In-Vessel Severe Accident Phase

Time Frame 2 is the period of time in the severe accident after the accident

progresses beyond the design basis of the plant and prior to the establishment

of a controlled, stable state (end of in-vessel core relocation), or prior to reactor

vessel failure. The onset of rapid zirconium-water reactions of the fuel rod

cladding and hydrogen generation defines the beginning of Time Frame 2. The

heat of the exothermic reaction accelerates the degradation, melting and

relocation of the core. Fission products are released from the fuel-clad gap as



the cladding bursts and also from the fuel matrix as the U0 2 pellets melt. Over

the period of Time Frame 2, the initial intact geometry of the core is lost as it

melts and relocates downward. Severe accident management strategies

exercised during Time Frame 2 are designed to recover reactor coolant system

inventory and heat removal, to maintain reactor vessel integrity and to maintain

containment integrity. Recovery actions in Time Frame 2 may create

containment environmental challenges by increasing the rate of hydrogen and

steam generation.

4.4. Time Frame 3 (T3) - Ex-Vessel Severe Accident Phase

Time Frame 3 is defined as the period of time after the reactor vessel fails until

the establishment of a controlled, stable state. The AP1000 reliably provides

the capability to flood the reactor vessel and prevent the vessel failure in a

severe accident. This severe accident, Time Frame 3, is predicted to be a very

low probability event. However, it is included in the SAMG to provide guidance

in the event that reactor vessel failure occurs. Molten core debris is relocated

from the reactor vessel onto the containment cavity floor which creates the

potential for rapid steam generation, core-concrete interaction and non-

condensable gas generation. Severe accident management strategies

implemented in Time Frame 3 are designed to monitor the accident

progression, re-establish a coolable core configuration on the containment

floor, maintain containment integrity and mitigate fission product releases to the

environment.

5. Definition of Active Time Frame

Equipment only needs to survive long enough to perform its function to protect the

containment fission product boundary. The time of active operation is the time



during which the equipment must perform its function. In cases of some items, such

as valves or motor-operators, the equipment function is completed when it changes

state (e.g., closed). For other items, such as pumps, the equipment must operate

continuously to perform its function.

6. Description of Systems Required for Survivability Evaluation

The following systems are used for the deterministic analyses model of the impact of

AP1000 design features on severe accident mitigation and containment performance

challenges associated with severe core damage accidents:

6.1. Reactor Coolant System (RCS)

One of the safety related functions is the capability to shut down the reactor

and maintain it in a safe shutdown condition. The RCS transfers the heat

generated in the RCS to the Steam Generator System (SGS) during accident

conditions. The RCS, in conjunction with SGS and startup feedwater pumps,

can prevent the need for actuation of the passive safety-related decay heat

removal system.

The RCS, in conjunction with Passive Core Cooling System (PXS), provides

the coolant circulation and decay heat removal required during the transition

from forced circulation to natural circulation during accident operations.

A subsystem of the RCS is the automatic depressurization system (ADS). The

ADS acts in conjunction with the PXS to mitigate the consequences of loss of

coolant accidents. The safety-related ADS function is to automatically

depressurize the RCS so that the PXS can adequately cool the core during

small break loss of coolant accidents (LOCAs).



6.2. Steam Generator System (SGS)

One of the functions of the SGS is to remove primary heat from reactor coolant

system and to provide secondary side over pressure protection. In conjunction

with the RCS, Main and Startup Feed Water System (FWS), and the Main

Steam System (MSS), SGS removes decay heat generated in the RCS and

transfers it to the SGS through the Steam Generators (SGs). Such operation

serves to prevent unnecessary actuation of the passive safety-related decay

heat removal system.

6.3. Passive Core Cooling System (PXS)

The Passive Core Cooling System is a safety-related system designed to

provide sufficient core cooling for design basis events. PXS consists of a

passive residual heat removal heat exchanger (PRHR HX), two accumulators

(ACC), two core makeup tanks (CMT), and an in-containment refueling water

storage tank (IRWST). The core cooling function is provided by the RCS

injection system, the emergency core decay heat removal subsystem, and the

automatic depressurization system (ADS) (Reference 2, Sections 19.1.8.8

through 19.1.8.13).

6.3.1. Passive Residual Heat Removal System (PRHR)

The PRHR provides a safety-related means of performing the following

functions:

* remove core decay heat during accidents

* allows adequate plant performance during transient (non-LOCA and

non-ATWS) accidents without ADS

* allows automatic termination of RCS leak during a steam generator

tube rupture (SGTR) accident without ADS



* allows the plant to ride out an anticipated transient without scram

(ATWS) event without rod insertion

6.3.2. Accumulators (ACC)

The accumulators provide a safety-related means of safety injection of

borated water to the RCS. Each of the two accumulators has an

injection line to the reactor vessel/DVI nozzle. Each injection line has

two check valves (CVs) in series.

6.3.3. Core Makeup Tanks (CMTs)

The CMTs provide safety-related means of high pressure safety injection

(HPSI) of borated water to the RCS. Each of the two CMTs has an

injection line to the reactor vessel/DVI nozzle. Each CMT has a normally

open pressure balance line from an RCS cold-leg. Each injection line is

isolated with a parallel set of air-operated valves (AOVs). These AOVs

open on loss of Class 1 E DC power, loss of air, or loss of the signal from

the protection and safety monitoring system (PMS). The injection line for

each CMT also has two normally open CVs in series.

6.3.4. In-Containment Refueling Water Storage Tank (IRWST)

The IRWST subsystem provides a safety-related means of performing

the following functions:

* low pressure safety injection (LPSI) following ADS actuation

* long-term core cooling via containment recirculation

* reactor vessel cooling through the flooding of the reactor cavity by

draining the IRWST into the containment

Two (redundant) injection lines run from the IRWST to the reactor

vessel/DVI nozzle. A parallel set of valves isolates each line. Each set



has a CV in series with a squib valve. Two (redundant) recirculation

lines run from the containment to the reactor vessel DVI injection line.

Each recirculation line has two paths. One path contains a squib valve

and a MOV, and the other path contains a squib valve and a CV. The

two MOV/squib valve lines also provide the capability to flood the reactor

cavity.

6.3.5. Automatic Depressurization System (ADS)

The function of the ADS is to provide a safety-related means of reducing

the RCS pressure in a controlled fashion during accidents to allow safety

injection. This contributes the bleed portion of the feed-and-bleed

means of core cooling. The ADS actuates automatically, with manual

backup actuation capability, and has incorporated redundancy (four ADS

stages with two paths in each of the first three stages and four paths in

fourth stage) and defense against common-cause failures (motor-

operated valves (MOVs) in the first three stages and explosive valves in

the fourth stage).

6.4. Chemical and Volume Control System (CVS)

The CVS provides a safety-related means to terminate inadvertent RCS boron

dilution and to preserve containment integrity by isolation of the CVS lines

penetrating the containment. The CVS also provides a non-safety-related

means to provide makeup water to maintain RCS inventory to prevent actuation

of the passive safety system (CMTs and/or ADS) during small RCS leaks, and

provide coolant to the pressurizer auxiliary spray to reduce the RCS pressure

during accident conditions. The CVS has two makeup pumps, and each pump

is capable of providing normal makeup. The two safety-related AOVs provide

isolation of normal CVS letdown during shutdown operation on low hot-leg

level.



6.5. Normal Residual Heat Removal System (RNS)

The RNS provides a non-safety-related means of core cooling during accidents

through the following functions:

* RCS recirculation cooling during shutdown conditions

" low pressure pumped makeup flow from the Spent Fuel Pool Cooling

System (SFS) cask loading pit and long-term recirculation from the

containment sump

" heat removal from the IRWST during PRHR operation

Such RNS functions provide defense-in-depth in mitigating accidents, in

addition to the protection provided by the passive safety-related systems. The

RNS also provides a safety-related means of performing the following

functions:

• containment isolation for the RNS lines that penetrate the containment

" isolation of the RCS at the RNS suction and discharge lines

* pathway for long-term, post accident makeup of containment inventory

The RNS has redundant pumps and redundant HXs.

6.6 Main and Startup Feed Water System (FWS)

The Steam Generator System (SGS) and portions of the Main and Startup

Feedwater System (FWS) transport and control feedwater from the Condensate

System (CDS) to the steam generator during normal operation. The start-up

feedwater system pumps provide a non-safety-related means of delivering

feedwater to the SGs when the main feedwater pumps are unavailable during a

transient. This capability provides an alternate core cooling mechanism to the



PRHR HX for non-LOCA or SGTR accidents which minimizes the PRHR

challenge rate.

6.7 Fire Protection System (FPS)

The FPS detects and suppresses fires in the plant. The FPS consists of water

distribution systems, automatic and manual suppression systems, fire detection

and alarm systems, and portable fire extinguishers. The FPS provides fire

protection for the nuclear island, the annex building, the turbine building, the

radwaste building and the diesel generator building.

6.8 Containment System (CNS)

The CNS is the collection of boundaries that separates the containment

atmosphere from the outside environment during design basis accidents. The

CNS provides the safety-related function of containment isolation for the

containment boundary integrity and provides a barrier against the release of

fission products to the atmosphere.

The Diverse Actuation System (DAS), in addition to the Protection and Safety

Monitoring System (PMS), controls containment isolation valves (CIVs) in lines

that represent risk-significant release paths to further limit offsite releases

following core melt accidents. These lines are containment purge supply and

exhaust, and normal containment sump. Short-term availability controls for the

DAS address the operability of DAS actuation of these isolation valves.

6.9 Containment Hydrogen Control System (VLS)

The VLS limits hydrogen gas concentration in the containment during

accidents. The AP1000 design includes a hydrogen igniter system to limit the

concentration of hydrogen in the containment during severe accidents. The

system has the following features:



* 64 glow plug igniters distributed throughout the containment

* powered from the non-safety-related onsite ac power system, but also

capable of being powered by offsite ac power, onsite nonessential diesel

generators, or non-Class 1 E batteries via dc-to-ac inverters

* manually actuated from the control room when core-exit temperature

exceeds 648.9 *C (1200 OF) to provide the igniter activation before rapid

cladding oxidation

6.10 Passive Containment Cooling System (PCS)

The PCS removes heat from the containment during design basis events. A

non-safety grade containment spray system with the capability to supply

water to the containment spray header from an external source in the event of

a severe accident is provided by the Fire Protection System.

6.11 Primary Sampling System (PSS)

The PSS collects samples of fluids in the Reactor Coolant System (RCS) and

the containment atmosphere during normal operation and post-accident mode

of plant operation.

6.12 Diverse Actuation System (DAS)

The DAS initiates reactor trip, actuates selected functions, and provides plant

information to the operator.

The following functions are automatically activated by DAS:

" Reactor and Turbine Trip on Low Wide Range Steam Generator Water

Level or Low Pressurizer Water Level

* Passive Residual Heat Removal (PRHR) Actuation and In-

Containment Refueling Water Storage Tank (IRWST) Gutter Isolation



on Low Wide Range Steam Generator Water Level or on High Hot Leg

Temperature

* Core Makeup Tank (CMT) Actuation and Trip All Reactor Coolant

Pumps on Low Wide Range Steam Generator Water Level or Low

Pressurizer Water Level

* Isolation of Selected Containment Penetrations and Initiation of

Passive Containment Cooling System (PCS) on High Containment

Temperature

The following functions are manually activated by DAS:

* Reactor and Turbine Trip

* PRHR Actuation and IRWST Gutter Isolation

• CMT Actuation and Trip All Reactor Coolant Pumps

* First-stage Automatic Depressurization System (ADS) Valve Actuation

" Second-stage ADS Valve Actuation

* Third-stage ADS Valve Actuation

* Fourth-stage ADS Valve Actuation

* PCS Actuation

* Isolation of Selected Containment Penetrations

* Containment Hydrogen Igniter Actuation

* IRWST Injection Actuation

* Containment Recirculation Actuation

• Actuate IRWST Drain to Containment



6.13 Protection and Safety Monitoring System (PMS)

The PMS initiates reactor trip and actuation of engineered safety features in

response to plant conditions monitored by process instrumentation and

provides safety-related displays. The PMS has two divisions of safety-related

post-accident parameter displays.

The following engineering safety features are automatically activated:

* Safeguards Actuation

* Containment Isolation

* Automatic Depressurization System (ADS) Actuation

* Main Feedwater Isolation

" Reactor Coolant Pump Trip

* CMT Injection

* Turbine Trip (Isolated signal to non-safety equipment)

* Steam Line Isolation

* Steam Generator Relief Isolation

* Steam Generator Blowdown Isolation

• Passive Containment Cooling Actuation

* Startup Feedwater Isolation

* Passive Residual Heat Removal (PRHR) Heat Exchanger Alignment

* Block of Boron Dilution

* Chemical and Volume Control System (CVS) Makeup Line Isolation

* MCR Isolation and Air Supply Initiation



* Auxiliary Spray and Letdown Purification Line Isolation

* Containment Air Filtration System Isolation

* Normal Residual Heat Removal Isolation

* Refueling Cavity Isolation

" In-Containment Refueling Water Storage Tank (IRWST) Injection

" IRWST Containment Recirculation

* CVS Letdown Isolation

* Pressurizer Heater Block (Isolated signal to non-safety equipment)

The following engineering safety features are manually activated:

* Reactor Trip

* Safeguards Actuation

* Containment Isolation

* Depressurization System Stages 1, 2, and 3 Actuation

" Depressurization System Stage 4 Actuation

* Feedwater Isolation

* Core Makeup Tank Injection Actuation

* Steam Line Isolation

* Passive Containment Cooling Actuation

* Passive Residual Heat Removal Heat Exchanger Alignment

" IRWST Injection

* Containment Recirculation Actuation

* Control Room Isolation and Air Supply Initiation



* Steam Generator Relief Isolation

* Chemical and Volume Control System Isolation

* Normal Residual Heat Removal System Isolation

7. High Level Action to Achieve a Controlled, Stable State

Framework for AP1000 Severe Accident Management Guidance (Reference 9)

defines the high level actions required to mitigate the severe accident, achieve a

controlled, stable state and terminate fission product releases. The high level

actions relative to severe accident management goals are summarized in Table 2

and serve as the basis for identification of the equipment required to mitigate the

accident.

The equipment and instrumentation required to be available in each Time Frame for

the high level actions are summarized in Table 3. They are based on the systems

identified in AP1000 Probabilistic Risk Assessment, Appendix D (Reference 1) with

additional input from APP-GW-VPC-020, AP1000 DCD Chapter 19 Appendix D

Markup (Reference 10), and AP1000 Severe Accident Management Guidelines,

Volume 1 (Reference 11).

The subsections which follow recap the high level actions and the equipment,

instrumentation and associated active operation times needed to provide reasonable

assurance of achieving a controlled stable state.



7.1 Injection into the Reactor Coolant Loop (RCS) (Al(note 3))

Successful injection into the RCS removes the sensible and decay heat from

the core. Failure of RCS injection is likely to be the reason the accident has

proceeded to core uncovery. Prior to onset of the rapid oxidation of the

cladding, successful RCS injection recovers the accident before it progresses

to substantial core damage and establishes a controlled, stable state. Failure

to inject into the RCS at a sufficient rate allows the accident to proceed into

Time Frame 2 and the SAMG.

In Time Frame 2, the in-vessel core configuration loses its coolable geometry

and it is likely that at least some of the core debris will migrate to the reactor

vessel lower head. If the RCS is depressurized and if the reactor vessel is

submerged, the core debris will be retained in the reactor vessel. However,

injection into the RCS to cover and cool the core debris is required to achieve a

controlled, stable state. RCS injection is not required to protect the

containment fission product boundary. Injection is successful if it is sufficient to

quench the sensible heat from the core debris and to refill the reactor vessel.

Decay heat removal will then be accomplished by a combination of heat

transfer to the water in the reactor vessel and heat transfer to the water on the

exterior surface of the reactor vessel. Water can be injected into the RCS

using the CVS or the RNS systems.

The PXS is not credited in Time Frame 2 because automatic and manual

activation of the system is attempted several times in Time Frame 0 and 1.

Injection to the RCS is no longer needed in Time Frame 3 since RCS is failed.

note 3 The letter "A" refers to High Level Action. In this case, Al is Injection into the Reactor Coolant

System.



The injection into RCS will be achieved in three stages:

a. RCS at operating pressure

The equipment and systems used to inject into the RCS are the core

makeup tanks and the makeup pumps.

b. RCS at reduced pressure

The equipment and systems used to inject into the RCS are the

accumulators, the makeup pumps, and the normal RNS pumps. For

non-LOCA and small LOCA sequences, depressurization of the RCS is

required for successful injection.

c. RCS at containment pressure

The equipment and systems used to inject into the RCS are IRWST

(which is part of the PXS), the makeup pumps, and RNS pumps.

The plant response is monitored using the system flowrates, IRWST water

level, core-exit temperature, RCS pressure and RCS temperature. Post-core

damage, the response may be monitored with RCS pressure, temperature,

containment pressure, CVS and RNS flowrates.

7.2 Injection into Containment (A2)

The operator is instructed via EOPs to inject water into the containment to

submerge the reactor vessel and cool the external surface if injection to the

RCS cannot be established. This action is performed at the end of

Time Frame 1, immediately prior to entry into the SAMG. Successful cavity

flooding, in conjunction with RCS depressurization, prevents vessel failure in

the event of molten core relocation to the vessel lower head. Failure of cavity

flooding may allow the accident to proceed to vessel failure and molten core

relocation into the containment (Time Frame 3) if timely injection into the



reactor vessel cannot be established to cool the core and prevent substantial

core relocation to the lower head.

The objective of injection to the containment prior to reactor vessel failure (Time

Frame 3) is to cool the external surface of the reactor vessel to maintain the

core debris in the vessel. Due to the lead time required to submerge the

bottom head of the reactor vessel prior to core relocation to the bottom head,

injection to the containment for in-vessel retention is achieved by instructing the

operator to drain the IRWST in the EOPs within Time Frame 1. If the vessel

fails, the accident progresses to Time Frame 3.

The injection into containment will be achieved in three ways:

a. Inject into containment from IRWST

The PXS motor-operated valves and PXS squib valves are opened

manually to drain the IRWST water into the containment in Time Frame 1.

b. Inject into containment from containment spray

The fire protection system provides containment spray function in

Time Frame 2 and 3.

c. Inject into containment via overflow IRWST

The RNS system provides water to overflow the IRWST in

Time Frames 2 and 3.

The plant response is monitored by core-exit thermocouples, containment

water level and IRWST water level indication.

7.3 Decay Heat Removal (A3)

In the event of non-LOCA or small LOCA sequences, the RCS pressure is

elevated above the secondary pressure. Failure of the PRHR may be the

reason that the event proceeds to core overheating. Recovery of the PRHR will



provide decay heat removal. Failure of feedwater to the steam generators with

the PRHR failed may be a cause for core overheating and recovery of injection

to the steam generators may be required. If the steam generators remain dry

without PRHR recovery and the core is uncovered, the tube integrity or hot leg

nozzle integrity may be threatened by creep rupture failure at the onset on rapid

oxidation (entry into Time Frame 2) if the RCS is at a high pressure state.

Injecting to the steam generators provides a heat sink to the RCS by boiling

water on the secondary side, and protects the tubes by cooling them.

Successful steam generator injection can establish a controlled, stable state if

the losses from the RCS can be recovered and mitigated. Failure to inject to

the steam generator requires depressurization of the RCS to prevent creep

rupture failure of the tubes and loss of the containment integrity at the onset of

rapid oxidation in Time Frame 2.

In transients and small LOCAs, initiation of PRHR or injection into the steam

generators is required to be recovered in Time Frame 1 to be successful. If the

secondary side is dry and the RCS is not depressurized, the steam generator

tubes can experience creep rupture failure due to circulation of hot gases when

the cladding oxidation begins at the onset of Time Frame 2. Steam generator

injection is not required for LOCAs which depressurize the RCS below the

secondary system pressure.

Within Time Frame 2, steam generator injection can be utilized in un-isolated

SGTR sequences to maintain the water level on the secondary side for

mitigation of fission product releases. Injecting into the steam generators,

along with depressurization of the RCS, is an accident management action to

isolate containment or scrub fission products. Failure to inject to the ruptured

steam generator in Time Frame 2 can lead to continued breech of the

containment fission product boundary and large offsite doses.



PRHR activation or injection into the steam generators is no longer needed in

Time Frame 3. Injection to the steam generator for SGTR fission product

scrubbing is not required to maintain the water level.

The decay heat removal can be achieved via two ways:

a. PRHR- HX

The PRHR - HX provides decay heat removal from the RCS.

b. High pressure injection into steam generator

The main feedwater and startup feedwater pumps are used to inject into a

pressurized secondary system.

The plant response is monitored with the core-exit thermocouples, RCS RTDs,

IRWST water level, IRWST water temperature, steam generator wide range

water level and steamline pressure.

7.4 Depressurize Reactor Coolant System (A4)

Depressurization of the RCS, along with injecting into the containment is an

accident management strategy to prevent vessel failure. The depressurization

of the RCS reduces the stresses on the damaged vessel wall facilitating the in-

vessel retention of core debris. In the event of non-LOCA or a small LOCA

sequences, the RCS pressure is above the secondary pressure. If the steam

generators are dry and the core is uncovered, the hot leg nozzle or tube

integrity is threatened by creep rupture failure at the onset of rapid cladding

oxidation (beginning of Time Frame 2). Timely depressurization (prior to

significant cladding oxidation) of the RCS mitigates the threat to the tubes,

allows injection of the accumulators and IRWST water, and provides a long-

term heat sink to establish a controlled, stable state. Failure to depressurize

can result in the failure of the tubes and a loss of containment integrity when

oxidation begins. The LOCA sequences (other than small LOCA sequences)



by definition are not a threat to steam generator tube integrity upon the onset of

rapid oxidation. Depressurization may be required for injection to establish a

long-term heat sink. Medium LOCAs require additional depressurization to

allow the injection of RNS or PXS. Large LOCAs are fully depressurized by the

initiating event.

RCS depressurization is required within Time Frame 1 for facilitating in-vessel

retention of core debris and for successfully preventing steam generator tube

failure in high pressure severe accident sequences. The steam generator tubes

or hot leg nozzles may fail due to creep rupture after the onset of rapid

oxidation at the beginning of Time Frame 2. This action facilitates in-vessel

retention of core debris in conjunction with injection into the containment to give

time to recover pumped injection sources to establish a controlled, stable state.

RCS depressurization is provided by instructing the operator to depressurize

the system in the EOPs in Time Frame 1. Active operation of RCS

depressurization is completed prior to Time Frame 2. The reactor vessel head

vent valves are used to depressurize the RCS and avoid overpressurization.

Since depressurize RCS (A4) action is completed in Time Frames I and 2, the

reactor vessel head vent is no longer needed in Time Frame 3.

The depressurization can be achieved via several methods. The most primary

methods are:

a. Depressurize via ADS stage 1, 2, and 3

The automatic depressurization system (ADS) is required to depressurize

the RCS to allow the PXS systems to inject.

b. The Reactor Vessel Head Vent

The reactor vessel head vent valves are used to depressurize the RCS and

avoid overpressurization.



c. Depressurize via ADS stage 4

The ADS stage 4 is used to depressurize the RCS to prevent reactor vessel

failure by flooding the RCS loop compartment. In LOCA sequences, only

the ADS are effective in providing depressurization capability to allow

injection to the RCS.

Also, the RCS is depressurized by the vessel failure in Time Frame 3.

The RCS pressure, IRWST water level, core-exit temperature and RCS

temperature can be used to monitor the plant response to the RCS

depressurization.

7.5 Depressurize Steam Generators (A5)

The steam generators may be depressurized to depressurize the RCS in non-

LOCA and small LOCA sequences. Injection to the steam generator must be

available to depressurize the secondary system to prevent creep rupture failure

of the tubes.

Active operation to depressurize a steam generator can be used to cooldown

the RCS prior to Time Frame 2. After the onset of core melting and relocation,

depressurizing steam generators could threaten steam generator tube integrity.

Depressurizing the steam generator in Time Frame 2 does not facilitate the

establishment of a controlled, stable state. However, depressurization of the

steam generators is called for in the EOPs and is appropriate in Time Frame 2

if the RCS is depressurized in order to minimize the pressure deferential across

the steam generator tubes.

The steam generator PORV and main steam bypass valves are used for

depressurizing the steam generators. Depressurization of the steam generators

is used in the EOPs as a means to cooldown and depressurize the RCS.



Steam generator depressurization is not needed in Time Frame 3 as the RCS

is failed.

The main steamline pressure, SG wide range water level and RCS pressure

can be used to monitor the plant response.

7.6 Containment Heat Removal (A6)

Containment heat removal is provided by the PCS. Water cooling of the shell is

needed to establish a controlled, stable state with the containment

depressurized. The actuation of PCS water is typically automatic in Time

Frame 0.

Within Time Frame 2, PCS flowrate and level are monitored to determine if

additional water is needed to permit continuation of PCS flow. Alternate water

sources can be provided by connections to the external PCS water tank which

is outside the containment pressure boundary and not subjected to the harsh

environment.

PCS water is supplied to the external surface of the containment shell from the

PCS water storage tank or the post-72 hour PCS ancillary water tank.

Alternative water sources can be provided via separate connections outside

containment.

The fire protection system provides a containment spray function for severe

accident management in Time Frames 2 and 3.

The containment heat removal can be monitored with the containment

pressure, the PCS water flowrate, the PCS water tank level, the PCS ancillary

water tank level and containment water level.



7.7 Containment Isolation and Venting (A7)

Containment isolation is provided by an intact containment shell and the

containment isolation system which closes the isolation valve in lines

penetrating the containment shell. Active operation of containment isolation

valves is required in Time Frame 1 to establish the containment fission product

barrier. Continued operation of the containment shell as a pressure boundary

is needed to maintain containment isolation in Time Frame 3.

In the event of containment pressurization above design pressure due to core

concrete interaction non-condensable gas generation, the containment can be

vented. Venting protects containment isolation by preventing an uncontrolled

containment failure airborne release pathway.

Containment venting to the spent fuel pool is available through RNS hot leg

suction line MOVs.

The containment isolation can be monitored by the containment isolation valve

position, containment pressure, SFP water level and containment temperature.

7.8 Hydrogen Control (A8)

Maintaining the containment hydrogen concentration below a global flammable

limit is a requirement for a controlled, stable state. While hydrogen is not

generated in a significant quantity until Time Frame 2, provisions are provided

in the EOPs within Time Frame 1 to turn on the igniters before hydrogen

generation begins so that hydrogen can be burned as it is produced.

Severe accident hydrogen control in the AP1000 is provided by hydrogen

igniters. The containment has passive auto-catalytic recombiners (PARs) as

well, but they are not credited in the severe accident assessments.



The operator action to actuate the igniters occurs prior to the hydrogen

generation at the onset of Time Frame 2. The igniters need to survive and

receive power throughout the hydrogen release to maintain the hydrogen

concentration below the lower flammability limit during the hydrogen generation

in Time Frame 2. If the containment becomes steam inert in Time Frame 2, the

igniters will become ineffective and hydrogen will accumulate in the

containment.

In Time Frame 3, the hydrogen igniters are used to control combustible gases.

Active operation of igniters continues to control the release of combustible

gases (e.g., hydrogen and carbon monoxide) from the degradation of concrete

in the reactor cavity. If the containment becomes steam inert in Time Frame 3,

the igniters will become ineffective and hydrogen will accumulate in the

containment.

The PARs are also available to control hydrogen in containment and can be

effective in a steam inert environment. The PARs are not credited in the design

basis for severe accident because they are passive equipment that cannot be

controlled by the operating staff from the control room.

The plant response to the igniter actuation can be monitored by containment

hydrogen concentration using the hydrogen monitors or containment

atmosphere sampling, which is part of the PSS. The containment pressure

response can also be used to indicate hydrogen burning.



7.9 Control Fission Product Releases (A9)

A non safety-related containment spray system is provided in AP1000 to scrub

aerosol fission products from the containment atmosphere. The spray system

is manually actuated on high containment radiation level at the onset of Time

Frame 2. Manually actuating the containment spray system involves opening

an air-operated valve inside the containment and actuating valves and a pump

outside the containment. Once open, the active operation of the valve inside

the containment is completed. The operation of the non-safety fire pumps,

which provide containment spray, could possibly continue into Time Frame 3,

until the water from the source tank is depleted. The plant response is

monitored using the containment water level.

7.10 Accident Monitoring (A10)

Sufficient instrumentation should exist to inform operators of the status of the

reactor and containment at all times, as it is intended that the operators can

recover from the in-vessel severe accident and implement a safe shutdown with

containment integrity maintained (Reference 2, 19.2.3.3.7).

Monitoring the progression of the accident and radioactive releases provide

input to emergency response and emergency action levels. During the initial

core melting and relocation, containment hydrogen and radiation monitors are

used for core damage assessment and verification of the hydrogen igniter

operation. Steam generator radiation monitoring is used to determine steam

generator tube integrity.

Containment pressure, temperature, water levels, radiation, steam generator

radiation, containment hydrogen concentration and containment atmosphere

sampling function are sufficient to monitor the accident in the long-term.



Containment pressure, containment temperature, containment hydrogen

monitors, containment water level, containment radiation, SG radiation

monitors, core-exit thermocouples, RCS pressure and IRWST water level could

be used for monitoring.

8. Equipment and Instrumentation

The equipment and instrumentation, used to diagnose, perform, and verify high level

actions in each Time Frame, are selected based on Table 3. The instrumentation

chosen allows the operator to confirm and trend the results of actions taken and

provides adequate information for those responsible for making accident

management decisions (Reference 2, 19.2.3.3.7.1).

The various containment locations are listed in Table 4. The location code is

designated as C-XY. The first letter of the code identifies the building with "C"

indicating inside containment and "A" indicating auxiliary building. X represents the

room elevations with the following identifiers. These room elevations are the

equipment actual elevation within the AP1000 plant and were obtained from list of

drawings in Reference 12:

* A-66ft6in

* B-82ft6inand96ft6in

* C-107ft2in

• D- 117 ft6 in

* E-135ft3in

• F-153ft0inand160ft6in

* G-160ft3inand180ft0in



0 H-233ft0inand258ft0in

Y is the last digit of the room number for the respective elevation. The room

number, elevation and room description are obtained from drawings listed in

Reference 12. For example, the location code "C-A4" identifies containment room

11104 at an elevation of 66 ft 6 in.

The equipment and instrumentation used in achieving a controlled, stable state

following a severe accident, the action required to operate in each Time Frame, and

equipment location are summarized in Table 5. The equipment locations are

obtained from AP1000 Equipment & Component Qualification Datasheet

(Reference 13) and the Hydrogen Igniter locations are obtained from AP1000

Hydrogen Igniter Locations (Reference 14).

Table 6a identifies the equipment located outside containment. This equipment will

not be subjected to the severe accident environment and therefore requires no

severe accident assessment.

Table 6b includes the list of equipment located inside containment that may be

required to perform an action during Time Frames 0 and 1. The environment during

Time Frames 0 and 1 is generally bounded by the Design Basis Accident (DBA)

environment for which safety-related equipment will be qualified.

Table 6c lists equipment inside containment that may need to perform an action

during Time Frames 2 and 3. It is noted that the following items listed in Table 5 as

being required during Time Frames 2 and/or 3 will not require assessment. The

technical justifications are provided in the identified subsections.

a. PXS IRWST Water Level (see Subsection 8.1.1.1 for technical justification)

b. CVS RCS Boundary AOVs, V081 and V084 (see Subsection 8.1.6.4 for

technical justification)



c. Containment Isolation MOVs, V207 (see Item 8.1.7.5 for technical

justification)

d. PXS PRHR MOV, V101 (see Item 8.1.7.8 for technical justification)

The detailed descriptions of equipment and instrumentation are summarized as

follows:

8.1. Equipment Located inside Containment

The exposure to elevated temperatures as a direct result of the postulated

severe accident or as a result of hydrogen burning is the primary parameter of

interest. Pressure environments do not exceed the design basis event

conditions for which the equipment has been qualified. Radiation environments

also do not exceed the design basis event conditions throughout


Tables 6b and 6c contain the primary instrumentation used to diagnose

conditions requiring operator actions or verifying successful implementation of

those actions.

8.1.1. Differential Pressure and Pressure Transmitters

The functions defined for accident management that utilizes in-

containment transmitters are IRWST water level, reactor coolant system

pressure, steam generator wide range water level and containment

pressure.

8.1.1.1. PXS I RWST Water Level

The IRWST water level transmitters are located in the

maintenance floor and are required during




Indirect IRWST water level and direct containment water level

are both measured using the containment water level floats. The

IRWST water level sensors are no longer needed in

Time Frames 2 or 3.

8.1.1.2. Reactor Coolant System Pressure

Reactor system pressure transmitters are required during

Time Frames 1 and 2 and are no longer needed in

Time Frame 3.

8.1.1.3. Steam Generator Wide Range Water Level

Steam generator wide range water level transmitters are

required during Time Frames 1 and 2 and are no longer needed

in Time Frame 3.

8.1.1.4. Containment Pressure

Containment pressure transmitters are needed for long term

monitoring. The transmitters may eventually be impacted by the

severe accident radiation dose.

8.1.2. Core-Exit Temperature

The functions defined for severe accident management that utilize

thermocouples are core-exit temperature. The core-exit temperature is

only required during Time Frames 1 and 2 and is no longer needed in

Time Frame 3.

8.1.3. Resistance Temperature Detectors (RTDs)

Both hot and cold leg temperatures are defined as parameters for

severe accident management in Time Frames 1 and 2. RTDs are



utilized for these measurements and will perform until their temperature

range is exceeded.

8.1.3.1. Hot Leg RTDs

The hot leg RTDs could fail as the temperature increases well

above the design conditions of the RTDs.

8.1.3.2. Cold Leg RTDs

The cold leg RTDs should perform throughout Time Frame 1. In

Time Frame 2 the RTDS could fail as the temperature increases

above the design conditions of the RTDs.

8.1.3.3. Containment Temperature

Containment Temperature RTDs are utilized through Time

Frame 3 for the containment temperature measurement and are

exposed to temperature -transients that exceed design basis

qualification conditions.

8.1.3.4. IRWST Water Temperature

The IRWST water temperature transmitters are located in the

maintenance floor and are required during


8.1.4. Hydrogen Monitors

Containment hydrogen is defined as a parameter to be monitored

throughout the severe accident scenarios. Early in the accident, the

hydrogen is monitored by a device that operates on the basis of catalytic

oxidation of hydrogen on a heated element. The hydrogen monitors are

located in the main containment area. These monitors may be used



through Time Frame 2. The design limits of this device may be

exceeded after the first few hours of some of the postulated accidents

and performance may be uncertain. Post-accident sampling of

containment atmosphere using analysis of grab samples may be used to

determine containment hydrogen concentrations.

8.1.5. PXS Radiation Monitors

Containment radiation is defined as a parameter to be monitored

throughout the severe accident scenarios. The containment radiation

monitors are located in the main containment area. Early in the

accident, the design basis event qualified containment radiation monitor

provides the necessary information until the environment exceeds the

design limits of the monitor. If the device fails, containment radiation is

determined through the containment atmosphere sampling function or by

portable monitors located against the outside of the containment shell.

8.1.6. Solenoid Valves - Vent Air-Operated Valves (AOVs)

Qualified solenoid valves are used to vent air-operated valves (AOVs) to

perform the function required.

8.1.6.1. PXS Core Makeup Tank AOVs

The core makeup tank AOVs located in the accumulator room

provides a path for RCS injection in Time Frames 0 and1.

8.1.6.2. PXS PRHR AOVs

The PRHR AOVs located in the maintenance floor provide a

path for RCS heat removal in Time Frames 0 and 1.



8.1.6.3. Containment Isolation AOVs

The containment is isolated by AOVs located in the

maintenance floor and the PXS valve/accumulator room which

are used in Time Frame 1.

8.1.6.4. CVS RCS Boundary AOVs

The RCS boundary AOV located in the maintenance floor is

used for CVS injection into the RCS in Time Frames 1 and 2.

Since the RCS purification return line stop valve is normal open

and failed open, this valve can be removed.

The auxiliary pressurizer spray line isolation valve is no longer

needed in Time Frame 3.

8.1.6.5. Containment Spray AOVs

The containment spray AOV located in the maintenance floor is

used for control of fission product release in


8.1.6.6. Containment Atmosphere Sampling Function

Throughout all Time Frames 0 through 3, access to the

containment environment from the containment atmosphere

sampling function is through solenoid valves located in the

maintenance floor.

8.1.6.7 Reactor Vessel Head Vent AOVs

The reactor head vent valves are used to depressurize the RCS

and avoid over pressurization in Time Frame 2.



8.1.7. Motor-Operated Valves (MOVs)

Motor-operated valves (MOVs) are utilized in several applications during

the severe accident scenarios.

8.1.7.1. PXS Accumulator MOVs

MOVs in the accumulator path are normally open and remain

open. These valves are needed in Time Frame 1.

8.1.7.2. PXS Core Makeup Tank MOVs

MOVs in the core makeup tank path are normally open and

remain open. These valves are needed in


8.1.7.3. PXS Recirculation MOVs

The PXS recirculation MOVs located in the PXS

valve/accumulator room are required for injection of water into

the containment in Time Frame 1.

8.1.7.4. ADS Stages 1, 2, 3, & 4 MOVs

MOVs for the first three stages of ADS located in a

compartment above the pressurizer and fourth stage ADS

located in steam generator compartments are required for RCS

depressurization in Time Frame 1.

8.1.7.5. Containment Isolation MOVs

In Time Frame 1, the containment is isolated by MOVs located

in the maintenance floor and the PXS valve/accumulator room.



Since CCS containment isolation valve will be closed in

Time Frame 1, this valve is no longer needed in


8.1.7.6. CVS Charging and Injection MOVs

In Time Frame 2, the charging and injection MOV located in the

maintenance floor provides a path from the CVS for RCS

injection.

8.1.7.7. RNS IRWST MOVs

An RNS MOV located in the PXS valve/accumulator room

provides a path from the IRWST for RCS injection in Time

Frame 1. This RNS MOV also provides a path from the RNS to

overflow the IRWST into containment in Time Frames 2 and 3.

8.1.7.8. RNS MOV for Injection from Cask Loading Pit to RCS

PXS PRHR MOV located in operating deck provides a path for

RCS heat removal in Time Frame 1 and 2 and replaces the

RNS MOV for injection from Cask Loading Pit to RCS (note 4)

Since the IRWST water will be drained at the end of Time

Frame 1, the PXS HX inlet isolation valve is no longer needed in


note 4 The MOV identified in Reference 1 section D.8.2.7 is identical to the MOV identified in section D.8.3

located outside containment. The PRHR HX has two AOVs and one MOV. PRHR AOVs are identified inD.8.2.6 but the PXS PRHR MOV is not identified in D.8.2.7. The PXS PRHR MOV is identified here as areplacement for the RNS MOV specified in section D.8.2.7 of Reference 1.



8.1.7.9. RNS Hot Leg Suction to Spent Fuel Pool

Throughout Time Frame 3, containment venting to the spent

fuel pool is available through RNS hot leg suction line MOVs

located in the RNS valve room.

8.1.8. Squib Valves

Squib valves are only required in Time Frame 1 when the severe

accident environment is not significantly different than the design basis

environment for which these valves are qualified.

8.1.8.1. IRWST Injection

IRWST injection squib valves located in the accumulator room are

used for injection into the RCS.

8.1.8.2. PXS Containment Recirculation

PXS recirculation squib valves located in the accumulator room are

used for injection into the containment.

8.1.8.3. Fourth Stage ADS

For RCS depressurization, the fourth stage ADS squib valves are

located in steam generator compartments 1 and 2.

8.1.9. Valve Position Sensors

Position sensors are required to monitor the position of containment

isolation valves that could lead directly to an atmospheric release.

These isolation valves actuate early in the transient, so verification is

only required during Time Frame 1. The position sensors are located in

the maintenance floor and the environment in this Time Frame does not

AP 000 Equipment Survivability Assessment APP-GW-VP-025 Rev. 0


exceed the design basis event qualification environment of the position

sensors.

8.1.10. Hydrogen Igniters

The hydrogen igniters are distributed throughout the containment and

are designed to perform in environments similar to those postulated for

severe accidents. The igniters' transformers are located outside

containment.

8.1.11. Electrical Containment Penetration Assemblies

The electrical containment penetrations are located in the lower

compartment and are required to perform both electrically and

mechanically (including containment pressure boundaries) throughout

the severe accident.

8.1.12. Cables

AP1000 cables will be evaluated using EPRI NP-4354 Large-Scale

Hydrogen Burn Equipment Experiments (Reference 5).

8.1.13 PXS Containment Water Level

The containment water level is required in Time Frames 2 and 3.

8.2. Equipment Located Outside Containment

Other functions defined for severe accident management are performed

outside containment and the equipment is not subjected to the harsh

environment of the event. Equipment includes the following:

8.2.1. Steamline Radiation Monitor (SG Radiation)

8.2.2. Transmitters for Monitoring Steamline Pressure



8.2.3. Passive Containment Cooling System Flow and Tank Level (PCS)

8.2.4. Containment Atmosphere Sampling Function

8.2.5. Makeup Pumps and Flow Measurement

8.2.6. RNS Pumps and Flow Measurement

8.2.7. MOV and Manual Valves from RNS Hot Leg Suction Lines to the Spent

Fuel Pool

8.2.8. RNS MOVs for Injection from Cask Loading Pit to RCS

8.2.9. Main Feedwater Pumps and Valves

8.2.10. Startup Feedwater Pumps and Valves

8.2.11. Fire Water, Fire Pumps, Valves and Flow Measurement Used to

Provide Containment Spray and Backup Containment Cooling

8.2.12. Steam Generator PORVs and Main Steam Bypass Valves for

Depressurization

8.2.13. PCS Recirculation Pumps and Valves and Fire Water Pumps and

Valves for Containment Heat Removal

8.2.14. Containment Isolation Valves (Outside Containment)

8.2.15. Auxiliary Building Radiation Monitor

9. Bounding Containment Environment

9.1. Radiation Accident - Severe Accident

This subsection (9.1) is extracted from APP-SSAR-GSC-507 (Reference 3).

The fraction of the core inventory released to the containment atmosphere has

been revised from the original PRA Appendix D (Reference 1).

house Electric Company Page 56 of 125

The radiation exposure inside the containment for a severe accident is

conservatively estimated by considering the dose in the middle of the AP1000

containment with no credit for the shielding provided by internal structures.

Sources are based on the emergency safeguards system core thermal power

rating and the following analytical assumptions:

* Power Level (including 2% power uncertainty) ............... 3,468 MWt

" Fraction of total core inventory released to the containment atmosphere

(Based on summing values in Tables 6-3 and 6-4 of Reference 3):

Noble Gases (Xe, Kr) .. .......................... 1.0

Halogens (I, Br) .. .......................... 0.75

Alkali Metals (Cs, Rb) . ........................... 0.75

Tellurium Group (Te, Sb, Se) .......................................... 0.305

Barium , Strontium (Ba, Sr) ....................................... 0.12

Noble Metals (Ru, Rh, Pd, Mo, Tc, Co) ............................ 0.005

Lanthanides (La, Zr, Nd, Eu, Nb, Pm, Pr, Sm, Y, Cm, Am) ... 0.0052

Cerium Group (Ce, Pu, Np) ............................... 0.0055

The radionuclide groups and elemental release fractions listed above are

consistent with the accident source term information presented in

NUREG-1465, Accident Source Terms for Light-Water Nuclear Power Plants -

Final Report (Reference 15).

The timing of the releases are based on NUREG-1465 assumptions. The

release scenario assumed in the calculations is described below.

An initial release of activity from the gaps of a number of failed fuel rods at

10 minutes into the accident is considered. The release of 5 percent of the



core inventory of the volatile species (defined as noble gases, halogens, and

alkali metals) is assumed. The release period occurs over the next 30 minutes,

that is, from 10 to 40 minutes into the accident. At this point, 5 percent of the

total core inventory of volatile species has been considered to be released.

Over the next 1.3 hours, releases associated with an early in-vessel release

period are assumed to occur, that is, from 40 minutes to 1.97 hours into the

accident. This source term is a time-varying release in which the release rate

is assumed to be constant during the duration time. Additional releases during

the early in-vessel release period include 95 percent of the noble gases,

35 percent of the halogens, and 25 percent of the alkali metals, as well as the

fractions of the tellurium group, barium and strontium, noble metals,

lanthanides, and cerium group as listed above.

The ex-vessel and late in-vessel periods commence after the early in-vessel

release period. After 2 hours, the early in-vessel period is assumed to have

completed. The late in-vessel period continues for an additional 8 hours. At

the completion of the late in-vessel period, the total fraction of the core

inventory defined above has been released to the containment atmosphere.

The resulting instantaneous gamma and beta dose rate are provided in

Figures 1 and 2, respectively.

9.2. Thermal-Hydraulic Environments

The bounding severe accident environmental envelopes for equipment

locations inside containment are provided by Thermal Hydraulic Environments

for AP1000 Equipment Survivability Analyses (Reference 4). The thermal

hydraulic conditions facing the equipment to be evaluated for equipment

survivability was developed using the MAAP4.04 code. Bounding conditions



are provided for the separate containment regions for each of the equipment

survivability Time Frames established for the analysis.

9.2.1. Containment Compartments

The thermal-hydraulic conditions for consideration of equipment

survivability are established for the following containment regions based

on the MAAP4 containment modeling:

* Loop Compartments

* Maintenance Floor at Elevation 107'-2" (CMT Room)

* PXS / Electrical Penetration Area (Intact PXS environment)

* CVS Compartment / Failed PXS environment

" Upper Compartment

* Reactor Cavity

The containment compartments with associated equipment locations are

shown in Table 7.

9.2.2. Selection of Cases Analyzed with MAAP4

The justification for the selection of the cases to generate the bounding

severe accident environments is presented in Section 4.2.4 of

Reference 4. This justification is repeated below.

Several observations that impact the sequence selection are noted with

respect to the AP1000 accident response:

* Based on the results of the AP1000 Level 1 PRA, a direct vessel

injection (DVI) line failure is the dominant initiating event that



contributes to core damage. The DVI line break fails one train of

the passive injection system. Consequently, the random failure of

the one available train of gravity injection leads to core damage.

* For an accident sequence to lead to significant core damage with

a large fraction of cladding oxidation and hydrogen generation (as

required for equipment survivability environments), typically either

the available gravity injection lines fail to open or inadequate ADS

prevents sufficient gravity injection.

* The dominant accident sequences in the PRA result in some

degree of automatic RCS depressurization. The ADS provides in-

vessel hydrogen release pathways to the containment.

" After the initial blowdown, even partial operation of the ADS

system (insufficient for adequate gravity injection) makes accident

sequences behave like a large LOCA sequence since the ADS

stage 4 is comprised of 14" diameter valves that deliver directly to

the loop compartments. Alone, one open ADS-4 valve is not

sufficient for adequate gravity injection, but it will depressurize the

RCS and direct hydrogen to the loop compartments as the path of

least resistance.

* In the event of hydrogen releases through the IRWST, diffusion

flames (sustained hydrogen combustion) at the IRWST vents are

mitigated by design. The IRWST hooded vents along the

containment steel shell are designed to open at an elevated

pressure when needed and close again. The stand-pipe vents

along the steam generator doghouse wall are designed to open at

a lower pressure than the hooded vents at the walls. Once

opened, the stand pipe vents remain open. Therefore, hydrogen



will be preferentially vented through the stand pipes, away from

the containment shell, to prevent the threat of over-temperature

failure of the containment shell by a diffusion flame along the wall.

Non-LOCA severe accident sequences (with ADS failure) tend to

bottle up the reactor coolant and hydrogen in the RCS and

release it relatively slowly through the safety valve to the upper

compartment where the steam condenses on the cooled

containment shell. These high pressure severe accident

sequences challenge containment integrity most significantly by

threatening steam generator tubes. The systems which mitigate

induced SGTR are subjected to harsher environments during

LOCA sequences. Therefore, the non-LOCA sequences are not

considered to produce bounding thermal-hydraulic environments

for equipment survivability in AP1000.

9.2.2.1. Break Sizes and Locations

The RCS break size and location impacts the containment

transient by determining the severity of the initial blowdown, the

timing of ADS actuation and the hydrogen flow pathway to the

containment compartments other than the ADS valves. Breaks

can primarily occur in two locations, the loop compartments and

the PXS/CVS compartments below the 107'-2" floor. Initiating

break cases were chosen to cover a range of break sizes and

locations:

* DVI line break (4" diameter) in one of the PXS

compartments.



* Large break (1 ADS-4 Valve in the hot leg) in the loop

compartment

* Large break (double ended break of the cold leg) in the

loop compartment

* Small break (1" diameter break in the hot leg) in the loop

compartment

9.2.2.2. Automatic Depressurization System

Full or partial ADS actuations are expected even in most severe

accident cases. The ADS system provides a hydrogen release

pathway to the containment. The hydrogen is released as it is

produced in-vessel. It is assumed that the IRWST vent

engineered design features to mitigate the threat from diffusion

flames are sufficient to protect the containment steel shell next

to the IRWST. So partial ADS failures releasing hydrogen only

to the IRWST are not bounding and are not analyzed for the

equipment survivability environment. All cases were run with

full ADS actuation. Large LOCA cases have full

depressurization to the loop compartments by the nature of the

break.

9.2.2.3. Core Reflooding

The cladding oxidation reaction that produces hydrogen is a

function of the availability of unoxidized, overheated cladding

and the availability of steam. Reflooding of a relatively intact,

overheated core will produce additional steam and oxidize more

cladding and produce more hydrogen than a core that is not

reflooded.



Hydrogen generation must be maximized per the acceptance

criteria for the equipment survivability environments in

1OCFR50.34(f). However, it is noted that reflooding is not

guaranteed in all cases. For example, the large LOCA case,

which is initiated by a spurious ADS-4 valve opening, will not

reflood the core since gravity injection is failed and the break is

above the water level in the containment. In the event the core

is not reflooded, less hydrogen is produced.

The DVI line break case will reflood the core if the IRWST

drains through the faulted DVI line into the PXS compartment.

When the compartment is flooded above the DVI line break,

water will drain into the vessel too late to prevent core damage

but just in time to create a lot of hydrogen. If the IRWST does

not drain into the PXS compartment, the core will not reflood.

Since reflooding maximizes the hydrogen production, the DVI

line failure case is assumed to drain the IRWST into the PXS

compartment when the gravity injection line squib valves are

actuated at low-low CMT level.

9.2.2.4. Hydrogen Generation, Combustion and the Hydrogen Igniter

System

The MAAP4 modeling parameters that control in-vessel

hydrogen generation are set to maximize hydrogen production

in all cases. Close to 100% cladding reaction will be generated

for the DVI line break cases, which reflood the core. Cases

which do not reflood the core cannot be expected to generate

100% cladding reaction, but the hydrogen production will be

maximized for the given conditions.



The hydrogen igniter system will impact the environments by

continuously burning hydrogen and generating the burning heat

load to the containment compartments. If the igniters are not

operating and the core is generating a significant amount of

hydrogen, a global deflagration may occur. The global burn will

result in a pressure and temperature spike.

, Cases were run with hydrogen igniters turned on.

" Cases were run without hydrogen igniters and a global

hydrogen burn in the containment was assumed to occur

after the time 100% of the active cladding is oxidized and

the hydrogen becomes well-mixed in the containment

(loop compartments, CMT room and upper

compartment).

9.2.2.5. Cavity Flooding and Reactor Vessel Failure

In-vessel retention of molten core debris (IVR) by external

reactor vessel cooling (ERVC) in the AP1000 is enabled by

depressurization of the reactor coolant system and flooding the

reactor cavity with IRWST water to submerge the vessel in

water. In the bounding case, the core is not reflooded and will

relocate to the lower plenum of the reactor vessel. The lower

head and vessel shell will be cooled by the water on the outside

of the vessel and the vessel will not fail. If the cavity is not

flooded with IRWST water and the core is not reflooded, the

vessel will not be flooded sufficiently for ERVC to prevent vessel

failure from a large mass of debris in the lower plenum. The

vessel will fail and debris will relocate from the lower plenum to

the reactor cavity. Core concrete interaction (CCI) and fuel



coolant interaction (FCI) will be assumed to occur. The AP1000

containment returns condensate to the containment sump in

post-accident conditions. There will always be at least

approximately 3.5 meters of water in the reactor cavity, even

after debris relocation.

* Cases were run with reactor cavity flooding manually

initiated when the core-exit gas temperature exceeds

2000°F to account for instrument uncertainty and

operator action delays.

* A large LOCA case was run with the failure of manual

cavity flooding, subsequent reactor vessel failure and a

non-coolable debris bed in the reactor cavity.

* A large LOCA case was run with the failure of manual

cavity flooding, subsequent reactor vessel failure and a

fuel-coolant interaction in the reactor cavity.

9.2.3.Summary of the Cases Analyzed for the Equipment Survivability

Environment

Based on the above discussion, seven cases were defined to be

analyzed with the MAAP4 code.

The seven cases are:

* Case IGN - DVI Line Break with Hydrogen Igniters

" Case NOIGN - DVI Line Break with Failure of the Hydrogen

Igniters



* Case IVR - DVI Line Break with Igniters and No Vessel

Reflooding

* Case GLOB - Large LOCA with Failure of Accumulators and

Failure of Hydrogen Igniters

* Case SL - Small LOCA in the Hot Leg with Full ADS

* Case CCI - Vessel Failure with Long-Term Core Concrete

Interaction

" Case EVX - Ex-Vessel Fuel Coolant Interaction

The event timing for each case is presented in Table 8. These key

events related to the equipment survivability Time Frames.

The passive residual heat removal heat exchanger (PRHR) is

conservatively assumed to be failed in all these cases. The PRHR

transfers energy to the IRWST water instead of cooling by steam

generators in transient accident sequences. All of these cases are loss

of coolant accidents (LOCAs). Any energy released to the IRWST water

does not go to the containment atmosphere. Therefore, the PRHR is

conservatively assumed to be failed.

9.2.3.1. Case IGN - DVI Line Break with Hydrogen Igniters

Case IGN is a direct vessel injection (DVI) line break into one

passive injection system (PXS) compartment in the

containment. It is conservatively assumed that the break is a

full break of the DVI line. Because of the DVI line break, one

accumulator is unavailable to inject into the RCS. The MAPP4

results are presented in Figure 3 through Figure 7.



9.2.3.2. Case NOIGN - DVI Line Break with Failure of the Hydrogen

Igniters

Case NOIGN is the same as case IGN, except the hydrogen

igniters are assumed to be failed until the core is recovered.

Then at 8 hours, the ignition parameters are turned on to

produce a full global burn. The MAAP4 results are presented in

Figure 8 through Figure 12.

9.2.3.3. Case IVR - DVI Line Break with Igniters and No Vessel

Reflooding

Case IVR is the same as Case IGN except that the gravity

injection valves in the broken DVI line do not open. The IRWST

water does not drain into the PXS compartment and the vessel

does not reflood. The vessel remains dry throughout the

accident. The entire core melts and drains into the lower head

of the reactor vessel. The operator action to drain the IRWST

water into the reactor cavity is successful and the vessel is

externally cooled by water. The vessel does not fail and the

molten core remains in the vessel. Because the vessel does

not reflood, less hydrogen production is expected in this case.

The MAAP4 results are presented in Figure 13 through

Figure 17.

9.2.3.4. Case GLOB - Large LOCA with Failure of Accumulators and

Failure of Hydrogen Igniters

Case GLOB is a design basis-like double-ended cold leg break.

The RCS is emptied and the passive safety systems refill the

vessel and cool the core. In this case, the accumulators are



assumed to be failed. The purpose of the gas-charged

accumulators is to rapidly refill the lower plenum of the reactor

vessel and start cooling the core before the much slower

injecting CMTs and IRWST complete the core cooling. When

the accumulators fail, the core overheats and the CMT and

gravity injection cause significant hydrogen production. The

case assumes minimum ADS (1 ADS-3 and 2 ADS-4 valves

open) and one CMT and one gravity injection line from the

IRWST. The flow rates are minimized to provide water slowly

and maximize the rate of hydrogen production. The igniters are

assumed to be failed. When the hydrogen production reaches

the equivalent of 100% active cladding reaction, a global burn is

assumed to occur. The MAAP4 results are presented in

Figure 18 through Figure 22.

9.2.3.5. Case SL - Small LOCA in the Hot Leg with Full ADS

Case SL represents a small LOCA in the hot leg with full ADS.

The sequence progresses to a severe accident because gravity

injection fails. Hydrogen production is maximized and the

igniters are operational. The break is assumed to be a 1"

diameter break at the hot leg centerline. The MAAP4 results

are presented in Figure 23 through Figure 27.

9.2.3.6. Case CCI - Vessel Failure with Long-Term Core Concrete

Interaction

Case CCI models the case in which the vessel is not reflooded,

manual cavity flooding fails and the fuel melts into the reactor

vessel lower plenum and fails the vessel. The molten debris is

released to the reactor cavity and forms a non-coolable debris



bed resulting in core-concrete interaction (CCI). The in-vessel

hydrogen generation is not maximized so that the ex-vessel

hydrogen generation is maximized.

Because the AP1000 is designed to drain the water in the

containment to the reactor cavity, there will always be water at

least approximately 3.5 meters of water in the cavity after an

accident, even if the IRWST water is not drained into the cavity.

Therefore, there is always water to cool ex-vessel debris. CCI

can only occur if the debris bed forms a non-coolable geometry.

The water cover over the debris bed will mitigate the

temperature of hot gases released from the CCI reaction. The

MAAP4 results are presented in Figure 28 through Figure 32.

9.2.3.7. Case EVX - Ex-Vessel Fuel Coolant Interaction

Case EVX models the case in which the vessel is not reflooded.

Manual cavity flooding fails and the fuel melts into the reactor

vessel lower plenum and fails the vessel. The debris is

released from the reactor vessel and interacts with the water in

the cavity. During the quench of the ex-vessel debris, there will

be a pressure and temperature spike in the containment. The

MAAP4 results are presented in Figure 33 through Figure 37.

9.2.4. Bounding Environments

The bounding environments were generated by envelopment of all

seven cases for Time Frames 1, 2, and 3. As shown in Table 8, the

beginning of Time Frame 2 (Rapid Cladding Oxidation / H2 Generation

Begins) and Time Frame 3 (Vessel Failure) occur at different times

depending on the particular cases, and only cases CCI and EVX



proceeded to Time Frame 3. In order to develop the thermal-hydraulic

envelopes, the time data for the various cases were adjusted so that

Time Frame 2 begins at 3,325 seconds and Time Frame 3 begins at

15,000 seconds with the envelope ending at 86,400 seconds. The

enveloped MAAP4 pressure and temperature bounding environments for

various compartment regions are shown in Figure 38 through Figure 44.

10. Assessment of Equipment Survivability

10.1. Approach to Equipment Survivability

Section D.8.1 of Reference 1 states that the approach to a systematic

evaluation of equipment and instrumentation to address its survivability for

intervening in a severe accident is by identification of the equipment type,

equipment location, survival time required, and the use of design basis

event qualification requirements and severe environment experimental

data.

10.2. As-Designed Assessment

The as-designed assessment of equipment survivability is contained in

Section D.8 of Reference 1. This approach was reviewed and accepted by

the NRC (Reference 2, Section 19.2.3.3.7.3, Basis for Acceptability) as

stated below.

"The staff performed this evaluation and concludes that the equipment and

instrumentation identified by the applicant in DCD Tier 2, Tables 19D-3

throughl9D-5, and the applicable environments described in Appendix D

to the AP1000 PRA supporting document, meet the above guidance of

SECY-93-087 and 10 CFR 50.34(f), as delineated in Section 19.2.3.3.7 of



this report. The environmental qualification ITAAC and completion of a

COL action item provide reasonable assurance that the equipment and

instrumentation identified in this section will operate in the severe accident

environment for which they are intended, and over the time span for which

they are needed. Specifically, the COL applicant referencing the AP1000

certified design will perform a thermal response assessment of the as-built

equipment used to mitigate severe accidents to provide additional

assurance that this equipment can perform its severe accident functions

during environmental conditions resulting from hydrogen burns. This

assessment is COL Action Item 19.2.3.3.7.3-1."

10.3. As-Built Assessment

Thermal lag assessment of the as-built equipment used to mitigate severe

accidents (hydrogen igniters and containment penetrations) will be

performed prior to fuel load. The purpose of the assessment is to provide

additional assurance that this equipment can perform its severe accident

functions during environmental conditions resulting from hydrogen burns.



11. Conclusion

This report examined the AP1000 severe accident design features and the

systems and equipment required to mitigate the accident parameters. Based on

the examination, lists of systems and equipment inside and outside containment

have been generated. Accident progression was also evaluated and identified

to progress in four Time Frames. Actions required to mitigate the consequences

of severe accidents were identified for each Time Frame and lists of equipment

required to successfully complete the required actions were also identified. The

equipment locations, floors, rooms and buildings were also identified to aid in

performing the equipment assessment. In parallel with this evaluation, an

analysis of the severe accident scenarios and resultant severe accident

environmental parameters was conducted using MAAP4, Reference 4. In

addition, the radiation doses associated with the severe accident were also

computed for inside and outside containment. The results of the analyses are

documented in References 4 and 3, respectively.

Assessment of equipment in severe accident environment was performed for the

equipment in Reference 1 and accepted by NRC in Reference 2.

The only remaining portion of this study is to perform the assessment. The

assessment will be conducted as follows:

1. Completion and documentation of the environmental qualification ITAAC

2. The thermal lag assessment of the as-built equipment required to mitigate

severe accident (hydrogen igniters and containment penetrations) that has

not been tested to severe accident conditions will be performed prior to fuel

load in accordance with Reference 6.



12. References

1. AP1000 Probabilistic Risk Assessment, Appendix D Equipment Survivability

Assessment, APP-GW-GL-022, Rev 1.

2. Final Safety Evaluation Report Related to Certification of the AP1000

Standard Design, Chapter 19 Severe Accidents, NUREG-1793,

September 2004.

3. AP1000 - Equipment Qualification (EQ) and Severe Accident Radiation

Dose, APP-SSAR-GSC-507, Rev. 3, CN-REA-02-16, Rev. 3.

4. Thermal Hydraulic Environments for AP1000 Equipment Survivability

Analyses, APP-GW-GER-010, Rev. 0 / CN-CRA-02-47, Rev. 0.

5. Large-Scale Hydrogen Burn Equipment Experiments, EPRI NP-4354,

Final Report 1985.

6. AP1000 As-Built COL Information Items, APP-GW-GLR-021, Rev. 0.

7. Evolutionary Light Water Reactor (LWR) Certification Issues and Their

Relationship to Current Regulatory Requirements, SECY-90-016,

January 12, 1990.

8. Policy, Technical, and Licensing Issues Pertaining to Evolutionary and

Advanced Light Water Reactor (ALWR) Designs, SECY-93-087,

April 2,1993.

9. Framework for AP1000 Severe Accident Management Guidance,

APP-GW-GL-027, Rev. 0, WCAP-16335, Rev. 0.

10. AP1000 DCD Chapter 19 Appendix D Markup, APP-GW-VPC-'020, Rev.0.

11. AP1000 Severe Accident Management Guidelines, Volume 1,

APP-GW-GJR-400, Rev. A.



12. Fire Area Drawing Nuclear

APP-1000-AF-902 Rev. 3,

APP-1020-AF-001 Rev. 3,

APP-1030-AF-001 Rev. 3,

APP-1050-AF-001 Rev. 2,

APP-1060-AF-001 Rev. 2.

Island, APP-1000-AF-901

APP-1010-AF-001

APP-1020-AF-002

APP-1040-AF-001

APP-1050-AF-002 Rev.

Rev.

Rev.

Rev.

Rev.

2

2,

2,

3,

2,

and

13. AP1000 Equipment & Component

APP-GW-VPD-001, Rev. A.

Qualification Datasheet,

14. AP1000 Hydrogen Igniter Locations, APP-GW-GLW-003, Rev. 0.

15. Accident Source Terms for Light-Water Nuclear Power Plants - Final Report,

NUREG-1465, February 1995.



Table 1: Definition of Equipment Survivability Time Frames

DEFINITION OF EQUIPMENT SURVIVABILITY TIME FRAMES

(Taken from Reference 1)

Time Frame Beginning Ending Time CommentsTime

TO Accident safe, stable stateinitiation or

core uncovery

T1 Core uncovery controlled, stable * Core uncovery and heatupstateorrapid claddingoxidation

T2 Rapid cladding controlled, stable 0 In-vessel core melting and relocationoxidation state - Entry into SAMG

orvessel failure

T3 Vessel failure controlled, stable 0 Ex-vessel core relocationstateorcontainmentfailure



Table 2: AP1000 High Level Actions relative to Accident Management Goals

AP1 000 HIGH LEVEL ACTIONS RELATIVE TO ACCIDENT MANAGEMENT GOALS

(Taken from Reference 10)

Goal Element High Level Action note 1

Controlled, stable core water inventory in RCS * inject into RCS (Al)* depressurize RCS (A4)

water inventory in containment * inject into containment (A2)

heat transfer to IRWST * initiate PRHR (A3)

heat transfer to SGs * inject into RCS (Al)• inject into SGs (A3)

heat transfer to containment • inject into RCS (Al)* inject into containment (A2)• depressurize RCS (A4)* initiate PRHR (A3)

Controlled, stable heat transfer from containment * depressurize containment (A6)containment * vent containment (A7)

* water on outside containment(A6)

isolation of containment * inject into SGs (A3)* depressurize RCS (A4)

hydrogen prevention/control * burn hydrogen (A8)• pressurize containment (A7)• depressurize RCS (A4)* inject into containment (A2)* vent containment (A7)* water on outside containment

(A6)

core concrete interaction prevention * inject into containment (A2)

high pressure melt ejection * inject into containment (A2)prevention • depressurize RCS (A4)

creep rupture prevention * depressurize RCS (A4)• inject into SGs (A3)

containment vacuum prevention • pressurize containment (A7)

Terminate fission product isolation of containment * inject into SGs (A3)release • depressurize RCS (A4)

reduce fission product inventory * inject into containment (A2)• depressurize RCS (A4)

reduce fission product driving force * depressurize containment (A6)* water on outside containment

(A6)

Notel" Al through A10 are high level actions and are defined in Table 3



Table 3: Equipment and Instrumentation used for the High Level ActionsEQUIPMENT AND INSTRUMENTATION USED IN EACH TIME FRAME FOR THE HIGH LEVEL ACTIONS

(Sheet I of 2)

Action Description Time Equipment InstrumentationFrame

Al a. Inject into RCS at TO, T1 • PXS - CMT * Core-exit thermocouplesoperating pressure • CVS e RCS pressure

b. Inject into RCS at TI • PXS - ACC e RCS RTDsreduced pressure • Cvs * Cvs flow

• RNS • RNSflowc. Inject into RCS at • PXS - IRWST * IRWST water level

containment • Cvspressure • RNS

T2 • Cvs * RCS pressure* RNS * RCS RTDs

• Containment pressure* CVS flow• RNS flow

A2 a. Inject into T1 • PXS - IRWST drains * Core-exit thermocouplescontainment from e Containment water levelIRWST e IRWST water level

b. Inject into T2, T3 • Containment spray * Containment water levelcontainment • Overflow IRWST via RNS

A3 a. Decay heat removal TO, TI * PXS - PRHR HX * IRWST water level- PRHR • IRWST water

temperature* Core-exit thermocouples• RCS RTDs

b. Decay heat removal TO, T1 , T2 • MFW • SG wide range water-Inject into SGs • SFW level

• Core-exit thermocouples• RCS RTDs• Steamline pressure

A4 a. Depressurize RCS T1 ° Auxiliary pressurizer spray & RCS pressure0 ADS stage 1, 2, and 3 * IRWST water level• PRHR HX * IRWST water• via SGs temperature

* Steamline pressureT2 * Reactor vessel head vent * RCS Pressure

b. Depressurize RCS T1 • ADS stage 4 * RCS pressure-ADS stage 4 • IRWST water level

* IRWST watertemperature

• Steamline pressureA5 Depressurize SGs T1 * SG PORV a Steamline pressure

0 Main steam bypass * SG wide range waterlevel

* RCS pressure



Table 3: Equipment and Instrumentation used for the High Level Actions

(Continued)EQUIPMENT AND INSTRUMENTATION USED IN EACH TIME FRAME FOR THE HIGH LEVEL ACTIONS

(Sheet 2 of 2)Action Description Time Equipment Instrumentation

FrameA6 Containment heat TI * PCS water * Containment pressure

removal * External water e PCS flowrate* PCS tank level

T2, T3 9 PCS water * PCS flowrate* Extemal water * PCS tank levele Containment spray a Containment pressure

* Containment water levelA7 a. Containment T1 9 Containment isolation * Containment isolation

isolation system system valve positione Containment shell * Containment pressure9 Containment penetrations

T2, T3 9 Containment shell * Containment pressure* Containment penetrations * Containment temperature

(for Time Frame 3 only)b. Containment T3 9 RNS hot leg suction MOVs 9 Containment pressure

venting e SFP water levelA8 Hydrogen control T1 * Igniters e Containment hydrogen

monitors* Containment pressure* Containment atmosphere

sampling functionT2 0 Containment hydrogen

monitors* Containment atmosphere

sampling function* Containment pressure

T3 e Containment atmospheresampling functionContainment pressure

A9 Control fission T2, T3 * Containment spray e Containment water levelproduct releases

A10 Accident monitoring TO, T1, T2, * Cables * Containment pressureT3 * Containment hydrogen

monitors* Containment water level* Containment radiation* Containment atmosphere

sampling function* Containment temperature

S SG radiation monitors" Core-exit thermocouples

(no longer needed in TimeFrame 3)

" RCS pressure (no longerneeded in Time Frame 3)

o Auxiliary building radiation



Table 4: Equipment Location in Containment

Location Room Room Room Description Reference Drawing Reference Drawing

Elevation (SECTION VIEWS) (PLAN VIEWS)

C-A4 11104 66 ft 6 in RCDT Room APP-1000-AF-901 APP-1010-AF-001C-A5 11105 66 ft 6 in Reactor Vessel Cavity APP-1 000-AF-901, -902 APP-1010-AF-001

C-B1 11201 82 ft 6 in SG Compartment 1 APP-1000-AF-902 APP-1020-AF-001C-B2 11202 82 ft 6 in SG Compartment 2 APP-1000-AF-902 APP-1020-AF-001C-B4 11204 82 ft 6 in Vertical Access APP-1 000-AF-901, -902 APP-1020-AF-001

C-B6 11206 82 ft 6 in PXS Valve/Accumulator Room A APP-1020-AF-001C-B7 11207 82 ft 6 in PXS Valve/Accumulator Room B APP-1020-AF-001C-B8 11208 96 ft 6 in RNS Valve Room APP-1000-AF-902 APP-1 020-AF-002C-B9 11209 82 ft 6 in North CVS Equipment Room APP-1000-AF-901 APP-1020-AF-001

C-CO 11300 107 ft 2 in Maintenance Floor APP-1 000-AF-901, -902 APP-1 030-AF-001C-C3 11303 107 ft 2 in Lower Pressurizer Compartment APP-1 030-AF-001C-C4 11304 107 ft 2 in SG I Access Room APP-1030-AF-001C-C5 11305 107 ft 2 in IRWST APP-1 000-AF-902 APP-1030-AF-001C-C6 11500 107 ft 2 in Electrical Penetration (Open to APP-1000-AF-901

11500)

C-Do 11400 117 ft 6 in Maintenance Floor Mezzanine APP-1 000-AF-901, -902 APP-1040-AF-001(CMT)

C-D1 11401 117 ft 6 in SG 1 Tubesheet Area APP-1000-AF-902 APP-1040-AF-001C-D2 11402 117 ft 6 in SG 2 Tubesheet Area APP-1000-AF-902 APP-1040-AF-001C-D3 11403 117 ft 6 in Pressurizer Spray Valve Room APP-1040-AF-001

C-EO 11500 135 ft 3 in Operating Deck APP-1000-AF-901, -902 APP-1050-AF-001C-El 11501 135 ft 3 in Loop Compartment 01 APP-1000-AF-902 APP-1050-AF-001C-E2 11502 135 ft 3 in Loop Compartment 02 APP-1000-AF-902 APP-1050-AF-001C-E3 11503 135 ft 3 in Pressurizer Compartment APP-1000-AF-901, -902 APP-1050-AF-001

C-E4 11504 135 ft 3 in Refueling Cavity APP-1000-AF-901 APP-1050-AF-001

C-F1 11601 153 ft 0 in SG1 Feed Nozzle Area APP-1000-AF-901, -902 APP-1050-AF-002C-F2 11602 153 ft 0 in SG2 Feed Nozzle Area APP-1000-AF-902 APP-1050-AF-002C-F3 11603 160 ft 6in Lower ADS Valve Area APP-1000-AF-901, -902 APP-1060-AF-001

C-G1 11701 160 ft 6 in SG1 Upper Manway Area APP-1000-AF-901, -902 APP-1060-AF-001C-G2 11702 160 ft 6 in SG2 Upper Manway Area APP-1000-AF-902 APP-1060-AF-001C-G3 11703 180 ft 0 in Upper ADS Valve Area APP-1000-AF-901, -902

C-H0 11500 233 ft 0 in Containment Med Region APP-1 000-AF-901, -902

C-H1 11500 258 ft 0 in Containment Upper Region APP-1000-AF-901, -902



Table 5: Equipment, Action Time Frame, and Equipment Location Summary

Equip Description Time Frame - Time Frame - BuildingSectionNo Action Action Location

Equipment Located in Containment

8.1.1 Differential Pressure and Pressure Transmitters

8.1.1.1 PXS - IRWST Water Level TO,T1-AI,A2,A3,A4 C-CO

8.1.1.2 RCS Pressure TO,T1-A1,A4,A5,A10 T2-A1,A4,A1 0 C-B4,C-B6

8.1.1.3 SG Wide Range Water Level TO,T1-A3,A5 T2-A3 C-B1,C-COT2-A1 ,T2,T3-

8.1.1.4 Containment Pressure TO,T1-A6,A7,A8, AO0 A6,A7,A8,A1O C-DO8.1.2 Core-exit Temperature TO,T1-A1 ,A2,A3,A1O T2-A3,A10 C-DO,C-EO

8.1.3 Resistance Temperature Detectors (RTD)

8.1.3.1 Hot Leg RTDs TO,T1-A1,A3 T2-A1,A3 C-B1,C-B28.1.3.2 Cold Leg RTDs TO,T1-A1,A3 T2-A1,A3 C-BI,C-B28.1.3.3 Containment Temperature TO,T1-A1O T3-A7,T2,T3-AI0 C-EQ

8.1.3.4 IRWST Water Temperature TO,T1-A3,T1-A4 C-CO

8.1.4 Hydrogen Monitors TO,T1-A8,A1O T2-A8,T2,T3-A10 C-H1

8.1.5 PXS Radiation Monitors TO,T1-A1O T2,T3-A10 C-G3

8.1.6 Solenoid Valves - Vent Air-Operated Valves (AOVs)

8.1.6.1 PXS Core Makeup Tank AOVs TO,T1-Al C-B6,C-B7

8.1.6.2 PXS PRHR AOVs TO,T1-A3,A4 C-COC-B8,C-CO,C-D0,

8.1.6.3 Containment Isolation AOVs T1-A7 C-EQ

8.1.6.4 CVS RCS Boundary AOVs TO,T1-A1 T2-A1 ,A4 C-C48.1.6.5 Containment Spray AOVs T2,T3-A2,A6,A98.1.6.6 Containment Atmosphere Sampling Func. TO,T1 -A8, Al 0 T2,T3-A8,A1 0 C-B1 ,C-B6,C-DO

8.1.6.7 Reactor Vessel Head Vent AOVs T2-A4 C-A5

8.1.7 Motor-Operated Valves (MOVs)8.1.7.1 PXS Accumulator MOVs T1-Al C-B6,C-B7

8.1.7.2 PXS Core Makeup Tank MOVs TO,TI-A1 C-DO

8.1.7.3 PXS Recirculation MOVs T1-A2 C-B6,C-B7C-F3,C-G3,C-DI,

8.1.7.4 ADS Stages 1,2, 3, & 4 MOVs T1-A4 C-D2C-B6,C-B8,C-CO,

8.1.7.5 Containment Isolation MOVs T1-A7 C-DO8.1.7.6 CVS Charging and Injection MOVs TO,T1-A1 T2-A1 C-CO8.1.7.7 RNS IRWST MOVs T1-A1 T2,T3-A2 C-B6,C-B8

8.1.7.8 PXS PRHR MOV TO,Tl-A3, A4 C-EQ

8.1.7.9 RNS HL Suction to Spent Fuel Pool T3-A7 C-B8

8.1.8 Squib Valves8.1.8.1 IRWST Injection T1-A2 C-B6,C-B78.1.8.2 PXS Containment Recirculation T1-A2 C-B6,C-B7

8.1.8.3 Fourth Stage ADS T1-A4 C-D1 ,C-D2



Table 5: Equipment, Action Time Frame, and Equipment Location Summary

(Continued)quip Description Time Frame - Time Frame - Buildingectiono Action Action Location

C-B6,C-B8,C-CO,

8.1.9 Valve Position Sensors T1-A7 C-DO,C-EO

8.1.10 Hydrogen Igniters T1-A8 T2,T3-A8 Note 1

8.1.11 Electrical Cont. Penetration Assemblies T1-A7 T2,T3-A7 C-CO,C-DO,C-C6

8.1.12 Cables T0,T1-A10 T2,T3-A10 Note 2T2,T3-

8.1.13 PXS Containment Water Level T0,T1-A2,A10 A2,A6,A9,A10 C-A4,C-A5

Equipment Located Outside Containment

8.2.1 Steamline Radiation Monitors T0,T1-A10 T2,T3-A10 A-D4,A-D6Transmitters for Monitoring Steamline

8.2.2 Pressure T1-A3,A5 T2-A3 A-E4,A-E6Passive Containment Cooling System

8.2.3 Flow and Tank Level T1-A6 T2,T3-A6 A-H1Containment Atmosphere Sampling

8:2.4 Function T0,T1-A8,A10 T2,T3-A8,A10 A-D48.2.5 Makeup Pumps and Flow Measurement T0,T1-A1 T2-A1 Aux Bldg8.2.6 RNS Pumps and Flow Measurement T0,T1 -Al T2-A1,T2,T3-A2 A-F2,Aux Bldg

MOV and Manual Valves from RNS HL A-B2,A-B88.2.7 Suction Lines to the Spent Fuel Pool T3-A7 Fuel Building

RNS MOV for Injection from Cask Loading8.2.8 Pit to RCS T2-A1,T2,T3-A2 A-B68.2.9 MFW Pumps and Valves T0,T1-A3 T2-A3 A-D4,A-D6,Aux Bldg

8.2.10 SFW Pumps and Valves TO,TI-A3 T2-A3 A-D4,A-D6,Aux BldgFire Water, Fire Pumps, Valves and FlowMeasurement used to provideContainment Spray and Containment

8.2.11 Cooling T2,T3-A2,A6,A9 Turbine Bldg, YardSG PORVs and Steam Bypass Valves for

8.2.12 Depressurization TI-A4,A5 A-D4,A-D6,A-E4,A-E6PCS Pumps, Valves, Fire Water Pumps

8.2.13 and Valves for Containment Heat Removal T1-A6 T2,T3-A6 A-C6,A-H1

8.2.14 Containment Isolation Valves T1-A7 T2,T3-A7 Note 38.2.15 Auxiliary Building Radiation Monitor T2,T3-A10 A-D1

Notes:1. Igniters are located in the following rooms: C-B4, C-B6, C-B7, C-B8, C-B9, C-C5, C-DO, C-D1, C-D2,

C-E0, C-El, C-E2, C-E3, C-E4, C-F3, C-G1, C-G2, C-G3, and C-H10.2. Cables are located in most rooms inside containment. A list of all rooms is included in the first

column in Table 4.3. Containment isolation valves are located in room A-B4, A-B6, A-B8, A-C6, A-D4, A-D5, A-D6, A-D7,

A-D9, A-E4 and A-E6.



Table 6a: List of Equipment Located Outside Containment (TO through T3)

(Not Subjected to Severe Accident Environment, No Assessment Required)

Sheet 1 of 5Ecuipment. Action Time Frame, and Equipment Location

Section and Description Time Frame 0,1 Time Frame 2,3 BuildingEquip Tag No I

IAction Action Location8.2.0 Equipment Located Outside Containment8.2.1 Steamline Radiation Monitors TO,TI -Al T2,T3-AI0 A-D4,A-D6SGS-JE-RE026 SG 1 Steamline Radiation Detector A-D6SGS-JE-RE027 SG 2 Steamline Radiation Detector A-D4

8.2.2 Transmitters for Monitoring TI-A3,A5 T2-A3 A-E4,A-E6Steamline Pressure

SGS-JE-PT031 SG 1 Steamline Pressure Transmitter B A-E6SGS-JE-PT033 SG 1 Steamline Pressure Transmitter D A-E6SGS-JE-PT035 SG 2 Steamline Pressure Transmitter B A-E4SGS-JE-PT037 SG 2 Steamline Pressure Transmitter D A-E4

8.2.3 Passive Containment Cooling System TI-A6 T2,T3-A6 A-HIFlow and Tank Level

PCS-JE-FT001 PCS Flow In Lines 6" Above Tank A-H1PCS-JE-FT002 PCS Flow In Lines 7.2' Above Tank A-H1PCS-JE-FT003 PCS Flow In Lines 22.2' Above Tank A-H1IPCS-JE-FT004 PCS Flow In Lines 14.7' Above Tank A-H1PCS-JE-LT010 PCCWST Water Level Tap 1 A-H1

TransmitterPCS-JE-LT01 1 PCCWST Water Level Tap 2 A-HI

Transmitter

8.2.4 Containment Atmosphere Sampling TO,TI-A8,AIO T2,T3-A8,AI0 A-D4Function

PSS-PL-V046 Air Sample Line Cont. Isolation ORC A-D4

8.2.5 Makeup Pumps and Flow TO,TI-Al T2-AI Aux BldgMeasurement

CVS-MP-01A CVS Makeup Pump A Aux BldgCVS-MP-01B CVS Makeup Pump B Aux BldgCVS-PL-V157 Makeup Pump Discharge Valve Aux BldgCVS-FI-025 CVS Makeup Flow Aux Bldg

8.2.6 RNS Pumps and Flow Measurement TO,TI -Al T2-A1,T2,T3-A2 A-F2,Aux Bldg

RNS-MP-01A Residual Heat Removal Pump A A-F2RNS-MP-01B Residual Heat Removal Pump B A-F2RNS-FT-001A RNS Flow Sensor Pump A Aux BldgRNS-FT-001 B RNS Flow Sensor Pump B _Aux Bldg





Sheet 2 of 5 (Continued)

Eouinment. Action Time Frame. and Eouioment Location

Section and Description Time Frames 0,1 Time Frame 2,3 BuildingEquip Tag No

Action Action Location8.2.7 MOV and Manual Valves from RNS HL T3-A7 A-B2,A-B8,

Suction Lines to the Spent Fuel Pool Fuel BuildingRNS-PL-V022 RNS Suction Header Isolation. -MOV A-B8RNS-PL-VO06A RNS HX A Outlet Flow Control A-B2

RNS-PL-VO06B RNS HX B Outlet Flow Control A-B2RNS-PL-V053 RNS Discharge to SFP Isolation A-B8SFS-JE-LT019 Spent Fuel Pool Level Sensor Fuel Building

8.2.8 RNS MOV for Injection from Cask T2-AI,T2,T3-A2 A-B6Loading Pit to RCS

RNS-PL-V055 RNS Suction from Cask Loading Pit A-B6

8.2.9 MFW Pumps and Values T0,T1-A3 T2-A3 A-D4,A-D6,Aux Bldg

FWS-MP-01A Main Feedwater Pump A A-D6FWS-MP-01B Main Feedwater Pump B A-D4FWS-MP-01C Main Feedwater Pump C iA-D6

FWS-MP-02A Main Feedwater Pump A A-D4FWS-MP-02B Main Feedwater Pump B Aux BldgFWS-MP-02C Main Feedwater Pump C Aux Bldg

FWS-PL-V004A MFW Pump A Discharge MOV Valve Aux BldgFWS-PL-V004B MFW Pump B Discharge MOV Valve Aux Bldg

SGS-PL-V057A SG 1 Main Feedwater Isolation Aux Bldg

SGS-PL-V057B SG 2 Main Feedwater Isolation Aux Bldg

SGS-PL-V250A SG 1 Main Feedwater Control Aux Bldg

SGS-PL-V250B SG 2 Main Feedwater Control Aux Bldg

8.2.10 SFW Pumps and Valves T0,TI-A3 T2-A3 A-D4,A-D6,Aux Bldg

FWS-MP-03A Startup Feedwater Pump A A-D6FWS-MP-03B Startup Feedwater Pump B A-D4FWS-PL-VO13A SFW Pump A Discharge MOV Valve Aux BldgFWS-PL-VO13B SFW Pump B Discharge MOV Valve Aux BldgSGS-PL-V067A SG 1 Startup Feedwater Isolation Aux BldgSGS-PL-V067B SG 2 Startup Feedwater Isolation Aux BldgSGS-PL-V255A SG 1 Startup Feedwater Control Aux BldgSGS-PL-V255B SG 2 Startup Feedwater Control Aux Bldg





Sheet 3 of 5 (Continued)Equipment, Action Time Frame, and Equipment LocationSection and Description Time Frames 0,1 Time Frame 2,3 BuildingEquip Tag No

Action Action Location8.2.11 Fire Water, Pumps, Valves and Flow T2,T3-A2,A6,A9 Turbine Bldg,

used to provide Containment Spray Yardand Cooling

FPS-MP-01A Motor-Driven Fire Pump Turbine BldgFPS-MP-01B Diesel-Driven Fire Pump YardFPS-MP-02 Jockey Pump Turbine BldgFPS-PL-VO10A Fire Water Flow Measurement Turbine BldgFPS-PL-V010B Fire Water Flow Measurement Yard

8.2.12 SG PORVs and Steam Bypass Valves T1-A4,A5 A-E4,A-E6,A-D4,for Depressurization A-D6

SGS-PL-V233A SG 1 Power Operated Relief Valve A-E6SGS-PL-V233B SG 2 Power Operated Relief Valve A-E4SGS-PL-240A SG1 MSIV Bypass Isolation A-D6SGS-PL-240B SG2 MSIV Bypass Isolation A-D4MSS-PL-VO01 Main Steam Bypass Valve Turbine BldgMSS-PL-V002 Main Steam Bypass Valve Turbine BldgMSS-PL-V003 Main Steam Bypass Valve Turbine BldgMSS-PL-V004 Main Steam Bypass Valve Turbine BldgMSS-PL-V005 Main Steam Bypass Valve Turbine BldgMSS-PL-V006 Main Steam Bypass Valve Turbine Bldg

8.2.13 PCS Pumps, PCS Valves and Fire T1-A6 T2,T3-A6 A-C6, A-H1Water Pumpsand Valves for Containment HeatRemoval

PCS-MP-01A Recirculation Pump A A-C6PCS-MP-01 B Recirculation Pump B A-C6PCS-PL-VO01A PCCWST Discharge Isolation AOV A A-H1PCS-PL-VO01 B PCCWST Discharge Isolation AOV B A-H1PCS-PL-VO01C PCCWST Discharge Isolation MOV C A-H1PCS-PL-VO02A PCCWST Discharge Isolation MOV A A-H1PCS-PL-VO02B PCCWST Discharge Isolation MOV B A-H1PCS-PL-VO02C PCCWST Discharge Isolation MOV C A-H1

8.2.14 Containment Isolation Valves T1-A7 T2,T3-A7 See belowCAS-PL-V014 Instrument Air Supply AOV A-D5CVS-PL-V047 Letdown Containment Isolation AOV A-B4CVS-PL-V092 Hydrogen Add Containment Isolation A-C6PSS-PL-V01 1 Liquid Sample Line Cont. Isolation AOV A-D4PSS-PL-V023 Sample Return Line Cont. Isolation AOV A-D4PSS-PL-V046 Air Sample Line Cont. Isolation AOV A-D4PXS-PL-V042 Nitrogen Supply Cont. Isolation AOV -------- A-D5






Action Action LocationSGS-PL-V040A SG I Main Steam Line Isolation T1-A7 T2,T3-A7 A-E6SGS-PL-V040B SG 2 Main Steam Line Isolation A-E4SGS-PL-V030A SG 1 Main Steam Safety Valve 1 A-E6SGS-PL-V030B SG 2 Main Steam Safety Valve 1 A-E4SGS-PL-V031A SG 1 Main Steam Safety Valve 2 A-E6SGS-PL-V031 B SG 2 Main Steam Safety Valve 2 A-E4SGS-PL-V032A SG 1 Main Steam Safety Valve 3 A-E6SGS-PL-V032B SG 2 Main Steam Safety Valve 3 A-E4SGS-PL-V033A SG 1 Main Steam Safety Valve 4 A-E6SGS-PL-V033B SG 2 Main Steam Safety Valve 4 A-E4SGS-PL-V034A SG 1 Main Steam Safety Valve 5 A-E6SGS-PL-V034B SG 2 Main Steam Safety Valve 5 A-E4SGS-PL-V035A SG 1 Main Steam Safety Valve 6 A-E6SGS-PL-V035B SG 2 Main Steam Safety Valve 6 A-E4SGS-PL-V036A SG 1 Steam Line Condenser Drain A-D6

IsolationSGS-PL-V036B SG 2 Steam Line Condenser Drain A-D4

IsolationSGS-PL-V057A SG 1 Main Feedwater Isolation A-D6SGS-PL-V057B SG 2 Main Feedwater Isolation A-D4SGS-PL-V074A SG 1 Blowdown Isolation A-C6SGS-PL-V074B SG 2 Blowdown Isolation A-C6SGS-PL-V240A SG 1 MSIV Bypass Isolation A-D6SGS-PL-V240B SG 2 MSIV Bypass Isolation A-D4VFS-PL-V003 Containment Purge Inlet - AOV A-D7VFS-PL-VO10 Containment Purge Discharge - AOV A-D9VWS-PL-V058 Fan Coolers Supply Cont. Isolation - A-D5

AOVVWS-PL-V086 Fan Coolers Return Cont. Isolation - A-D5

AOVWLS-PL-V057 Sump Discharge Cont. Isolation AOV A-B8WLS-PL-V068 RCDT Gas Outlet Cont. Isolation AOV A-B8CCS-PL-V200 CCS Cont. Isolation - Inlet Line MOV A-D5CCS-PL-V208 CCS Cont. Isolation -Outlet Line MOV A-D5CVS-PL-V090 Makeup Line Cont. Isolation - MOV A-B4






Action Action LocationRNS-PL-V01 1 RNS Discharge Cont. Isolation - MOV T1-A7 T2,T3-A7 A-B6RNS-PL-V022 RNS Suction Header Cont. Isolation. A-B6

MOVSFS-PL-V035 SFS Suction Line Cont. Isolation A-B4SFS-PL-V038 SFS Discharge. Line Cont. Isolation A-D4SGS-PL-V027A SG 1 PORV Block Valve A-E6SGS-PL-V027B SG 2 PORV Block Valve A-E4SGS-PL-V067A SG 1 Startup Feedwater Isolation A-D6SGS-PL-V067B SG 2 Startup Feedwater Isolation A-D4

8.2.15 Auxiliary Building Radiation Monitor T2,T3-A10 A-DIVBS-JE-RE001A MCR Supply Duct Radiation Detector A A-D1VBS-JE-RE001B MCR Supply Duct Radiation Detector B A-D1



Table 6b: List of Equipment Located Inside Containment (TO and T1)

(Subjected to Severe Accident Environment, Assessment Required)

Sheet 1 of 8

Equipment, Action Time Frame, and Equipment LocationSection and Description Time Frames 0,1 BuildingEquip Tag No

Action Location8.1. Equipment Located in Containment8.1.1 Differential Pressure and Pressure Transmitters8.1.1.1 PXS - IRWST Water Level T0,T1-A1,A2,A3,A4,A10 C-COPXS-JE-LT045 IRWST Level Transmitter C-COPXS-JE-LT046 IRWST Level Transmitter C-COPXS-JE-LT047 IRWST Level Transmitter C-COPXS-JE-LT048 IRWST Level Transmitter C-CO

8.1.1.2 RCS Pressure T0,T1-A1,A4,A5,A10 C-B4,C-B6RCS-JE-PT140A RCS Wide Range Pressure Trans. A C-14RCS-JE-PT140C RCS Wide Range Pressure Trans. C C-14RCS-JE-PT140B RCS Wide Range Pressure Trans. B C-B6RCS-JE-PT140D RCS Wide Range Pressure Trans. D C-B6

8.1.1.3 SG Wide Range Water Level TO,TI-A3,A5 C-BI,C-COSGS-JE-LT012 SG 1 Wide Range Level Transmitter C-B1SGS-JE-LT016 SG 1 Wide Range Level Transmitter C-B1SGS-JE-LT01 1 SG 1 Wide Range Level Transmitter C-COSGS-JE-LT01 5 SG 1 Wide Range Level Transmitter C-COSGS-JE-LT013 SG 2 Wide Range Level Transmitter C-COSGS-JE-LT014 SG 2 Wide Range Level Transmitter C-COSGS-JE-LT017 SG 2 Wide Range Level Transmitter C-COSGS-JE-LT018 SG 2 Wide Range Level Transmitter C-CO

8.1.1.4 Containment Pressure T0,T1-A6,A7,A8,A10 C-D0PCS-JE-PT012 Extended Range Cont. Pressure 1 C-DOPCS-JE-PT013 Extended Range Cont. Pressure 2 C-DOPCS-JE-PT014 Extended Range Cont. Pressure 3 C-DO

8.1.2 Core-exit Temperature T0,T1-A1,A2,A3,A10 C-D0,C-E0IIS-JE-TE002 Core-exit Thermocouple, B09 C-DOIIS-JE-TE003 Core-exit Thermocouple, C04 C-DOIIS-JE-TE005 Core-exit Thermocouple, C08 C-DOIIS-JE-TE008 Core-exit Thermocouple, E02 C-DOIIS-JE-TE010 Core-exit Thermocouple, E06 C-DOIIS-JE-TE012 Core-exit Thermocouple, El 0 C-DOIIS-JE-TE015 Core-exit Thermocouple, G02 C-DOIIS-JE-TE016 Core-exit Thermocouple, G04 C-DOIIS-JE-TE017 Core-exit Thermocouple, G06 C-DOIIS-JE-TE020 Core-exit Thermocouple, G12 C-DO





Sheet 2 of 8 (Continued)Equipment, Action Time Frame, and Equipment LocationSection and Description Time Frames 0,1 BuildingEquip Tag No

Action LocationIIS-JE-TE021 Core-exit Thermocouple, G14 T0,T1-A1,A2,A3,A10 C-DOIIS-JE-TE025 Core-exit Thermocouple, J08 C-DOIIS-JE-TE026 Core-exit Thermocouple, J10 C-DOIIS-JE-TE030 Core-exit Thermocouple, L04 C-DOIIS-JE-TE033 Core-exit Thermocouple, Li 0 C-DOIIS-JE-TE035 Core-exit Thermocouple, L14 C-DOIIS-JE-TE038 Core-exit Thermocouple, N08 C-DOIIS-JE-TE039 Core-exit Thermocouple, N10 C-DOIIS-JE-TE040 Core-exit Thermocouple, N12 C-DOIIS-JE-TE041 Core-exit Thermocouple, P07 C-DOIIS-JE-TE001 Core-exit Thermocouple, B07 C-EOIIS-JE-TE004 Core-exit Thermocouple, C06 C-EOIIS-JE-TE006 Core-exit Thermocouple, C1 0 C-EOIIS-JE-TE009 Core-exit Thermocouple, E04 C-EOIIS-JE-TE013 Core-exit Thermocouple, El 2 C-EOIIS-JE-TE014 Core-exit Thermocouple, E14 C-EOIIS-JE-TE018 Core-exit Thermocouple, G08 C-EOIIS-JE-TE019 Core-exit Thermocouple, GI0 C-EOIIS-JE-TE022 Core-exit Thermocouple, J02 C-EOIIS-JE-TE023 Core-exit Thermocouple, J04 C-EOIIS-JE-TE024 Core-exit Thermocouple, J06 C-EOIIS-JE-TE027 Core-exit Thermocouple, J12 C-EOIIS-JE-TE029 Core-exit Thermocouple, L02 C-EOIIS-JE-TE031 Core-exit Thermocouple, L06 C-EOIIS-JE-TE034 Core-exit Thermocouple, L12 C-EOIIS-JE-TE036 Core-exit Thermocouple, N04 C-EOIIS-JE-TE037 Core-exit Thermocouple, N06 C-EOIIS-JE-TE007 Core-exit Thermocouple, C12 Cont. BldgIIS-JE-TE011 Core-exit Thermocouple, E08 Cont. BldgIIS-JE-TE028 Core-exit Thermocouple, K14 Cont. BldgIIS-JE-TE032 Core-exit Thermocouple, L08 Cont. Bldg

8.1.3 Resistance Temperature Detectors (RTDs)8.1.3.1 Hot Leg RTDs T0,T1-A1,A3 (Note 1) C-BI,C-B2 (Note 1)RCS-JE-TE135A RCS Hot Leg 1 Wide Range RTD C-B1RCS-JE-TE135B RCS Hot Leg 2 Wide Range RTD C-B2

8.1.3.2 Cold Leg RTDs T0,T1 -AI,A3 C-B1,C-B2 (Note 1)RCS-JE-TE125A RCS Cold Leg 1A Wide Range RTD C-B1RCS-JE-TE125C RCS Cold Leg 1B Wide Range RTD C-BIRCS-JE-TE125B RCS Cold Leg 2A Wide Range RTD C-B2RCS-JE-TE125D RCS Cold Leg 2B Wide Range RTD C-B2

8.1.3.3 Containment Temperature T0,T1 -Al 0 C-EOVCS-JE-TE053A Operating Floor Area Temperature A C-EOVCS-JE-TE053B Operating FloorArea Temperature B C-EO



Table 6b: List of Equipment Located Inside Containment (TO and TI)



Action Location8.1.3.4 IRWST Water Temperature T0,T1-A3,A4 C-COPXS-JE-TE041 IRWST Water Temperature C-COPXS-JE-TE042 IRWST Water Temperature C-COPXS-JE-TE043 IRWST Water Temperature C-COPXS-JE-TE044 IRWST Water Temperature C-CO

8.1.4 Hydrogen Monitors T0,T1-A8,A10 C-H1APP-VLS-JE001 Hydrogen Monitor C-H1APP-VLS-JE002 Hydrogen Monitor C-H1APP-VLS-JE003 Hydrogen Monitor C-H1

8.1.5 PXS Radiation Monitors T0,T1-A10 (Note 2) C-G3PXS-JE-RE 160 Containment Radiation Detector A C-G3PXS-JE-RE161 Containment Radiation Detector B C-G3PXS-JE-RE162 Containment Radiation Detector C C-G3PXS-JE-RE163 Containment Radiation Detector D C-G3

8.1.6 Solenoid Valves - Vent Air-Operated Valves (AOVs)8.1.6.1 PXS Core Makeup Tank AOVs T0,T1 -Al C-B,C-B7PXS-PL-VO14A CMT A Discharge Isolation C-B6PXS-PL-V01 5A CMT A Discharge Isolation C-B6PXS-PL-VO14B CMT B Discharge Isolation C-B7PXS-PL-V01 5B CMT B Discharge Isolation C-B7

8.1.6.2 PXS PRHR AOVs T0,T1-A3,A4 C-COPXS-PL-V108A PRHR HX Control A C-COPXS-PL-V108B PRHR HX Control B C-CO

8.1.6.3 Containment Isolation AOVs TI -A7 C-B8,C-C0,C-D0,E0CVS-PL-V045 Letdown Containment Isolation C-COPSS-PL-V008 Cont. Air Sample Cont. Isolation C-D0PSS-PL-V010A Liquid Sample Line Cont. Isolation A C-DOPSS-PL-VO10B Liquid Sample Line Cont. Isolation B C-DORNS-PL-V061 RNS Return from CVS Cont. Isolation C-B8VFS-PL-V004 Cont. Purge Inlet Cont. Isolation C-D0VFS-PL-V009 Cont. Purge Discharge Cont. Isolation C-DOVWS-PL-V082 Fan Coolers Return Cont. Isolation C-EOWLS-PL-V055 Sump Discharge Cont. Isolation C-COWLS-PL-V067 RCDT Gas Outlet Cont. Isolation C-CO





Sheet 4 of 8 (Continued)EauiDment. Action Time Frame, and EouiDment LocationSection and Description Time Frames 0,1 BuildingEquip Tag No

Action Location8.1.6.4 CVS RCS Boundary AOVs T0,T1 -Al C-C4CVS-PL-V081 RCS Purification Return Line Stop C-C4

ValveCVS-PL-V084 Auxiliary Pressurizer Spray Line C-C4

Isolation

8.1.6.6 Containment Atmosphere Sampling T0,T1-A8,A10 C-DOFunction

PSS-PL-VO08 Containment Air Sample Cont. C-DOIsolation

8.1.7 Motor-Operated Valves (MOVs)8.1.7.1 PXS Accumulator MOVs T1-A1 (Note 3) C-B6,C-B7PXS-PL-V027A Accumulator A Discharge Isolation C-B6PXS-PL-V027B Accumulator B Discharge Isolation C-B7

8.1.7.2 PXS Core Makeup Tank MOVs TO,TI-Al (Note 3) C-DOPXS-PL-VO02A CMT A Inlet Isolation C-DOPXS-PL-VO02B CMT B Inlet Isolation C-DO

8.1.7.3 PXS Recirculation MOVs TI-A2 C-B6,C-B7PXS-PL-V1 17A Cont. Recirculation. A Isolation C-B6PXS-PL-V117B Cont. Recirculation. B Isolation C-B7

8.1.7.4 ADS Stages 1, 2, 3, & 4 MOVs T1-A4 C-DI,C-D2,C-F3,C-G3RCS-PL-VO01A First Stage ADS A C-G3RCS-PL-VO11A First Stage ADS Isolation A C-G3RCS-PL-VO02A Second Stage ADS A C-G3RCS-PL-VO12A Second Stage ADS Isolation A C-G3RCS-PL-VO03A Third Stage ADS A C-G3RCS-PL-VO13A Third Stage ADS Isolation A C-G3RCS-PL-VO01 B First Stage ADS B C-F3RCS-PL-VO11B First Stage ADS Isolation B C-F3RCS-PL-VO02B Second Stage ADS B C-F3RCS-PL-VO12B Second Stage ADS Isolation B C-F3RCS-PL-VO03B Third Stage ADS B C-F3RCS-PL-VO13B Third Stage ADS Isolation B C-F3RCS-PL-VO14A Fourth Stage ADS MOV C-D1RCS-PL-VO14B Fourth Stage ADS MOV C-D2RCS-PL-VO14C Fourth Stage ADS MOV C-DIRCS-PL-VO14D Fourth Stage ADS MOV C-D2





Sheet 5 of 8 (Continued)Enuinment. Ac~tion Time Frame. and Eauinment Loc~ation

Section and Description Time Frames 0,1 BuildingEquip Tag No

Action Location8.1.7.5 Containment Isolation MOVs TI-A7 C-B6,C-B8,C-CO,C-DOCCS-PL-V207 CCS Containment Isolation Valve C-D0CVS-PL-V091 Makeup Line Cont. Isolation C-CORNS-PL-VO02A RNS HL Suction & Cont. Isolation - A C-B8RNS-PL-VO02B RNS HL Suction & Cont. Isolation - B C-B8RNS-PL-V023 RNS Suction from IRWST - Cont. C-B8

IsolationSFS-PL-V034 SFS Suction Line Cont. Isolation. C-B6

8.1.7.6 CVS Charging and Injection MOVs T0,T1 -Al C-COCVS-PL-V091 Makeup Line Cont. Isolation C-CO

8.1.7.7 RNS IRWST MOVs T1-Al C-B6,C-B8RNS-PL-V023 RNS Suction from IRWST - Cont. C-B8

IsolationRNS-PL-V024 IRWST Discharge Isolation Valve C-B6

8.1.7.8 PXS PRHR MOV (Note 4) T0,T1-A3,A4 C-EOPXS-PL-V101 PRHR HX Inlet Isolation C-EQ

8.1.8 Squib Valves8.1.8.1 IRWST Injection T1-A2 C-B6,C-B7PXS-PL-V123A IRWST Injection A Isolation C-B6PXS-PL-V125A IRWST Injection A Isolation C-B6PXS-PL-V123B IRWST Injection B Isolation C-B7PXS-PL-V125B IRWST Injection B Isolation C-B7

8.1.8.2 PXS Containment Recirculation T1-A2 C-B6,C-B7PXS-PL-V 118A Cont. Recirculation A Isolation C-B6PXS-PL-V120A Cont. Recirculation A Isolation C-B6PXS-PL-Vl 18B Cont. Recirculation B Isolation C-B7PXS-PL-V120B Cont. Recirculation B Isolation C-B7

8.1.8.3 Fourth Stage ADS TI-A4 C-D1,C-D2RCS-PL-VO04A Fourth Stage ADS A C-D1RCS-PL-VO04C Fourth Stage ADS C C-D1RCS-PL-VO04B Fourth Stage ADS B C-D2RCS-PL-VO04D Fourth Stage ADS D C-D2






Equipment, Action Time Frame, and Equipment LocationSection and Description Time Frames 0,1 BuildingEquip Tag No

Action Location8.1.9 Valve Position Sensors T1-A7 C-B6,C-B8,C-CO,C-DO,

C-EOCCS-PL-V207-L CCS Containment Isolation Valve C-DOCVS-PL-V045-L Letdown Containment Isolation C-COCVS-PL-V091-L Makeup Line Cont. Isolation C-COPSS-PL-V008-L Containment Air Sample Cont. C-DO

IsolationPSS-PL-V010A-L Liquid Sample Cont. Isolation Valve A C-DOPSS-PL-V010B-L Liquid Sample Cont. Isolation Valve B C-DORNS-PL-VO02A-L RNS HL Suction & Cont. Isolation - A C-B8RNS-PL-VO02B-L RNS HL Suction & Cont. Isolation - B C-B8RNS-PL-V023-L RNS Suction from IRWST - Cont. C-B8

IsolationRNS-PL-V061-L RNS Return from CVS - Cont. C-B8

IsolationSFS-PL-V034-L SFS Suction Line Cont. Isolation. C-B6VFS-PL-V004-L Containment Purge Inlet Cont. C-DO

IsolationVFS-PL-V009-L Containment Discharge Cont. C-DO

IsolationVWS-PL-V082-L Fan Coolers Return Cont. Isolation C-EO

ValveWLS-PL-V055-L Sump Discharge Cont. Isolation C-COWLS-PL-V067-L RCDT Gas Outlet Cont. Isolation C-CO

8.1.10 Hydrogen Igniters T1 -A8 See belowVLS-EH-01 Hydrogen Igniter 01, 1 C-B4VLS-EH-02 Hydrogen Igniter 02, 2 C-B4VLS-EH-03 Hydrogen Igniter 03, 1 C-B4VLS-EH-04 Hydrogen Igniter 04, 2 C-B4VLS-EH-05 Hydrogen Igniter 05, 1 C-D2VLS-EH-06 Hydrogen Igniter 06, 2 C-E2VLS-EH-07 Hydrogen Igniter 07, 2 C-D2VLS-EH-08 Hydrogen Igniter 08, 1 C-E2VLS-EH-09 Hydrogen Igniter 09, 1 C-C5VLS-EH-10 Hydrogen Igniter 10, 2 C-C5VLS-EH-1 1 Hydrogen Igniter 11, 2 C-D1VLS-EH-12 Hydrogen Igniter 12, 1 C-ElVLS-EH-13 Hydrogen Igniter 13, 1 C-D1VLS-EH-14 Hydrogen Igniter 14, 2 C-ElVLS-EH-15 Hydrogen Igniter 15, 2 C-C5VLS-EH-16 Hydrogen Igniter 16, 1 C-C5VLS-EH-17 Hydrogen Igniter 17, 2 C-B7VLS-EH-18 Hydrogen Igniter 18, 1 C-B7VLS-EH-19 Hydrogen Igniter 19, 2 C-B8VLS-EH-20 Hydrogen Igniter 20, 2 C-B6VLS-EH-21 Hydrogen Igniter 21, 1 C-B6



Table 6b: List of Equipment Located Inside Containment (TO and T1).(Subjected to Severe Accident Environment, Assessment Required)

Sheet 7 of 8 (Continued)Ecuipment, Action Time Frame, and Equipment LocationSection and Description Time Frames 0,1 BuildingEquip Tag No

Action LocationVLS-EH-22 Hydrogen Igniter 22, 1 T0,T1-A8 C-DoVLS-EH-23 Hydrogen Igniter 23, 2 C-DoVLS-EH-24 Hydrogen Igniter 24, 2 C-DOVLS-EH-25 Hydrogen Igniter 25, 2 C-DOVLS-EH-26 Hydrogen Igniter 26, 2 C-DOVLS-EH-27 Hydrogen Igniter 27, 1 C-DOVLS-EH-28 Hydrogen Igniter 28, 1 C-DOVLS-EH-29 Hydrogen Igniter 29, 1 C-DOVLS-EH-30 Hydrogen Igniter 30, 2 C-D0VLS-EH-31 Hydrogen Igniter 31, 1 C-DOVLS-EH-32 Hydrogen Igniter 32, 1 C-DOVLS-EH-33 Hydrogen Igniter 33, 2 C-B9VLS-EH-34 Hydrogen Igniter 34, 1 C-B9VLS-EH-35 Hydrogen Igniter 35, 1 C-C5VLS-EH-36 Hydrogen Igniter 36, 2 C-C5VLS-EH-37 Hydrogen Igniter 37, 1 C-C5VLS-EH-38 Hydrogen Igniter 38, 2 C-C5VLS-EH-39 Hydrogen Igniter 39, 1 C-G1VLS-EH-40 Hydrogen Igniter 40, 2 C-G3VLS-EH-41 Hydrogen Igniter 41, 2 C-G2VLS-EH-42 Hydrogen Igniter 42, 1 C-G2VLS-EH-43 Hydrogen Igniter 43, 1 C-EOVLS-EH-44 Hydrogen Igniter 44, 1 C-G1VLS-EH-45 Hydrogen Igniter 45, 2 C-EOVLS-EH-46 Hydrogen Igniter 46, 2 C-G2VLS-EH-47 Hydrogen Igniter 47, 1 C-G2VLS-EH-48 Hydrogen Igniter 48, 2 C-G1VLS-EH-49 Hydrogen Igniter 49, 1 C-E3VLS-EH-50 Hydrogen Igniter 50, 2 C-E3VLS-EH-51 Hydrogen Igniter 51, 1 C-HOVLS-EH-52 Hydrogen Igniter 52, 2 C-HOVLS-EH-53 Hydrogen Igniter 53, 2 C-HOVLS-EH-54 Hydrogen Igniter 54, 1 C-HOVLS-EH-55 Hydrogen Igniter 55, 1 C-E4VLS-EH-56 Hydrogen Igniter 56, 2 C-E4VLS-EH-57 Hydrogen Igniter 57, 2 C-E4VLS-EH-58 Hydrogen Igniter 58, 1 C-E4VLS-EH-59 Hydrogen Igniter 59, 2 C-E3VLS-EH-60 Hydrogen Igniter 60, 1 C-E3VLS-EH-61 Hydrogen Igniter 61, 1 C-HOVLS-EH-62 Hydrogen Igniter 62, 2 C-HOVLS-EH-63 Hydrogen Igniter 63, 1 C-HOVLS-EH-64 Hydrogen Igniter 64, 2 C-HO





Sheet 8 of 8 (Continued)Eauioment. Action Time Frame. and Eauioment LocationSection and Description Time Frames 0,1 BuildingEquip Tag No

Action Location

8.1.11 Electrical Containment Penetration T1-A7 C-CO,C-DO,C-C6Assemblies

ECS-EY-P01X Electrical Penetration P01 C-D0ECS-EY-P02X Electrical Penetration P02 C-DOECS-EY-P03X Electrical Penetration P03 C-DOECS-EYrP06Y Electrical Penetration P06 C-DOECS-EY-P09W Electrical Penetration P09 C-DOECS-EY-P10W Electrical Penetration P10 C-DOECS-EY-P11Z 1E Electrical Penetration P11 C-C6ECS-EY-P12Y 1E Electrical Penetration P12 C-C6ECS-EY-P1 3Y 1E Electrical Penetration P13 C-C6ECS-EY-P14Z 1E Electrical Penetration P14 C-C6ECS-EY-P1 5Y 1E Electrical Penetration P15 C-C6ECS-EY-P16Y 1E Electrical Penetration P16 C-C6ECS-EY-P18X Electrical Penetration P18 C-COECS-EY-P21Z 1E Electrical Penetration P21 C-C6ECS-EY-P22X Electrical Penetration P22 C-COECS-EY-P23X Electrical Penetration P23 C-COECS-EY-P24 Spare Electrical Penetration C-COECS-EY-P25W Electrical Penetration P25 C-COECS-EY-P26W Electrical Penetration P26 C-COECS-EY-P27Z 1 E Electrical Penetration P27 C-C6ECS-EY-P28Y 1 E Electrical Penetration P28 C-C6ECS-EY-P29Y 1E Electrical Penetration P29 C-C6ECS-EY-P30Z 1E Electrical Penetration P30 C-C6ECS-EY-P31Y 1E Electrical Penetration P31 C-C6ECS-EY-P32Y 1E Electrical Penetration P32 C-C6

8.1.12 Cables T0,T1-A10 Note 5

8.1.13 PXS Containment Water Level T0,T1-A2,A10 C-A4,C-A5PXS-JE-LS050 Containment Floodup Level C-A4PXS-JE-LS052 Containment Floodup Level C-A4PXS-JE-LS051 Containment Floodup Level C-A5

_____ I I I _______

Notes:I. RTDs could fail as temperature exceeds the designed condition.2. If device fails, monitoring can be made through the Cont. Atmosphere Sampling Function.3. Valve is open and remains open.4. See Section 8.1.7.85. Cables are located in most rooms inside containment



Table 6c: List of Equipment Located Inside Containment (T2 and T3)


Sheet 1 of 6Equipment, Action Time Frame, and Equipment LocationSection and Description Time Frames T2, T3 BuildingEquip Tag No

Action Location8.1.1 Differential Pressure and Pressure

Transmitters

8.1.1.2 RCS Pressure T2-A1,A4,A10 C-B4,C-B6RCS-JE-PT140A RCS Wide Range Pressure Trans. A C-B4RCS-JE-PT140C RCS Wide Range Pressure Trans. C C-B4RCS-JE-PT140B RCS Wide Range Pressure Trans. B C-B6RCS-JE-PT140D RCS Wide Range Pressure Trans. D C-B6

8.1.1.3 SG Wide Range Water Level T2-A3 C-BI,C-COSGS-JE-LT012 SG 1 Wide Range Level Transmitter C-B1SGS-JE-LT016 SG 1 Wide Range Level Transmitter C-B1SGS-JE-LTOI 1 SG 1 Wide Range Level Transmitter C-COSGS-JE-LT015 SG 1 Wide Range Level Transmitter C-COSGS-JE-LT013 SG 2 Wide Range Level Transmitter C-COSGS-JE-LT014 SG 2 Wide Range Level Transmitter C-COSGS-JE-LT017 SG 2 Wide Range Level Transmitter C-COSGS-JE-LT018 SG 2 Wide Range Level Transmitter C-CO

8.1.1.4 Containment Pressure T2-A1,T2,T3-A6,A7,A8,A1 0 C-DOPCS-JE-PT012 Extended Range Cont. Pressure I C-DOPCS-JE-PT013 Extended Range Cont. Pressure 2 C-DOPCS-JE-PT014 Extended Range Cont. Pressure 3 C-DO

8.1.2 Core-exit Temperature T2-A3,T2,T3-A10 C-DO,C-EOIIS-JE-TE002 Core-exit Thermocouple, B09 C-DOIIS-JE-TE003 Core-exit Thermocouple, C04 C-DOIIS-JE-TE005 Core-exit Thermocouple, C08 C-DOIIS-JE-TE008 Core-exit Thermocouple, E02 C-DOIIS-JE-TE010 Core-exit Thermocouple, E06 C-DOIIS-JE-TE012 Core-exit Thermocouple, El 0 C-DOIIS-JE-TE015 Core-exit Thermocouple, G02 C-DOIIS-JE-TE016 Core-exit Thermocouple, G04 C-DOIIS-JE-TE017 Core-exit Thermocouple, G06 C-DOIIS-JE-TE020 Core-exit Thermocouple, G12 C-DOIIS-JE-TE021 Core-exit Thermocouple, G14 C-DOIIS-JE-TE025 Core-exit Thermocouple, J08 C-DOIIS-JE-TE026 Core-exit Thermocouple, J10 C-DOIIS-JE-TE030 Core-exit Thermocouple, L04 C-DO





Sheet 2 of 6 (Continued)Equipment, Action Time Frame, and Equipment LocationSection and Description Time Frames T2, T3 BuildingEquip Tag No

Action LocationIIS-JE-TE033 Core-exit Thermocouple, L10 T2-A3,T2,T3-A10 C-DOIIS-JE-TE035 Core-exit Thermocouple, L14 C-DOIIS-JE-TE038 Core-exit Thermocouple, N08 C-DOIIS-JE-TE039 Core-exit Thermocouple, N10 C-DOIIS-JE-TE040 Core-exit Thermocouple, N12 C-DOIIS-JE-TE041 Core-exit Thermocouple, P07 C-DOIIS-JE-TEOOI Core-exit Thermocouple, B07 C-EOIIS-JE-TE004 Core-exit Thermocouple, C06 C-EOIIS-JE-TE006 Core-exit Thermocouple, C10 C-EOIIS-JE-TE009 Core-exit Thermocouple, E04 C-EOIIS-JE-TE013 Core-exit Thermocouple, El 2 C-EOIIS-JE-TE014 Core-exit Thermocouple, E14 C-EOIIS-JE-TE018 Core-exit Thermocouple, G08 C-EOIIS-JE-TE019 Core-exit Thermocouple, G10 C-EOIIS-JE-TE022 Core-exit Thermocouple, J02 C-EOIIS-JE-TE023 Core-exit Thermocouple, J04 C-EOIIS-JE-TE024 Core-exit Thermocouple, J06 C-EOIIS-JE-TE027 Core-exit Thermocouple, J12 C-EOIIS-JE-TE029 Core-exit Thermocouple, L02 C-EOIIS-JE-TE031 Core-exit Thermocouple, L06 C-EOIIS-JE-TE034 Core-exit Thermocouple, L12 C-EOIIS-JE-TE036 Core-exit Thermocouple, N04 C-EOIIS-JE-TE037 Core-exit Thermocouple, N06 C-EOIIS-JE-TE007 Core-exit Thermocouple, C12 Cont. BldgIIS-JE-TEOI 1 Core-exit Thermocouple, E08 Cont. BldgIIS-JE-TE028 Core-exit Thermocouple, K14 Cont. BldgIIS-JE-TE032 Core-exit Thermocouple, L08 Cont. Bldg

8.1.3 Resistance Temperature Detectors(RTDs)

8.1.3.1 Hot Leg RTDs T2-A1,A3 (Notel) C-BI,C-B2RCS-JE-TE135A RCS Hot Leg 1 Wide Range RTD C-B1RCS-JE-TE135B RCS Hot Leg 2 Wide Range RTD C-B2

8.1.3.2 Cold Leg RTDs T2-AI,A3 C-BI,C-B2RCS-JE-TE125A RCS Cold Leg 1A Wide Range RTD C-B1RCS-JE-TE125C RCS Cold Leg 1B Wide Range RTD C-B1RCS-JE-TE125B RCS Cold Leg 2A Wide Range RTD C-B2RCS-JE-TE125D RCS Cold Leg 2B Wide Range RTD C-B2

8.1.3.3 Containment Temperature T3-A7,T2,T3-A10 C-EOVCS-JE-TE053A Operating Floor Area Temperature A ___ C-EOVCS-JE-TE053B [Operating Floor Area Temperature B . C-EO






Eauipment, Action Time Frame, and Equipment LocationSection and Description Time Frames 2,3 BuildingEquip Tag No

Action Location8.1.4 Hydrogen Monitors T2-A8,T2,T3-AIO (Note 2) C-H1APP-VLS-JE001 Hydrogen Monitor C-H1APP-VLS-JE002 Hydrogen Monitor C-HIAPP-VLS-JE003 Hydrogen Monitor C-HI

8.1.5 PXS Radiation Monitors T2,T3-AIO (Note 2) C-G3PXS-JE-RE160 Containment Radiation Detector A C-G3PXS-JE-RE161 Containment Radiation Detector B C-G3PXS-JE-RE162 Containment Radiation Detector C C-G3PXS-JE-RE163 Containment Radiation Detector D C-G3

8.1.6 Solenoid Valves - Vent Air-Operated Valves (AOVs)

8.1.6.4 CVS RCS Boundary AOVs T2-A1,A4 C-C4CVS-PL-V081 RCS Purification Return Line Stop C-C4

ValveCVS-PL-V084 Auxiliary Pressurizer Spray Line C-C4

Isolation

8.1.6.5 Containment Spray AOVs T2,T3-A2,A6,A9 Note 3FPS-PL-V701 Containment Spray AOVs

8.1.6.6 Containment Atmosphere Sampling T2,T3-A8,AI0 C-DO,C-B1,C-B6Function

PSS-PL-V008 Containment Air Sample Cont. C-DOIsolation

8.1.6.7 Reactor Vessel Head Vent AOVs T2-A4 C-A5RCS-PL-V150A Reactor Vessel Head Vent C-A5RCS-PL-V150B Reactor Vessel Head Vent C-A5RCS-PL-V150C Reactor Vessel Head Vent C-A5RCS-PL-V150D Reactor Vessel Head Vent C-A5

8.1.7 Motor-Operated Valves (MOVs)8.1.7.6 CVS Charging and Injection MOVs T2-A1 C-COCVS-PL-V091 Makeup Line Cont. Isolation C-CO

8.1.7.7 RNS IRWST MOVs T2,T3-A2 C-B6RNS-PL-V024 IRWST Discharge Isolation Valve C-B6






Action Location8.1.7.9 RNS HL Suction to Spent Fuel Pool T3-A7 C-B8RNS-PL-VO01A RNS HL Suction Isolation - Inner A C-B8RNS-PL-V001B RNS HL Suction Isolation - Inner B C-B8RNS-PL-V002A RNS HL Suction & Cont. Isolation - A C-B8RNS-PL-VO02B RNS HL Suction & Cont. Isolation - B C-B8

8.1.10 Hydrogen Igniters T2,T3-A8 See belowVLS-EH-01 Hydrogen Igniter 01, 1 C-B4VLS-EH-02 Hydrogen Igniter 02, 2 C-B4VLS-EH-03 Hydrogen Igniter 03, 1 C-B4VLS-EH-04 Hydrogen Igniter 04, 2 C-B4VLS-EH-05 Hydrogen Igniter 05, 1 C-D2VLS-EH-06 Hydrogen Igniter 06, 2 C-E2VLS-EH-07 Hydrogen Igniter 07, 2 C-D2VLS-EH-08 Hydrogen Igniter 08, 1 C-E2VLS-EH-09 Hydrogen Igniter 09, 1 C-C5VLS-EH-10 Hydrogen Igniter 10, 2 C-C5VLS-EH-1 1 Hydrogen Igniter 11, 2 C-D1VLS-EH-12 Hydrogen Igniter 12, 1 C-ElVLS-EH-13 Hydrogen Igniter 13, 1 C-D1VLS-EH-14 Hydrogen Igniter 14, 2 C-ElVLS-EH-15 Hydrogen Igniter 15, 2 C-C5VLS-EH-16 Hydrogen Igniter 16, 1 C-C5VLS-EH-17 Hydrogen Igniter 17, 2 C-B7VLS-EH-18 Hydrogen Igniter 18, 1 C-B7VLS-EH-19 Hydrogen Igniter 19, 2 C-B8VLS-EH-20 Hydrogen Igniter 20, 2 C-B6VLS-EH-21 Hydrogen Igniter 21, 1 C-B6VLS-EH-22 Hydrogen Igniter 22, 1 C-DOVLS-EH-23 Hydrogen Igniter 23, 2 C-DoVLS-EH-24 Hydrogen Igniter 24, 2 C-DOVLS-EH-25 Hydrogen Igniter 25, 2 C-DoVLS-EH-26 Hydrogen Igniter 26, 2 C-DOVLS-EH-27 Hydrogen Igniter 27, 1 C-DoVLS-EH-28 Hydrogen Igniter 28, 1 C-DOVLS-EH-29 Hydrogen Igniter 29, 1 C-DOVLS-EH-30 Hydrogen Igniter 30, 2 C-DOVLS-EH-31 Hydrogen Igniter 31, 1 C-DOVLS-EH-32 Hydrogen Igniter 32, 1 C-DOVLS-EH-33 Hydrogen Igniter 33, 2 C-B9VLS-EH-34 Hydrogen Igniter 34, 1 C-B9



Table 6c: List of Equipment Located Inside Containment (T2 and T3)(Subjected to Severe Accident Environment, Assessment Required)


Action LocationVLS-EH-35 Hydrogen Igniter 35, 1 T2,T3-A8 C-C5VLS-EH-36 Hydrogen Igniter 36, 2 C-C5VLS-EH-37 Hydrogen Igniter 37, 1 C-C5VLS-EH-38 Hydrogen Igniter 38, 2 C-C5VLS-EH-39 Hydrogen Igniter 39, 1 C7G1VLS-EH-40 Hydrogen Igniter 40, 2 C-G3VLS-EH-41 Hydrogen Igniter 41, 2 C-G2VLS-EH-42 Hydrogen Igniter 42, 1 C-G2VLS-EH-43 Hydrogen Igniter 43, 1 C-EOVLS-EH-44 Hydrogen Igniter 44, 1 C-G1VLS-EH-45 Hydrogen Igniter 45, 2 C-EOVLS-EH-46 Hydrogen Igniter 46, 2 C-G2VLS-EH-47 Hydrogen Igniter 47, 1 C-G2VLS-EH-48 Hydrogen Igniter 48, 2 C-G1VLS-EH-49 Hydrogen Igniter 49, 1 C-E3VLS-EH-50 Hydrogen Igniter 50, 2 C-E3VLS-EH-51 Hydrogen Igniter 51, 1 C-HoVLS-EH-52 Hydrogen Igniter 52, 2 C-HoVLS-EH-53 Hydrogen Igniter 53, 2 C-HOVLS-EH-54 Hydrogen Igniter 54, 1 C-HOVLS-EH-55 Hydrogen Igniter 55, 1 C-E4VLS-EH-56 Hydrogen Igniter 56, 2 C-E4VLS-EH-57 Hydrogen Igniter 57, 2 C-E4VLS-EH-58 Hydrogen Igniter 58, 1 C-E4VLS-EH-59 Hydrogen Igniter 59, 2 C-E3VLS-EH-60 Hydrogen Igniter 60, 1 C-E3VLS-EH-61 Hydrogen Igniter 61, 1 C-H0VLS-EH-62 Hydrogen Igniter 62, 2 C-H0VLS-EH-63 Hydrogen Igniter 63, 1 C-HOVLS-EH-64 Hydrogen Igniter 64, 2 C-H0






Action Location8.1.11 Electrical Containment Penetration T2,T3-A7 C-CO,C-DO,C-C6

AssembliesECS-EY-PO1X Electrical Penetration P01 C-DoECS-EY-P02X Electrical Penetration P02 C-DOECS-EY-P06Y Electrical Penetration P06 C-DOECS-EY-P09W Electrical Penetration P09 C-DOECS-EY-P1OW Electrical Penetration P10 C-DOECS-EY-P11Z 1E Electrical Penetration P11 C-C6ECS-EY-P12Y 1E Electrical Penetration P12 C-C6ECS-EY-P13Y 1E Electrical Penetration P13 C-C6ECS-EY-P14Z 1E Electrical Penetration P14 C-C6ECS-EY-P15Y 1E Electrical Penetration P15 C-C6ECS-EY-P16Y 1E Electrical Penetration P16 C-C6ECS-EY-P18X Electrical Penetration P18 C-COECS-EY-P21Z 1E Electrical Penetration P21 C-C6ECS-EY-P22X Electrical Penetration P22 C-COECS-EY-P23X Electrical Penetration P23 C-COECS-EY-P24 Spare Electrical Penetration C-COECS-EY-P25W Electrical Penetration P25 C-COECS-EY-P26W Electrical Penetration P26 C-COECS-EY-P27Z 1E Electrical Penetration P27 C-C6ECS-EY-P28Y 1 E Electrical Penetration P28 C-C6ECS-EY-P29Y 1 E Electrical Penetration P29 C-C6ECS-EY-P30Z 1 E Electrical Penetration P30 C-C6ECS-EY-P31Y 1E Electrical Penetration P31 C-C6ECS-EY-P32Y 1 E Electrical Penetration P32 C-C6

8.1.12 Cables T2,T3-A10 Note 4

8.1.13 PXS Containment Water Level T2,T3-A2,A6,A9,A10 C-A4,C-A5PXS-JE-LS050 Containment Floodup Level C-A4PXS-JE-LS052 Containment Floodup Level C-A4PXS-JE-LS051 Containment Floodup Level C-A5

Notes:1.2.3.

Hot Leg RTDs could fail as temperature exceeds the designed condition.If device fails, monitoring can be made through the Cont. Atmosphere Sampling Function.Equipment is part of the fire protection system, on vertical pipe inside containment, feeding waterto top rings, Room 11500.

4. Cables are located in most rooms inside containment.



Table 7: Containment Regions with Associated Equipment Locations

Location Room Room Room Description MAAP4 CompartmentElevation

C-A5 11105 66 ft 6 in Reactor Vessel Cavity Reactor CavityC-A4 11104 66 ft 6 in RCDT Room Reactor Cavity

C-B6 11206 82 ft 6 in PXS Valve/Accumulator Room A PXS Compartment AC-B7 11207 82 ft 6 in PXS Valve/Accumulator Room B PXS Compartment BC-B8 11208 96 ft 6 in RNS Valve Room PXS Compartment BC-B9 11209 82 ft 6 in North CVS Equipment room Failed PXS CompartmentC-C6 11500 107 ft 2 in Electrical Penetration (Open to 11500) Intact PXS Compartment

C-CO 11300 107 ft 2 in Maintenance Floor CMT RoomC-DO 11400 118 ft 6 in Maintenance Floor Mezzanine (CMT) CMT Room

C-B1 11201 82 ft 6 in SG Compartment 1 SG Compartment 1C-C4 11304 107 ft 2 in SG 1 Access Room SG Compartment 1C-D1 11401 117 ft 6 in SG 1 Tubesheet Area SG Compartment 1C-El 11501 135 ft 3 in Loop Compartment 01 SG Compartment 1C-F1 11601 153 ft 0 in SG1 Feed Nozzle Area SG Compartment 1C-G1 11701 160 ft 6 in SG1 Upper Manway Area SG Compartment 1

C-C3 11303 107 ft 2 in Lower Pressurizer Compartment SG Compartment 1C-D3 11403 117 ft 6 in PRZ Spray Valve Room SG Compartment 1C-E3 11503 135 ft 3 in Pressurizer Compartment SG Compartment 1C-F3 11603 160 ft 6 in Lower ADS Valve Area SG Compartment 1C-G3 11703 180 ft 0 in Upper ADS Valve Area SG Compartment 1

C-B2 11202 82 ft 6 in SG Compartment 2 SG Compartment 2C-B4 11204 82 ft 6 in Vertical Access SG Compartment 2C-D2 11402 117 ft 6 in SG 2 Tubesheet Area SG Compartment 2C-E2 11502 135 ft 3 in Loop Compartment 02 SG Compartment 2C-F2 11602 153 ft 0 in SG2 Feed Nozzle Area SG Compartment 2C-G2 11702 160 ft 3 in SG2 Upper Manway Area SG Compartment 2

C-C5 11305 107 ft 2 in IRWST Upper CompartmentC-E4 11504 135 ft 3 in Refueling Cavity Upper Compartment

C-EO 11500 135 ft 3 in Operating Deck Upper CompartmentC-HO 11500 233 ft 0 in Containment Med Region Upper Compartment

JC-H1 11500 258 ft 0 in Containment Upper Region Upper Compartment



Table 8: MAAP4 Event Timing Related to the Equipment SurvivabilityTime Frames

(Taken from Table 6.1-1, Reference 4) - Time is provided in Seconds)

IGN NOIGN IVR GLOB SL CCI EVX

Break Compartment PXS PXS PXS Loop Loop Loop Loop

Igniters Status On Off On Off On On On

Accident Initiation 0 0 0 0 0 0 0

Core Uncovery 2481 2481 2484 16 9957 2306 2304

H2 Gen Begins 3318 3318 3321 179 11,123 3242 3242

Reflood RPV Yes Yes No Yes No No No

Flood Faulted PXS Yes Yes No No No No No

% Clad Rx 78 87 48 103 4 8((note 1) 37 35

Clad Rx Duration 700 800 1700 500 2000 1500 1500

Vessel Failure .......... 9040 9115

Containment 02 ......... 31,960 --

Depleted

note 1: prior to the relocation event and in-vessel fuel-coolant interaction



Table 9: High Level Action and Associated Equipment Required in Each Time FrameI Time Frames 0, 1 Time Frame 2 Time Frame 3

I RCS at operating pressureA3 Decay heat removal

PXS-PRHR HXMFWSFW

Al Inject into RCSPXS-CMTCVS

A4 Depressurize RCSPRHR HXAux. pressurizer spray

__ via SGsADS stage 1, 2, and 3

A5 Depressurize SGsSG PORVMain steam bypass

II RCS at reduced pressureA3 Decay heat removal

PXS-PRHR HXMFW MFWSFW SFW

Al Inject into RCS____ PXS-ACC

CvSRNS

A4 Depressurize RCSADS Stage 4

Reactor vessel head ventIII RCS at containment pressureAl Inject into RCS

____ PXS - IRWSTCvS CVSRNS RNS

A2 I Inject into containment___PXS - IRWST drains

I Overflow IRWST Overflow IRWSTContainment spray Containment spray

IV Containment integrityA6 Containment heat removal

PCS water PCS water PCS waterExternal water External water External water

Containment spray Containment spray

A7 Containment isolation_____ Containment isolation system

I Containment penetrations Containment penetrations Containment penetrationsA7 Containment venting

I RNS hot leg suction MOVsV Control and monitoringA8 Hydrogen control

I Igniters Igniters Igniters

A9 Control fission product releasesI Containment spray Containment spray

A10 Accident monitoringInstrumentation are defined in Table 3 and are required throughout all Time Frames 0 thru 3.


Westinqhouse Electric Company


Paqe 103 of 125

Gamma Dose Rate and Dose In Containment AirFollowing a Severe Accident

I.E .07

1.E-06

0

0-0

M 0:

I.E+04

1.E+09

I.E+08

1.E+07 0

1.E+06

1.E+03 1.E+05

0.1 1 10 100 1000 10000

Time After Accident, hours

Figure 1: Post-LOCA Gamma Dose and Dose Rate Inside Containment

(Taken from Figure 2-2, Reference 3)




Page 104 of 125

Beta Dose Rate and Dose in Containment AirFollowing a Severe Accident

1.E+08

1.E+07

0 0

1.E+060*

I.E.O5

0

0

0vE

1.E+04 LL4 1.E+060.1 1 10 100 1000 10000

Time After Accident, hours

Figure 2: Post-LOCA Beta Dose and Dose Rate Inside Containment

(Taken from Figure 2-4, Reference 3)



AP1000 Equip Surv Case IGN - DVI Break with Igniters OnContainment Gas Pressure

=)

n)

3

2.5

2

1.5

40

35- -U)a-

300)

25 o0)_

20

15I

Time (s)

Figure 3: Containment Gas Pressure - Case IGN(Taken from Figure 6.1.1-6, Reference 4)

AP1000 Equip Surv Case IGN - DVI Break with Igniters OnContainment Gas Temperature

Loop Compartment 1---- Loop Comportment 2

1000 -

900 -

C)

(1DC)

E30)

F-

800 -

700 -

600 -

500 -

400 -

1200

1000 LL

800

600 0)

E400

200

3000

I10000 I20000

Time (s)30000 40000

Figure 4: Loop Compartments Gas Temperature - Case IGN(Taken from Figure 6.1.1-7, Reference 4)

APIO00 Equipment Survivability Assessment APP-GW-VP-025 Rev. 0


AP1000 Equip Surv Case IGN - DVI Break with Igniters OnContainment Gas Temperature

U Upper Compor tmentMaintenance Floor (Elev 107-2")

550

500

450

400E

-- 350

300

500

400

300 -Z()0-E

200

100

20000Time (s)

Figure 5: CMT & Upper Compartment Gas Temperature - Case IGN(Taken from Figure 6.1.1-8, Reference 4)

AP1000 Equip

PXSpxs

Surv Case IGN - DVI Break withContainment Gas TemperatureI n ta c t Camp or tme ntBreak Compor tment

Igniters On

650

600 -

550 -

500 -

450

E 4000)

j~l

~I~x- II

Ill~ l~i-v I~

'I ----------------

- 700

- 600L.U-

- 500

400 73

a-)300 '-_E

200350 -

300I-0

I10000 20000Time (s)

30000

100

40000

Figure 6: PXS Compartments Gas Temperature - Case IGN(Taken from Figure 6.1.1-9, Reference 4)




Page 107 of 125

AP1000 Equip Surv Case IGN - DVI Break with Igniters OnTemperature in the Reactor Cavity

Cas TemperatureWater Temperature

600

550

500

450

400

350

300

250

600

500

400

300 -

200

100

20000

Time (s)

Figure 7: Reactor Cavity Gas Temperature - Case IGN(Taken from Figure 6.1.1-10, Reference 4)

APMO00 Equip Surv Case NOIGN - DVI Break with Igniters OffContainment Gas Pressure

5

4

:3

U)

2

70

60

50 c_

40Uf)

30 c-

20

20000

Time (s)40000

Figure 8: Containment Gas Pressure - Case NOIGN(Taken from Figure 6.1.2-6, Reference 4)




Page 108 of 125

AP1000 Equip Surv Case NOIGN - DVI Break with Igniters OffContainment Gas Temperature

Loop Compar tment 1- - Loop Comportment 2

1200 -

1000 -

Q 800-

0D 600-

E400-

- 1500

- 1000 <L)

Q)

-500 '-E

F--

200 I I . I I ý I I I . I I I I . I 0

40000I10000 1

20000

Time (s)

030000

Figure 9: Loop Compartments Gas Temperature - Case NOIGN(Taken from Figure 6.1.2-7, Reference 4)


Upper Compartment

Mointenance Floor ([E ev 107-2")

1400

0)

E.--

1200 -

1000 -

800 -

600 -

400 -

- 2000

- 1500 -_.

- 1000

(DC)

-500 EQ0)

I I I I I I I I I I I200I0000

120000

Time (s)30000

0

40000

Figure 10: CMT & Upper Compartment Gas Temperature - Case NOIGN

(Taken from Figure 6.1.2-8, Reference 4)




Page 109 of 125


PXS Intact Compar tmen tPXS Break Compartment

800

700

600

500

E400

300

- - - - - - --"

- 800

-600

-400E

- 200

0 10000 20000

Time (s)30000 40000

Figure 11: PXS Compartments Gas Temperature - Case NOIGN(Taken from Figure 6.1.2-9, Reference 4)

AP1O00 Equip Surv Case NOIGN - DVI Break with Igniters OffTemperature in the Reactor Cavity

Gas TemperatureWater Temperature

450

" 400

-.- " 350

Ca)

E 300

250

300U-

200

0

(a_

100 E

Time (s)

Figure 12: Reactor Cavity Gas Temperature - Case NOIGN




AP1000 Equip Surv Case IVR - DVI Break No RPV Reflood with Igniters OnContainment Gas Pressure

3 -

40

2.5-35-.

S2 30

=3

- 25 u)

1.520

1- I I I , , I 15

0 1o0oo 20000 30000 40600Time (s)

Figure 13: Containment Gas Pressure - Case IVR


AP1000 Equip Surv Case IVR - DVI Break No RPV Reflood with Igniters OnContainment Gas Temperature

Loop Compar tment 1---- Loop Comportment 2

600 - 600

550- 500 -.

500 -a 400

2 450 2C:) C)

- 300F 400 k, E

- 200 -350

3 0 0 1- p p i 1 1 , I I I I I 1 0 00 10000 20000 30000 40000

Time (s)

Figure 14: Loop Compartments Gas Temperature - Case IVR

(Taken from Figure 6.1.3-7, t5656 r5 4)




Upper Compartment

Maintenance Floor ([Eev 1077-2)

460

440

420

400

b 380

360

340

320

350

300 ',

250

(Dr'0)

200 E50

150

20000

Time (s)

Figure 15: CMT & Upper Compartment Gas Temperature - Case IVR(Taken from Figure 6.1.3-8, Reference 4)


PXS Intact Compar tment

PXS Break Compor tment

460

440 -

420 -

400 -

b 380 -

D 360 -

340 -

320 -

711 IIII I I

-I

I. '~I~

"-Il

- 350

- 300 LZ_

-250()

-200 E

- --

-150

I0

I10000 20000

Time (s)30000 40000

Figure 16: PXS Compartments Gas Temperature - Case IVR(Taken from Figure 6.1.3-9, Reference 4)



AP1O0O Equip Surv Case IVR - DVI Break No RPV Reflood with Igniters OnTemperature in the Reactor Cavity

Gas Temperature

Water Temperature

450 ,

400

-" 350

a:)E"-- 300

I I I I I I I I I I I

-300

-200 2)

Z3O

(Dca)

O 100

095n. 10000 20600 30000 40000

Time (s)

Figure 17: Reactor Cavity Gas Temperature - Case IVR(Taken from Figure 6.1.3-10, Reference 4)

AP1000 Equip Surv Case GLOB - DEG Cold Leg Break with Igniters Off

Containment Gas Pressure

5 -

4

<D 3

U)U)a)

2

70

60

50 o•

40Uf)()

30 C

20

Time (s)

Figure 18: Containment Gas Pressure - Case GLOB


API 000 Equipment Survivability Assessment

Westinahouse Electric Company


Paae 113 of 125

AP1O00 Equip Surv Case GLOB - DEG Cold Leg Break with Igniters OffContainment Gas Temperature

Loop Comportment 1

- -- - Loop Compor tment 2

1400

1200 -

1000 -

=3

- 800-

Cp

E 600-(C3

- 2000

- 1500 i:Z:

- 1000

C)-

- 50

p I I I I P I I

400 -

2000

100000 20'00 40'00 60'00

Time (s)8000

Figure 19: Loop Compartments Gas Temperature - Case GLOB


APIO00 Equip Surv Case GLOB - DEG Cold Leg Break with Igniters OffContainment Gas Temperature

Upper ComportmentMoi ntenonce Floor ([E ev 107-2")

1400

1200

1000

-- ' 800(1DC)-

E 600

400

200

2000

1500 --

1000

CD)

F5

4000 6000

Time (s)

Figure 20: CMT & Upper Compartment Gas Temperature - Case GLOB




AP1000 Equip Surv Case GLOB DEG Cold Leg Break with Igniters OffContainment Gas Temperature

PXS Intact ComportmentPXS Br eok Compor tmen t

700 - 800

600 "--"-. 600 600 U

:3 5004000.) - 0

E E•_ 400•_'- - -

200

3 0 0 i II F I I I

0 2000 4000 6000 8000 10000

Time (s)

Figure 21: PXS Compartments Gas Temperature - Case GLOB


APIOO Equip Surv Case GLOB - DEG Cold Leg Break with Igniters OffTemperature in the Reactor Cavity

Gos TemperatureWater Temperature

1400 2000

1200

- 1500 -,,1000

-- 800 10000) 0)

E 600 E<u 500

400 . . .

200 -

0 2000 4000 6000 8000 10o00

Time (s)

Figure 22: Reactor Cavity Gas Temperature - Case GLOB




AP1000 Equip Surv Case SL - Small Break with Igniters OnContainment Gas Pressure

2 2-28

1.8 26

2- 24~-1.6 220

1.4 -U)20

181.2

16

0 10000 20000 30000 40000

Time (s)

Figure 23: Containment Gas Pressure - Case SL


AP1000 Equip Surv Case SL - Small Break with Igniters OnContainment Gas Temperature

Loop Compor tment 1Loop Comportment 2

1200

15001000

cv 800 - 1000 (D

600 500

0 500 E-- 400 . . .- - ----

0

0 10000 20000 30000 40000

Time (s)

Figure 24:Loop Compartments Gas Temperature - Case SL(Taken from Figure 6.1.5-7, Reference 4)



AP1000 Equip Surv Case SL - Small Break with Igniters OnContainment Gas Temperature

Upper ComportmentMointenonce F oor (EIev 1077-2 )

550

500

450

400

E- 350

300

500

400

3000)

E200 0)

1--

100

20000

Time (s)

Figure 25: CMT & Upper Compartment Gas Temperature - Case SL(Taken from Figure 6.1.5-8, Reference 4)

AP1000 Equip

pxspxs

355

350

345

340

335CL

E 330

325 -

320

Surv Case SL - Small Break with Igniters OnContainment Gas TemperatureIntact ComportmentBreak Comportment

170

i-

160

(D

150

0)

140 0_E

130 •-

120

4000020000

Time (s)

Figure 26: PXS Compartments Gas Temperature - Case SL(Taken from Figure 6.1.5-9, Reference 4)



AP1000 Equip Surv Case SL - Small Break with Igniters OnTemperature in the Reactor Cavity

Gas Temperature

Water Temperature

450

400

350

ET 300

0 10000 20000 30000 400

Time (s)

- 300

- 200 E-)

-100 E

250 )0

Figure 27: Reactor Cavity Gas Temperature - Case SL(Taken from Figure 6.1.5-10, Reference 4)

APlO00 Equip Surv Case CCI - Spurious ADS-4. Vessel FailureContainment Gas Pressure

C)

U)Uf)CD

a)

2.5

2

1.5

CCI with Igniters

40

35

30

U)

25 QO

20

___ _ 151

Figure 28: Containment Gas Pressure - Case CCI(Taken from Figure 6.1.6-6, Reference 4)



APIO00 Equip Surv Case CCI - Spurious ADS-4, Vessel Failure CCI with IgnitersContainment Gas Temperature

Loop Compar tment 1

---- Loop Compartment 2

800

700 800

600

i 600 l600 T

500 ®400E E

4- 400 - - ----

200

II II

0 20000 40000 60000 80000 100000Time (s)

Figure 29: Loop Compartments Gas Temperature - Case CCI


AP1000 Equip Surv Case CCI - Spurious ADS-4. Vessel Failure CCI with IgnitersContainment Gas Temperature

Upper Comportment

Maintenance F oor (E[ ev 107 -2")

800

700 800

600 600® 500

Ci)

- 400E E

400 -

- 200

300 -

0 20000 40000 60000 80000 100000Time (s)

Figure 30: CMT & Upper Compartment Gas Temperature - Case CCI




APIO00 Equip Surv Case CCI - Spurious ADS-4, Vessel Failure CCI with IgnitersContainment Gas Temperature

PXS I ntac t Compor tment

PXS Breok Compor tment

460 -

350440

" 420 300 1 -i

400250

380

200 E360

340 " -- -150

3 20 I I I I I I I I I i

0 20000 40000 60000 80000 106000Time (s)

Figure 31: PXS Compartments Gas Temperature - Case CCI


AP1000 Equip Surv Case CCI - Spurious ADS-4. Vessel Failure CCI with IgnitersTemperature in the Reactor Cavity

G Gas TemperatureWater Temperature

550 -50

500

400

450

300-•400

3 5 0 ,. >2 0 0E 350 E

100300

250 r 0

Figure 32: Reactor Cavity Gas Temperature - Case CCI(Taken from Figure 6.1.6-10, Reference 4)



AP1000 Equip Surv Case EVX - Spurious ADS-4. Vessel Failure FCI with IgnitersContainment Gas Pressure

3.5 50

3

i40- 2.5 -

(n)3

Cn 2 U)

0- 0)

1.520

1~I III I I

0 10000 20000 30000 40000Time (s)

Figure 33: Containment Gas Pressure - Case EVX


AP1000 Equip Surv Case EVX - Spurious ADS-4. Vessel Failure FCI with IgnitersContainment Gas Temperature

Loop Compartment 1Loop Compar tment 2

600 600

550_--- - 500

500400

450 20) 3000)

-_ 400 T E

I- -200 .350

3 0 0 , I I ,I, I , , 1 0 0

Time (s)

Figure 34: Loop Compartments Gas Temperature - Case EVX




AP1000 Equip Surv Case EVX - Spurious ADS-4. Vessel Failure FCI with IgnitersContainment Gas Temperature

Upper CompartmentMaintenance Floor (E ev 107-2")

460350

440

420 300

400250

•o380 .

E -200 E( 360

0

340 150

3 2 0 I I I I I I I I I

Time (s)

Figure 35: CMT & Upper Compartment Gas Temperature - Case EVX(Taken from Figure 6.1.7-8, Reference 4)

APIO00 Equip Surv Case EVX - Spurious ADS-4, Vessel Failure FCI with IgnitersContainment Gas Temperature

PXS Intoct Comportment

PXS Break Compor tment

380 2

-220

370 ~200360

180 ®2350 2

160 wE 340 E

330

320 120

10000 20000 30000 40000Time (s)

Figure 36: PXS Compartments Gas Temperature - Case EVX




AP1O00 Equip Surv Case EVX - Spurious ADS-4, Vessel Failure FCI with IgnitersTemperature in the Reactor Cavity

Gas TemperatureW a Water Temperature

a)

E

420 -

400 -

380 -

360 -

340 -

320 -

300 -

280 -

260

vý -- - - - - - - - - - - - - - - - - - - -250

200

150 -a)

100 EF-

-50

0 10600 20000Time (s)

30600 40000

Figure 37: Reactor Cavity Gas Temperature - Case EVX


Figure 38: Containment Pressure Envelope




Figure 39: Loop Compartment Gas Temperature Envelope


Figure 40: Upper Compartment Gas Temperature Envelope




Figure 41: Maintenance Floor Gas Temperature Envelope

(Taken from Figure 6.2.5.4, Reference 4)

Figure 42: Intact PXS Compartment Gas Temperature Envelope




Figure 43: Faulted PXS/CVS Compartment Gas Temperature Envelope


Figure 44: Reactor Cavity Gas Temperature Envelope


F-AP-3.2-1 Rev. 0

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APP-GW-VPC-020 Revision 0

This document provides a markup of the Design Control Document (DCD) for AP 1000, Chapter 19,Appendix D (Reference 1). The changes were made because of two reasons:

1) the Severe Accident Management Guidelines (SAMG) for AP1000 (Reference 2) were developed,and

2) the actual design of certain systems is better identified.

During the development of the SAMG for AP 1000, requirements were defined for accident management inTime Frame 2 and Time Frame 3. For example, previously unidentified methods of injecting water intocontainment were added (e.g., providing makeup to overflow the IRWST by the RNS system). Also, the useof containment spray was identified as a several severe accident strategy (e.g., injecting water intocontainment and containment heat removal). Also, another method of depressurizing the RCS in Time Frame2 was identified (e.g., reactor vessel head vent).

Following the finalization of certain systems for AP 1000, the equipment and instrumentation associated withthose systems was updated. For example, the finalization of the alternate steam generator feedwater systemsresulted in the elimination of low pressure steam generator feed systems (i.e., service water, condensatewater).

Finally, changes in the identification of the equipment and instrumentation were made to update the namingconvention for AP1000. Changes were also made to update the list of references to the latest documentavailable.

The new list of equipment and instrumentation reflects the AP 1000 design as of the date this document.

Open Items:

1. Identification of equipment and instrumentation for prevention of core damage (e.g., Time Frame 0 andTime Frame 1) was not completed because the Emergency Operating Procedures (EOPs) are still indevelopment. Upon finalization of the EOPs, the equipment and instrumentation used in thoseprocedures can be identified and considered for equipment survivability assessments. This open item willbe removed upon completion of a review of the equipment and instrumentation following completion ofthe EOP development.

2. The SSCs required for containment isolation are not completely identified. It has been determined that asurvivability assessment is required for environment electrical penetrations, as identified in the DCDmark-up. However, it has not been determined whether mechanical penetrations and hatches (e.g., gasketmaterials) also need to be included in the environmental assessment to ensure containment integrity.

References:

1. APP-GW-GL-700, Revision 15, "AP1000 Design Control Document," November 11, 2005.

2. APP-GW-GJR-400, Revision A, "AP 1000 Severe Accident Management Guidelines," January 31, 2007.


AP1000 DCD Chapter 19, Appendix D Markup


19. Probabflistic Risk Assessment AP1000 Design Control Document

APPENDIX 19D EQUIPMENT SURVIVABILITY ASSESSMENT

19D.1 Introduction

The purpose of the equipment survivability assessment is to evaluate the availability ofequipment and instrumentation used during a severe accident to achieve a controlled, stable stateafter core damage under the unique containment environments. Severe accident phenomena maycreate harsh, high temperature and pressure containment environments with a significantconcentration of combustible gases. Local or global burning of the gases may occur, presentingadditional challenges to the equipment. Analyses demonstrate that there is reasonable assurancethat equipment used to mitigate and monitor severe accident progression is available at the time itis called upon to perform.

The methodology used to demonstrate equipment survivability is:

* Identify the high level actions used to achieve a controlled, stable state

* Define the accident time frames for each high level action

* Determine the equipment and instruments used to diagnose, perform and verify high levelactions in each time frame

* Determine the bounding environment within each time frame

* Demonstrate reasonable assurance that the equipment will survive to perform its functionwithin the severe environment.

19D.2 Applicable Regulations and Criteria

Equipment that is classified as safety-related must perform its function within the environmentalconditions associated with design-bases accidents. The level of assurance provided by equipmentrequired for design-bases events is "equipment qualification."

The environmental conditions resulting from beyond design basis events may be more limitingthan conditions from design-bases events. The NRC has established criteria to provide areasonable level of assurance that necessary equipment will function in the severe accidentenvironment within the time span it is required. This criterion is referred to as "equipmentsurvivability."

The applicable criteria for equipment, both mechanical and electrical, required for recovery fromin-vessel severe accidents are provided in 10 CFR 50.34(f):

Part 50.34(f)(2)(ix)(c) states that equipment necessary for achieving and maintaining safeshutdown of the plant and maintaining containment integrity will perform its safety functionduring and after being exposed to the environmental conditions attendant with the release ofhydrogen generated by the equivalent of a 100 percent fuel-clad metal-water reactionincluding the environmental conditions created by activation of the hydrogen controlsystem.

Tier 2 Material 19D-1 Revision 14


19. Probabilistic Risk Assessment AP1000 Design Control Document

" Part 50.34(f)(2)(xvii) requires instrumentation to measure containment pressure,containment water level, containment hydrogen concentration, containment radiationintensity, and noble gas effluent.

" Part 50.34(f)(2)(xix) requires instrumentation adequate for monitoring plant conditionsfollowing an accident that includes core damage.

* Part 50.44(c)(2) states that systems necessary to ensure containment integrity shall bedemonstrated to perform their function under conditions associated with an accident thatreleases hydrogen generated from 100 percent fuel-clad metal-water reaction.

-- Part 50.44(c)(4) states that equipment must be provided for monitoring hydrogen in thecontainment that is functional, reliable, and capable of continuously measuring theconcentration of hydrogen in the containment atmosphere following a significant beyonddesign-basis accident for accident management, including emergency planning. Part50.3. (f(3)(v) states th.at system.s necessary to ensure centainment integrity shall bedemenstratcd to per-form their- function under- conditions associated with an accident tareleases hydroge gener.te from 100 percent fuel elad metal v.ater- reaction.

The applicable criteria for equipment, both electrical and mechanical, required to mitigate theconsequences of ex-vessel severe accidents is discussed in Section III.F, "EquipmentSurvivability" of SECY-90-016. The NRC recommends in SECY-93-087 that equipmentprovided only for severe accident protection need not be subject to 10 CFR 50.49 equipmentqualification requirements, the 10 CFR 50 Appendix B quality assurance requirements, or10 CFR 50 Appendix A redundancy/diversity requirements. However, mitigation features mustbe designed to provide reasonable assurance they will operate in the severe accident environmentfor which they are intended and over the time span for which they are needed.

19D.3 Definition of Controlled, Stable State

The goal of accident management is to achieve a controlled, stable state following a beyonddesign basis accident. Establishment of a controlled, stable state protects the integrity of thecontainment pressure boundary. The conditions for a controlled, stable state are defined byWCAP 1-394-4APP-GW-GL-027, the-The Framework for AP600-AP1000 Severe AccidentManagement Guidance (SAMG) (Reference 19D- 1) which is considered valid for AP !000.

For a controlled, stable core state:

* A process must be in place for transferring the energy being generated in the core to along-term heat sink

* The bulk core temperature must be well below the point where chemical or physicalchanges might occur

For a controlled, stable containment state:

* A process must be in place for transferring the energy that is released to the containment to along-term heat sink




* The containment boundary must be protected

* The containment and reactor coolant system conditions must be well below the point wherechemical or physical processes (severe accident phenomena) might result in a dynamicchange in containment conditions or a failure of the containment boundary.

19D.4 Definition of Equipment Survivability Time Frames

The purpose of the equipment survivability time frames is to identify the time span in the severeaccident in which specific equipment is required to perform its function. The phenomena andenvironment associated with that phase of the severe-accident defines the environment whichchallenges the equipment survivability. The equipment survivability time frame definitions aresummarized in Table 19D- 1.

19D.4.1 Time Frame 0 - Pre-Core Uncovery

Time Frame 0 is defined as the period of time in the accident sequence after the accidentinitiation and prior to core uncovery. The fuel rods are cooled by the water/steam mixture in thereactor vessel. The accident has not yet progressed beyond the design basis of the plant, andhydrogen generation and the release of fission products from the core is negligible. Emergencyr•sponse guidelines (ERGsOperating Procedures (EOPs) are designed to maintain or recover theborated water inventory and heat removal in the reactor coolant system to prevent core uncoveryand establish a safe, stable state. Recovery within Time Frame 0 prevents the accident frombecoming a severe accident. Equipment survivability in Time Frame 0 is covered under thedesign basis equipment qualification program for the primary accident management strategies.

19D.4.2 Time Frame 1 - Core Heatup

Time Frame 1 is defined as the period of time after core uncovery and prior to the onset ofsignificant core damage as evidenced by the rapid exidatienefzirconium-water reactions in thecore. This is the transition period from design basis to severe accident environment. The overallcore geometry is intact and the uncovered portion of the core is overheating due to the lack ofdecay heat removal. Hydrogen releases are limited to relatively minor cladding oxidation andsome noble gas and volatile fission products may be released from the fuel-clad gap due torupture of fuel rod cladding at these higher temperatures. As the core-exit gas temperatureincreases above 1200 degrees F, the ERGs-EOPs transition to a red path indicating inadequatecore cooling (FR-C. 1). Upon entry into FR-C. 1, the control room. staff initiates actions tomitigate a severe accident by turning on the hydrogen igniters for hydrogen control and floodingthe reactor cavity to prevent reactor pressure vessel failure. The operators attempt to reduce thecore temperature by depressurizing the RCS and re-establish the borated water inventory in thereactor coolant system. if these actiens de net result in a decrease in cere exit temperature, theeentrol room staff initiate actions to mitigate a severe aecident by turning en the hydrogenigniters for hydrogen control and flooding the reactor cavity to prevent reactor- prIuevse

i-aue-.-Recovery in Time Frame 1 prevents the accident from becoming a core melt. In general,the containment conditions are expected to be within the design basis conditions while thereactor vessel and RCS conditions will be slightly above the design basis. Equipmentsurvivability in Time Frame 1 is evaluated to demonstrate it is within the equipment qualificationenvelope except for components inside the RCS pressure boundary.

Tier 2 Material 1913-3 Revision 14



19D.4.3 Time Frame 2 - In-Vessel Severe Accident Phase

Time Frame 2 is the period of time in the severe accident after the accident progresses beyond thedesign basis of the plantonset of rapid zirconium-water reactions and prior to the establishment ofa controlled, stable state (end of in-vessel core relocation), or prior to reactor vessel failure. Theonset of rapid e*idatien-zirconium-water reactions of the fuel rod cladding and hydrogengeneration defines the beginning of Time Frame 2. The heat of the exothermic reactionaccelerates the degradation, melting and relocation of the core. Fission products are released fromthe fuel-clad gap as the cladding bursts and from the fuel matrix as the U0 2 pellets melt. Over theperiod of Time Frame 2, the initial, intact geometry of the core is lost as it melts and relocatesdownward. Severe accident management strategies exercised during Time Frame 2 are designedto recover reactor coolant system inventory and heat removal, to maintain reactor vessel integrityand to maintain containment integrity. Recovery actions in Time Frame 2 may createcontainment environmental challenges by increasing the rate of hydrogen and steam generation.

19D.4.4 Time Frame 3 - Ex-Vessel Severe Accident Phase

Time Frame 3 is defined as the period of time after the reactor vessel fails until the establishmentof a controlled, stable state. The AP 1000 reliably-pr-e4desdesign and the AP 1000 EOPs providethe capability to flood the reactor vessel and depressurize the RCS to prevent the-vessel failure ina severe accident. This severe accident time-phase-3Time Frame 3 is ef-suiepredicted to be ayy low feque robabilit event. However, it is censidered to be remete andspeeulativeincluded in the SAMG to provide guidance in the event that reactor vessel failureoccurs. Molten core debris is relocated from the reactor vessel onto the containment cavity floorwhich creates the potential for rapid steam generation, core-concrete interaction and non-condensible gas generation. Severe accident management strategies implemented in Time Frame3 are designed to monitor the accident progression, attempt to re-establish a coolable coreconfiguration on the containment floor, maintain containment integrity and mitigate fissionproduct releases to the environment.

19D.5 Definition of Active Operation Time

Equipment only needs to survive long enough to perform its function to protect the containmentfission product boundary. In the case of some items, such as valves or motor-operators, once theequipment performs its function-i• and changes state and-(e.g. opens). the function is completed.An exception to this is solenoid operated valves that must maintain a position other than itsdesign basis failure position (e.g., a fail closed AOV that must remain open for a strategy toremain effective). For other items, such as pumps, the equipment must operate continuously toperform its function. The time of active operation is the time during which the equipment must.hange stat, . r v p..er to, perform its function.

19D.6 Equipment and Instrumentation for Severe Accident Management

The AP600-AP 1000 emergency response guideli eEOPs (Reference 199D-2) and severe accidentmanagement guidance (SAMG) framework (Reference 19D-1)-, which are .nsider.ed validforAP1-0OOdefine actions that accomplish the goals for achieving a controlled, stable state andterminating fission product releases in a severe-accident. The high level actions from the accidentmanagement framework are summarized in Table 199D-2 and provide the basis for the aetiens




cnsidered for- identifying equipment. -hc purpose- t is section is toe-eviewERGdiscusses the EOP and SAMG actions within each of the time frames of the severe-accidentto determine the equipment and instrumentation and the active operation time in which they areneeded to provide reasonable assurance of achieving a controlled, stable state. The-AP600-specifie accident management framewor-k is used to identify the equipment for- peffonning thehigh level actions. These high level actions are applicable to APl000-.

The Westinghouse Ov.-ers Group .W.6.- AP1000 SAMG (Reference 19D-3) provides theprimary input to the selection of the instrumentation used for monitoring the actions. Theinstrument used to diagnose the need for the action and monitor the response are listed.Instruments to evaluate potential negative impacts are covered under other high level actions inthe framework and therefore are also considered for survivability.

The equipment and instrumentation used in each time frame are summarized in Tables 19D-3through 199D-5. Although the SAMG considers ALL possible paths for each high level action,only the primary method is listed in Tables 19D-4 and 19D-5 for the equipment survivabilityassessment.

19D.6.1 Time Frames 0 and 1 - Accident Initiation, Core Uncovery and Heatup

Time Frame 0 represents the accident time prior to core uncovery. Time Frame 1 represents thetime following core uncovery, but prior to the rapid oxidation of the core. Aside from potentialballooning of the cladding, the core has not lost its initial intact geometry and ise-oolableoolabilitv is assured by recovering the core with borated water.

During Time Frames 0 and 1, most of the equipment that is automatically actuated will receive asignal to start. However, given that the accident has progressed to a severe accident sequencecoreuncovery and heatup, some critical equipment does-has not actuated. From accident initiationuntil the time of core uncovery (Time Frame 0) the conditions are bounded by the design basisand covered under equipment qualification. During Time Frame 1, the containment environmentis still within the design basis of the plant and the control room is operating within theEmergency Response GuidelinesOperating Procedures, but the conditions have the petential todegraded. Accident management Tto achieve a controlled, stable state, accident management, viathe EBRGsEOPs, is geared toward recovering the core cooling before the coolable geometry islost. Failing that, the plant is .. ..figned to keep the core debris in the vessel, and mitigate thecontainment hydrogen that will be generated in Time Frame 2.

19D.6.1.1 Injection into the RCS

Failure of RCS injection is likely to be the reason the accident has proceeded to core uncovery.Successful injection into the RCS removes the sensible and decay heat from the core. Prior to theonset of rapid oxidation of the cladding, successful RCS injection essentially recovers theaccident before it progresses to substantial core melting and relceationdamage and establishes acontrolled, stable state. Failure to inject into the RCS at a sufficient rate allows the accident toproceed into Time Frame 2 and the SAMG.

The equipment and systems used to inject into the RCS during Time Frame 0 and 1 are the coremakeup tanks, accumulators and IRWST (which are part of the passive core cooling system




(PXS)), the chemical and volume control system (CVS) makeup pumps, and the normal residualheat removal (RNS) pumps. For non-LOCA and small LOCA sequences, depressurization of theRCS using the automatic depressurization system (ADS) is required for successful injection.

The plant response is monitored using the system flowrates, IRWST water level indication, RCSpressure, eore-exitcore-exit temperature-ef and RCS temperature.

19D.6.1.2 Injection into Containment

The operator is instructed via the ERGs-EOPs to inject water into the containment to submergethe reactor vessel and cool the external surface if ij..i...n to the RCS c...t be establishe.coreoverheating begins to occur. This action is performed at-the-end-efater in Time Frame 1,inbnediately-but prior to entry into the SAMG. Successful cavity flooding, in conjunction withRCS depressurization, prevents vessel failure in the event of molten core relocation to the vessellower head. Failure of cavity flooding may-allows the accident to proceed to vessel failure andmolten core relocation into the containment (Time Frame 3) if timely injection into the reactorvessel cannot be established to cool the core and prevent substantial core relocation to the lowerhead.

The PXS motor-operated and squib recirculation valves are opened manually to drain the IRWSTwater into the containment in Time Frame 1.

The plant response is monitored by core-exit temperature, containment water level indication orand IRWST water level indication.

19D.6.1.3 Decay Heat Removal and Inject into the Steam Generators

In the event of non-LOCA or small LOCA sequences, the RCS pressure is elevated above thesecondary pressure. In Time Frame 0, the SGs and PRHR are used for decay heat removal. Notethat PRHR is only effective in Time Frame 0. Failure of the PRHR may be the initiating-reasonthat the event ofroceeds to core overheating. Recovery of the PRHR willprovide decay heat removal. Failure of feedwater to the steam generators with the PRHR failedmay also be the initiating eventa cause for sueh-sequeneescore overheating and recovery ofinjection to the steam generators may be required. If the steam generators remain dry withoutPRHR recovery and the core is uncovered, the tube integrity or hot leg nozzle integrity w,4-laybe threatened by creep rupture failure at the onset on-of rapid oxidation (entry into Time Frame2) if the RCS is at a high pressure. Injecting to the steam generators provides a heat sink to theRCS by boiling water on the secondary side, and protects the tubes by cooling them. Successfulsteam generator injection can establish a controlled, stable state if the losses from the RCS can berecovered and mitigated. Failure to inject to the steam generator requires depressurization of theRCS to prevent creep rupture failure of the tubes and loss of the containment integrity at theonset of rapid oxidation in Time Frame 2.

For accident sequences initiated by steam generator tube rupture, the procedures instruct thecontrol room to isolate injeetiefeedwater to the faulted steam generator, and to use injeefienfeedwater to the intact steam generator in conjunction with steam generator depressurization andPRHR initiation to cooldown the reactor coolant system and isolate the break. In Time Frame 1,PRHR initiation or injaetin-.feed to the intact steam generators may be used to re-establish a

Tier 2 Material 19D-6 Revision 14Tier 2 Material 19D-6 Revision 14



primary heat sink to cooldown the RCS and a controlled, stable state if the losses from the RCScan be recovered and mitigated. Failure to recover the PRHR or to injeelefeed the intact steamgenerator may lead to a continued loss of coolant to the faulted steam generator and progressionto Time Frame 2.

The main feedwater and startup feedwater pumps are used to inject into a pressurized secondarysystem. If thc seccnd•ry .sytem can be deprc-ssuized sufficiently,The AP 1000 plant design doesnot allow for use of low pressure systems (e.g., condensate, fire water or service water) ran-alsobesed-to injeet-feed inte-the seee..day-s idesteam generators.

The plant response is monitored with the steam generator water level indicationand-steamlinepressure, core-exit temperature, RCS temperature, IRWST temperature and IRWST water levelindication.

19D.6.1.4 Depressurize Reactor Coolant System

19D.6.1.4.1 Non-LOCA and Small LOCA Sequences

In Time Frame 0, RCS depressurization is not used for most accidents because the steamgenerators and PRHR are used to establish a controlled stable state.

In the event of non-LOCA or a small LOCA sequences, the RCS pressure is-will remain abovethe secondary pressure. If the steam generators are dry and the core is uncovered, the hot legnozzle or tube integrity is threatened by creep rupture failure at the onset of rapid claddingoxidation (beginning of Time Frame 2). Timely depressurization (prior to significant claddingoxidation) of the RCS mitigates the threat to the tubes, allows injection of the accumulators andIRWST water, and provides a long-term heat sink to establish a controlled, stable state. Failure todepressurize can result in the failure of the tubes and a loss of containment integrity whenoxidation begins.

For steam generator tube rupture (SGTR) initiated sequences, depressurization of the RCS can beused to isolate the faulted steam generator, and re-establish core cooling via injection.

The automatic depressurization system (ADS) is required to fu~ly-depressurize the RCS to allowthe PXS systems to inject. However, the recovery of passive residual heat removal (PRHR) orinjeetien-feedwater to the steam generators will provide a substantial heat sink to depressurize theRCS and mitigate the threat to the tubes. The auxiliary pressurizer sprays are not evaluated forsurvivability since the inclusion of several other safety-related systems which perform the samefunction provides reasonable assurance of RCS depressurization in the event of a non-LOCA orsmall LOCA severe accident.

The RCS pressure, SG pressure, IRWST water level and IRWST temperature,-eeFe-ex-it.mpe.atr .and RCS tempcr-a.u. . can be used to monitor the plant response to the RCSdepressurization.

19D.6.1.4.2 LOCA Sequences

In Time Frame 0, steam generators and PRHR are not effective due to low RCS pressure.




LOCA sequences (other than small LOCA sequences) by definition are depressurized below thesecondary system pressure by the initiating event and therefore, are not a threat to steamgenerator tube integrity upon the onset of rapid oxidation. Depressurization may be required forinjection to establish a long-term heat sink. Medium LOCAs require additional depressurizationto allow the injection of RNS or PXS. Large LOCAs are fully depressurized by the initiatingevent.

In LOCA sequences, only-the ADS is effective in providing depressurization capability to allowinjection to the RCS. Steam generator coldwn and auxiliary presurzer .pray• arc noteffeetiveWhile RCS cooldown and depressurization using the steam generators could beeffective, it is not evaluated here for survivability for LOCA sequences. RCS cooldown usingpressurizer sprays was determined to not be effective for the larger LOCA sequences because ofthe loss of communication between the RCS and the pressurizer for these sequences.

The RCS pressure, core exit temperature and RCS temperature can be used to monitor the plant

response to the RCS depressurization.

19D.6.1.4.3 Prevent Reactor Vessel Failure

Depressurization of the RCS, along with injecting into the containment is an accidentmanagement strategy to prevent vessel failure. The depressurization of the RCS reduces thestresses on the damaged vessel wall facilitating the in-vessel retention of core debris. To preventreactor vessel failure, the RCS must be depressurized to nearly containment conditions.

The ADS is used to depressurize the RCS to prevent reactor vessel failure. The use of the steamgenerators to depressurize the RCS to prevent vessel failure was determined to not be effectivebecause it cannot bring the RCS pressure down far enough in the time frame of interest foraccidents that progress to Time Frame I (i.e., no water on primary side of SGs).

The RCS pressure, core exit temperature and RCS ttemperature can be used to monitor the plantresponse to the RCS depressurization.

19D.6.1.5 Depressurize Steam Generators

The steam generators are-may be depressurized to facilitate low p.. .ss.e injection into the.... ndary system and to depressurize the RCS in non-LOCA and small LOCA sequences.Injection to the steam generator must be available to depressurize the secondary system toprevent creep rupture failure of the tubes.

The steam generator PORV and main steam dump-bypass valves are used for depressurizing thesteam generators. The MSIV must be opened in order to use the main steam bypass valves.

Depressurization of the steam generators is outlined-used in the ERfs-EOPs as a means tofacilitate injection intocooldown and depressurize the steam-geeaterwsRCS. Depressurization ofthe steam generators is called for in the EOPs and is only appropriate in Time Frame 1 as theRCS is depressurized in order to minimize the pressure differential across the steam generatortubes.




The steamline pressure, SG water level and RCS pressure can be used to monitor the plantresponse.

19D.6.1.6 Containment Heat Removal

Containment heat removal is not explicitly listed as a high level action in the AP600-AP 1000SAMG Framework, but it is implicit in the high level action "Depressurize Containment."Containment heat removal is provided by the passive containment cooling system (PCS). Watercooling of the shell is needed to establish a controlled, stable state with the containmentdepressurized. The actuation of PCS water is typically automatic in Time Frame 0.

PCS water is supplied to the external surface of the containment shell from the PCS water storagetank or the post-72 hour PCS ancillary water tank. Alternative water sources can be provided viaseparate connections outside containment.

The containment heat removal can be monitored with the containment pressure and the PCSwater flowrate or PCS water and PCS ancillary water storage tank levels.

19D.6.1.7 Containment Isolation

Containment isolation is not explicitly listed as a high level action in the AP-600-AP 1000 SAMGFramework, but it is implicit as a requirement to protect the fission product barrier.

Containment isolation is provided by an intact containment shell and the containment isolationsystem which closes the isolation valve in lines penetrating the containment shell that may beopen to either the RCS or containment atmosphere following an accident.

The containment isolation can be monitored by the containment pressure and the containmentisolation system valve positions.

19D.6.1.8 Hydrogen Control

Maintaining the containment hydrogen concentration below a globally flammable limit is arequirement for a controlled, stable state. The containment can withstand the pressurization froma global deflagration, but potential flame accler-aticn can produce impulsive loads fcr Whichcntaimnent integrity is uncertain. While hydrogen is not generated in a significant quantity until

Time Frame 2, provisions are provided in the ERGs-EOPs within Time Frame 1 to turn on thehydrogen igniters before hydrogen generation begins so that hydrogen can be burned as it isproduced.

Severe accident hydrogen control in the AP1000 is provided by hydrogen igniters. Thecontainment has passive auto-catalytic recombiners (PARs) as well, but they are not credited inthe fer-severe accidents assessments. The PARs are passive equipment that cannot be controlledby the operating staff from the control room.

The igniters are manually actuated from the control room in the ERG--EOPs on high core-exittemperature. The intention is to actuate the igniters prior to the onset of significant claddingoxidation (Time Frame 1). The containment hydrogen concentration is monitored prior to igniter




actuation so that a globally flammable mixture is not unintentionally ignited by the hydrogenigniters.

The plant response to the igniter actuation can be monitored by containment hydrogenconcentration using the hydrogen monitors or containment atmosphere sampling, which is part ofthe primary sampling system. The containment pressure response can also be used to indicatehydrogen burning which creates a distinctive pressure global peak, but not continual hydrogenburning by the igniters because the energy release to containment is at a low rate and thecontainment pressure response cannot be distinguished from other heat generation processes.

19D.6.1.9 Accident Monitoring

Accident monitoring is a post-TMI requirement as outlined in 10 CFR 50.34(f). Aside from theaccident management purposes outlined above, monitoring the progression of the accident andradioactive releases provides input to emergency response and emergency action levels.

Accident monitoring is provided by the in-containment monitors for pressure, hydrogenconcentration, water levels, temperature and radiation, core-exit temperature, IRWST water level,RCS pressure and the steam generator radiation monitors.

19D.6.2 Time Frame 2 - In-Vessel Core Melting and Relocation

Time Frame 2 represents the period of core melting and relocation and the entry into the SAMG.The intact and coolable in-vessel core geometry is lost, and relocation of core debris into thelower head is likely. The in-vessel hydrogen generation and fission product releases from the fuelmatrix occur during this time frame.


In Time Frame 2, the in-vessel core configuration loses its coolable geometry and it is likely thatat least some of the core debris will migrate to the reactor vessel lower head. If the RCS isdepressurized and the reactor vessel is submerged, the core debris will be retained in the reactorvessel. However, injection into the RCS to cover and cool the core debris is required to achieve acontrolled, stable state. RCS injection is not required to protect the containment fission productboundary. Injection is successful if it is sufficient to quench the sensible heat from the core debrisand maintained to remove decay heatrefill the reactor vessel. Decay heat removal will then beaccomplished by a combination of heat transfer to the water in the reactor vessel and heat transferto the water on the exterior surface of the reactor vessel.

Severe accident studies for the AP 1000 indicate that even with the reactor vessel refilled and theexterior surface of the reactor vessel submerged, the entire core debris may not return to lowtemperatures (e.g., less than 1200'F for a substantial period of time (e.g., months) if most of thecore debris has relocated to the reactor vessel bottom head. This is due to the heat transfer ratethrough the outer shell of frozen core debris in relation to the heat generation in the centralunfrozen core debris. However, this is an extreme case (i.e., no recovery of injection to the RCSuntil the entire core debris is in the reactor vessel bottom head).




Guidance for establishing RCS injection is-eutlinedwould be from the APOOO SAMG(Referenee-Reference 19D-3). Water can be injected into the RCS using the CVS or the RNSsystems. The PXS (CMT, accumulator, IRWST) is not credited in Time Frame 2 in survivabilityassessments because automatic and manual activation of the system is attempted several times inTime Frame-Frame 0 and 1, and diverse pumped systems are +redited to pr.vide reasonableassurance of RCS injcctiosuiabit in this time frame.

Post-core damage, the actions may be monitored with RCS pressure or temperature, orcontainment pressure or CVS or RNS flowrates.

19D.6.2.2 Injection into Containment

The objective of injection to the containment prior to reactor vessel failure (Time Frame 3) is tocool the external surface of the reactor vessel to maintain the core debris in the vessel.Reasonable assurance efDue to the lead time required to submerge the bottom head of the reactorvessel prior to core relocation to the bottom head, injecting to the containment for in-vesselretention is achieved by instructing the operator to drain the IRWST in the ERGs-EOPs withinTime Frame 1. After relecation of core debris te the lewer head in Time Frame 2, the suecess Af

this action becomes uncertain-.

Since a long lead time is required to submerge the exterior surface of the RPV, the objective ofinjecting into containment in Time Frame 2 is to provide water in the containment if the accidentprogresses to RPV failure and Time Frame 3. Two methods are used to inject into containmentduring Time Frame 2; the containment spray and the addition of water to the IRWST to overflowinto containment. There is one primary method used to add makeup to the IRWST to overflow:RNS pumps. Draining the IRWST to containment is not credited in Time Frame 2 insurvivability assessments because activation of the system is attempted several times in TimeFrame 1, and diverse systems are credited to provide reasonable assurance of containmentinjection survivability in this time frame. If the vessel fails, the accident progresses to TimeFrame 3. Active oper-ati. n f•o- injeetion te con.taiment is completed prior- to Time Fr.am..e 2.

Post-core damage, the actions may be monitored with containment water level indication or

IRWST water level indication if IRWST overfill is used.

19D.6.2.3 Decay Heat Removal and Inject into the Steam Generators

In transients and small LOCAs, initiation of PRHR or injection into the steam generators isrequired to be recovered in Time Frame 1 to be successful. If the secondary side is dry and theRCS is not depressurized. the 8steam generator tubes or the hot leg nozzles will failcanexperience creep rupture failure due to circulation of hot gases when the cladding oxidationbegins at the onset of Time Frame 2. Steam generator injection is not required for LOCAs whichdepressurize the RCS below the secondary system pressure.

Within Time Frame 2-SAMG, steam generator injection can be utilized in unisolated SGTRsequences to maintain the water level on the secondary side for mitigation of fission productreleases. Injecting into the steam generators, along with depressurization of the RCS, is anaccident management action to isolate containment or scrub fission products. Failure to inject to




the faulted-ruptured steam generator in Time Frame 2 can lead to continued breech of thecontainment fission product boundary and large offsite doses.

Steam generator feed for non-ruptred SGs is not credited in Time Frame 2 because it isattempted several times in Time Frame 0 and Time Frame 1. However, re-initiation of feedwaterto the ruptured steam generator is not attempted until the SAMG, which is not used until TimeFrame 2. Thus, re-initiation of feedwater is a Time Frame 2 activity.

The main feedwater and startup feedwater pumps are used to inject into a pressurized secondarysystem. if the secondary system an be depressu..ized sufficiently, condensate, fire water- .sevr.'iewaeter- can also be used to injeet into the secondary side.

Injeeticn into the steam generators is eovcred in the WA G SANIG (Reference 19D 3). The plantresponse is monitored with the core-exit temperature, RCS temperature, steam generator waterlevel and steamline pressure.

19D.6.2.4 Depressurize RCS

RCS depressurization is required within Time Frame 1 for facilitating in-vessel retention of coredebris and for successfully preventing steam generator tube failure in high pressure severeaccident sequences. The steam generator tubes or hot leg nozzles will-may_fail due to creeprupture after the onset of rapid oxidation at the beginning of Time Frame 2. Thi aetien'RCSdepressurization facilitates in-vessel retention of core debris in conjunction with injection intothe containment to give time to recover pumped injection sources to the RCS to establish acontrolled, stable state. Rcasonable assurance of successfil RCS depressurization is provided byinstructing the operator to depressurize the system in the 0-Gs-EOPs in Time Frame 1. Aetiveoperation of RCS depr-essurization is ompleted prior- to Time Frame 2.

Three methods are used to depressurize the RCS during Time Frame 2; ADS, auxiliarypressurizer spray and reactor vessel head vent. ADS and auxiliary pressurizer spray are notcredited in Time Frame 2 in survivability assessments because activation of the system isattempted several times in Time Frame 1. Survivability of reactor vessel head vent is onlyassessed in Time Frame 2.


Active operation to depressurize the-asteam generators is-can be used to cooldown the RCS priorto Time Frame 2. After the onset of core melting and relocation, depressurizing steam generatorscould threaten steam generator tube integrity. Depressurizing the steam generator in Time Frame2 does not facilitate the establishment of a controlled, stable state. Depressurization of the steamgenerators is called for in the EOPs and is only appropriate in Time Frame 1 if the RCS isdepressurized in order to minimize the pressure differential across the steam generator tubes.


Reasonable assur-ance of successful containment heat removal is provided since aAutomaticactuation of PCS water occurs in Time Frame 0 or 1. In Time Frame 2, PCS flowrate and levelare monitored to determine if additional water is needed to permit continuation of PCS flow.




Alternate water sources can be provided by connections to the external PCS water tank which isoutside the containment pressure boundary and not subjected to the harsh environment.

In addition to PCS water, a nonsafety-related containment spray system can provide heat removalfrom containment. The design basis purpose of containment spray is scrubbing fission productsand containment spray is actuated on high containment radiation levels. This would most likelyoccur in Time Frame 2 when the fuel rods are overheated and melting. Manually actuating thecontainment spray system involves opening an air-operated valve inside the containment andactuating valves and a pump outside the containment. Once open, the active operation of thevalve inside the containment is completed.

Post-core damage, the actions may be monitored with PCS flowrate and tank water level,containment water level and containment pressure.

19D.6.2.7 Containment Isolation

Active operation of containment isolation valves is required in Time Frame 0 or I to establish thecontainment fission product barrier. Therefore, only the survivability of the containment pressureboundary, including penetrations, is required to maintain containment isolation after TimeFrame 1.

19D.6.2.8 Hydrogen Control

The operator action to actuate the igniters occurs prior to the hydrogen generation at the onset ofTime Frame 2. The igniters need to survive and receive power throughout the hydrogen releaseto maintain the hydrogen concentration below the lower flammability limit during the hydrogengeneration in Time Frame 2.

If containment becomes steam inert in Time Frame 2, the igniters will become ineffective andhydrogen will accumulate in containment. The passive auto-catalytic recombiners (PARs) arealso available to control hydrogen in containment and can be effective in a steam inertenvironment. The PARs are not credited in the design basis for severe accidents because they arepassive equipment that cannot be controlled by the operating staff from the control room.

The plant response to the igniter actuation can be monitored by containment hydrogenconcentration using the hydrogen monitors or containment atmosphere sampling, which is part ofthe primary sampling system. The containment pressure response can also be used to indicatehydrogen burning which creates a distinctive pressure global peak, but not continual hydrogenburning by the igniters because the energy release to containment is at a low rate and thecontainment pressure response cannot be distinguished from other heat generation processes.

19D.6.2.9 Mitigt Control Fission Product Releases

A nonsafety-related containment spray system is provided in AP1000 to wash aerosol fissionproducts from the containment atmosphere. The spray system is manually actuated from theSAMG which is entered at the onset of Time Frame 2. Operating the spray involves opening anair-operated valve inside the containment and actuating valves and a pump outside thecontainment. Once open, the active operation of the valve inside the containment is completed.




Post-core damage. this action may be monitored with containment water level.


During the initial core melting and relocation, containment hydrogen and radiation monitors areused for core damage assessment and verification of the hydrogen igniter operation. Steamgenerator radiation monitoring is used to determine steam generator tube integrity. In the longerterm, containment atmosphere sampling can be used to monitor hydrogen and radiation.Containment pressure, and-temperature and water level indication and RCS pressure -need to bemonitored throughout Time Frame 2.

During a severe accident, the instrumentation may be subjected to conditions well beyond theirdesign basis. The SAMG does not automatically eliminate instrumentation based on its designbasis in comparison to severe accident conditions. Instead, the AP1000 SAMG relies on allavailable instrumentation indications and instructs the user to constantly compare instrumentationreadings to diverse sources to validate the instrumentation reading. It is also noteworthy thatwhile target values are established for various plant parameters to indicate a controlled stablestate, the trends of the parameters being monitored are equally as important in managing theaccident. The parameter trends indicate whether strategies are effective and determine ifadditional strategies need to be considered.

19D.6.3 Time Frame 3 - Ex-Vessel Core Relocation

Time Frame 3 represents the phase of the accident after vessel failure. The core debris is in thereactor cavity, and the IRWST water is not injected into the containment.


19D.6.3.2

The RCS is failed. Injection to the RCS is no longer needed in Time Frame 3. Note that theAP1000 SAMG considers RCS injection as a means to inject water into the reactor cavity inTime Frame 3.

Injection into Containment

Reasonable assuance of sufficient water Water coverage to the ex-vessel debris bed is passivelyprovided by the containment design to drain water from the RCS; via the CMTs, andaccumulators to the lower eontainmentIRWST. Water condensing on the PCS shell is returned tothe reactor cavity after filling the IRWST to the overflow. The addition of water to the IRWSTfrom other sources to overflow into containment is also a method of injecting water intocontainment. Containment spray can also be used to inject water into containment in Time Frame3. Draining the IRWST to containment is not credited in Time Frame 3 in survivabilityassessments because activation of the system is attempted several times in Time Frame 1, anddiverse systems are credited to provide reasonable assurance of containment injectionsurvivability in this time frame. Containment spray and overflowing the IRWST are also notcredited in Time Frame 3 survivability assessments because these methods are already credited inTime Frame 2.Witheut draining thc .WST water to the cavity, the CMT, acumulat.r and R.CSwater prcvides sufficient water- r-etu to the cavity to maintain water •cverage ever the ex vesseldebris bed.

Tier 2 Material 19D-14 Revision 14Tier 2 Material 1913-14 Revision 14



19D.6.3.3 Decay Heat Removal and Iniect into the Steam Generators

The RCS is failed. PRHR activation or injection into the steam generators is no longer needed inTime Frame 3. Injection to the steam generator for SGTR fission product scrubbing is notrequired to maintain the water level.

19D.6.3.4 Depressurize RCS

The RCS is depressurized by the vessel failure in Time Frame 3.


The RCS is failed. Steam generator depressurization is not needed in Time Frame 3.


Active initiation of PCS water is completed prior to Time Frame 3. PCS flowrate and level aremonitored for post-72 hour activities. Alternate water sources can be provided by connections tothe external PCS water tank which is outside the containment pressure boundary and notsubjected to the harsh environment.

In addition to PCS water, a nonsafety-related containment spray system can provide heat removalfrom containment. The design basis purpose of containment spray is scrubbing fission productsand containment spray is actuated on high containment radiation levels. This would most likelyoccur in Time Frame 2 when the fuel rods are overheated and melting. Manually actuating thecontainment spray system involves opening an air-operated valve inside the containment andactuating valves and a pump outside the containment. Once open, the active operation of thevalve inside the containment is completed.

Post-core damage, the actions may be monitored with PCS flowrate and tank water level,containment water level and containment pressure.

19D.6.3.7 Containment Isolation and Venting

Continued operation of the containment shell as a pressure boundary is needed to maintaincontainment isolation in Time Frame 3. Containment temperature needs to be monitored becauseprolonged exposure of organic materials (e.g., equipment and personnel hatch seals) to hightemperatures (> 400'F) can degrade the material.

In the event of containment pressurization above design pressure due to core concrete interactionnon-condensable gas generation, the containment can be vented. Venting protects containmentisolation by preventing an uncontrolled containment failure airborne release pathway. The ventcan be opened and closed as required to maintain pressure in the containment below seieebevel-Gits failure pressure. Containment venting does not prevent or mitigate containmentbasemat failure due to core concrete interaction. Containment venting to the spent fuel pool isavailable through RNS hot leg suction line MOVs.




19D.6.3.8 Combustible Gas Control

The hydrogen igniters are used to control combustible gases. Active operation of igniterscontinues to control the release of combustible gases (e.g., hydrogen and carbon monoxide) fromthe degradation of concrete in the reactor cavity.

If containment becomes steam inert in Time Frame 3, the igniters will become ineffective andhydrogen will accumulate in containment. The passive auto-catalytic recombiners (PARs) arealso available to control hydrogen in containment and can be effective in a steam inertenvironment. The PARs are not credited in the design basis for severe accidents because they arepassive equipment that cannot be controlled by the operating staff from the control room.

The plant response to the igniter actuation can be monitored by containment hydrogenconcentration using the containment atmosphere sampling, which is part of the primary samplingsystem. The containment pressure response can also be used to indicate hydrogen burning whichcreates a distinctive pressure global peak, but not continual hydrogen burning by the ignitersbecause the energy release to containment is at a low rate and the containment pressure responsecannot be distinguished from other heat generation processes.

19D.6.3.9 Mitig-te Control Fission Product Releases

The nonsafety-related sprays are actuated in Time Frame 2. The operation of the nonsafety=related fire.pump . h;ih provide containment spray continues, possibly into Time Frame 3, untilthe water from the source tank is depleted.

Post-core damage, this action may be monitored with containment water level.


Containment pressure, temperature, water level and radiation, steam generator radiation and thecontainment atm•sphere sampling fincti'nhydrogen concentration are sufficient to monitor theaccident in the long-term. Hydrogen concentration and radiation can be monitored withcontainment sampling functions. In both Time Frame 2 and Time Frame 3, auxiliary buildingradiation monitors, if properly correlated, could be used for containment radiation monitoring.

19D.6.4 Summary of Equipment and Instrumentation

The equipment and instrumentation used in achieving a controlled, stable state following a severeaccident, and the time it operates are summarized in Tables 19D-3 through 19D-5.

19D.7 Severe Accident Environments

This section intentionally blank.

19D.8 Assessment of Equipment Survivability

Since severe accidents are very low probability events, the NRC recommends in SECY-93-087,that equipment desired to be available following a severe accident need not be subject to the




qualification requirements of 10CFR50.49, the quality assurance requirements of IOCFR50Appendix B, or the redundancy/diversity requirements of 10CFR50 Appendix A. It issatisfactory to provide reasonable assurance that the designated equipment will operate followinga severe accident by comparing the AP1000 severe accident environments to design basisevent/severe accident testing or by design practices.

19D.8.1 Approach to Equipment Survivability

The approach to survivability is by equipment type, equipment location, survival time required,and the use of design basis event qualification requirements and severe environmentexperimental data.

19D.8.t.1 Equipment Type

The various types of equipment needed to perform the activities discussed above are transmitters,thermocouples, resistance temperature detectors (RTDs), hydrogen and radiation monitors,valves, pumps, valve limit switches, containment penetration assemblies, igniters, and cables.

19D.8.l.2 Equipment Location

Some of the in-containment equipment, i-e-.,such as transmitters, have-has been deliberatelylocated to avoid the most severe calculated environments. Other equipment is located outsidecontainment. The performance of the equipment was judged based on the most severe postulatedevent for that location.

19D.8.1.3 Time Duration Required

Requirements are defined for each time frame, so the equipment evaluation only discussesperformance during these periods. A limited amount of equipment has been designated for thelong term (Time Frame 3) and these parameters can be monitored outside containment.

19D.8.1.4 Severe Environment Experiments

The primary source for performance expectations of similar equipment in severe accidentenvironments is EPRI NP-4354, "Large Scale Hydrogen Burn Equipment Experiments." Thisinformation is supplemented by NUREG/CR-5334, "Severe Accident Testing of ElectricalPenetration Assemblies." These programs tested equipment types that had previously beenqualified for design basis event environmental conditions. The temperature in the chamber for thefirst program was in the 700'F - 8007F range for ten to twenty minutes during the continuoushydrogen injection tests. Although the conditions at the equipment would be somewhat lesssevere, the chamber conditions envelop all of the longer duration profiles indicated for theAP1000 events. The equipment in this program was also exposed to significant hydrogen burnspikes that are also postulated for the AP 1000_plant. The same equipment was exposed to andsurvived several events, both pre-mixed and continuous hydrogen injection which providesconfidence in its ability to survive a postulated severe accident. The second program testedcontainment penetrations to high temperatures for long durations. A penetration was tested undersevere accident conditions simulated with steam up to 400°F and 75 psia for ten days. The resultsindicated that the electrical performance of the penetration would not lead to degraded equipment




performance for the first four days. The mechanical performance did not degrade (no leaks)during the entire test.

19D.8.2 Equipment Located in Containment

The exposure to elevated temperatures as a direct result of the postulated severe accident or as aresult of hydrogen burning is the primary parameter of interest. Pressure environments do notexceed the design basis event conditions for which the equipment has been qualified if PCS isoperating as designed. Radiation environments also do not exceed the design basis eventconditions throughout Time Frames 1 &and 2.

19D.8.2.1 Differential Pressure and Pressure Transmitters

The functions defined for severe-accident management that utilize in-containment transmittersare IRWST water level, reactor coolant system pressure, steam generator wide range water leveland containment pressure. Most of these transmitters that provide this information are located inrooms where the environment is limited to short duration temperature transients. These transientsexceed ambient design basis temperature conditions but should not impact the transmitterperformance since the internal transmitter temperature do not increase significantly above thatexperienced during design basis testing. EPRI NP-4354 documents transmitter performanceduring several temperature transients with acceptable results. The 1RWST water leveltransmitters are located in the maintenance floor and are only required during Time Frames I&and 2. The environment during Time Frames 1 &and 2 does not exceed the design basisqualification parameters of the transmitters if PCS is operating as designed. Reactor systempressure and steam generator wide range water level are required through the second time frame.The only long term application is the containment pressure transmitter which may eventually beimpacted by the severe accident radiation dose. Containmcnt prc-urc zc uld also be measuredoutside containment if necessary.

19D.8.2.2 Thermocouples

The functions defined for severe accident management that utilize thermocouples are eereexi4core-exit temperature and containment water level. The eer-eexitore-exit temperature is onlyrequired during Time Frame I and the containment water level is required through Time Frame2. The temperatures to which the thermocouples are exposed during the defined time frames donot exceed the thermocouple design.

19D.8.2.3 Resistance Temperature Detectors (RTDs)

Both hot and cold leg temperatures are defined as parameters for severe accident management inTime Frame 1. RTDs are utilized for these measurements and will perform until their temperaturerange is exceeded. The hot leg RTDs could fail as the temperature increases well above thedesign conditions of the RTDs but the cold leg RTDs should perform throughout Time Frame 1.RTDs are also utilized through Time Frame 3 for the containment temperature measurement andare exposed to temperature transients that exceed design basis qualification conditions. EPRINP-4354 documents RTD performance during several temperature transients with acceptableresults.

Tier 2 Material 19D- 18 Revision 14

APP-GW-VPC-020 Revision.0


19D.8.2.4 Hydrogen Monitors

Containment hydrogen is defined as a parameter to be monitored throughout the severe accidentscenarios. Note that the design of the hydrogen monitors has not been finalized and both in-containment and outside containment monitors are being considered. Early in the accident, thehydrogen is-may be monitored by a device that operates on the basis of catalytic oxidation ofhydrogen on a heated element. The hydrogen monitors are located in the main containment area.The design limits of this device may be exceeded after the first few hours of some of thepostulated accidents and performance may be uncertain. If the device fails, hydrogenconcentration is-may be determined through the ccntainmcnt atmospherc sampling fincticn.post-accident sampling of containment atmosphere using analysis of grab samples may be used todetermine containment hydrogen concentrations.

19D.8.2.5 Radiation Monitors

Containment radiation is defined as a parameter to be monitored throughout the severe accidentscenarios. The containment radiation monitors are located in the main containment area. Early inthe accident, the design basis event qualified containment radiation monitor provides thenecessary information until the environment exceeds the design limits of the monitor. If thedevice fails, containment radiation is determined through the containment atmosphere samplingfunction or by portable monitors located against the outside of the containment shell.

19D.8.2.6 Solenoid Valve

Qualified solenoid valves are used to vent air-operated valves (AOVs) to perform the functionrequired. In Time Frame 1, the core makeup tank AOVs located in the accumulator room providea path for RCS injection, the PRHR AOVs located in the maintenance floor provide a path forRCS heat removal and the containment is isolated by AOVs located in the maintenance floor andthe PXS valve/accumulator room. The environment to which these solenoid valves may beexposed in Time Frame 1 is not significantly different than the design basis events to which thedevices are qualified. In Time Frame 2, the RCS boundary AOV located in the maintenance flooris used for CVS injection into the RCS and the containment spray AOV located in themaintenance floor is used for control of fission product release. Also in Time Frame 2, thereactor vessel head vent AOVs provide a path for RCS depressurization. In addition, throughoutTime Frame 3, access to the containment environment from the containment atmospheresampling function is through solenoid valves located in the maintenance floor. During TimeFrames 2 and Time Frame 3, these valves may be exposed to transient conditions due tohydrogen bums that exceed design basis event qualification. Solenoid valves in an energizedcondition were included in the hydrogen bum experiments (EPRI NP-4354) and survived manytransients. Shielding provided by the location of the valves limits the severe accident radiationdose to the typical design basis qualification dose for these valves.

19D.8.2.7 Motor-Operated Valves

Motor-operated valves (MOVs) are utilized in several applications during the severe accidentscenarios. MOVs in the accumulator and core makeup tank path are normally open and remainopen. In Time Frame 1, the PXS recirculation MOVs located in the PXS valve/accumulator roomare required for injection of water into the containment, MOVs for the first three stages of ADS




located in a compartment above the pressurizer are required for RCS depressurization and thecontainment is isolated by MOVs located in the maintenance floor and the PXSvalve/accumulator room. The environment to which these MOVs may be exposed in Time FrameI is not significantly different than the design basis events to which they are qualified. In TimeFrame 2, the charging and injection MOV located in the maintenance floor provides a path fromthe CVS for RCS injections- and an RNS MOV located in the PXS valve/accumulator roomprovides a path from the IRWST for RCS injection and an RPNS MOV located in the ,NLSm.nitor tank room pro-vid.s a path from the ea.k leading pit fer, RCS injection. In addition,throughout Time Frame 3, containment venting to the spent fuel pool is available through RNShot leg suction line MOVs located in the RNS valve room. During Time Frames 2 and 3, thesevalves may be exposed to transient conditions due to hydrogen burns that exceed design basisevent qualification. MOVs were included in the hydrogen bum experiments (EPRI NP-43 54) andsurvived many transients. Shielding provided by the location of the valve limits the severeaccident radiation dose to the typical design basis qualification dose for these valves.

19D.8.2.8 Squib Valves

Squib valves are only required in Time Frame 1 when the severe accident environment is notsignificantly different than the design basis environment for which these valves are qualified.IRWST and PXS recirculation squib valves located in the accumulator room are used forinjection into the RCS and containment, respectively. For RCS depressurization, the fourth stageADS squib valves are located in steam generator compartments 1 and 2.

19D.8.2.9 Position Sensors

Position sensors are required to monitor the position of containment isolation valves that couldlead directly to an atmospheric release. These isolation valves actuate early in the transient, soverification is only required during Time Frame 1. The position sensors are located in themaintenance floor and the environment in this time frame does not exceed the design basis eventqualification environment of the position sensors.

19D.8.2.10 Hydrogen Igniters

The hydrogen igniters are distributed throughout the containment and are designed to perform inenvironments similar to those postulated for severe accidents. The igniters' transformers arelocated outside containment. The successful results of glow plug testing through severalhydrogen bums is documented in EPRI NP-4354 and provides confidence in the performance ofthese devices.

19D.8.2.11 Electrical Containment Penetration Assemblies

The electrical containment penetrations are located in the lower compartment and are required toperform both electrically and mechanically throughout the severe accident. The hydrogen burnequipment experiments documented by EPRI NP-4354 included penetrations qualified fornuclear plants. Electrical testing on the penetration cables after all the pre-mixed and continuousinjection tests concluded that most of the cables passed the electrical tests while submerged inwater. These tests consisted of ac (at rated voltage) and dc (at three times rated voltage)withstand tests and insulation resistance tests at 500 volts. The penetrations were also tested




under simulated severe accident conditions at 4007F and 75 psia for about 10 days (NUREG/CR-5334). The results indicated that some degradation in instrumentation connected to thepenetration may occur in four days under these severe conditions. The maintenance floor mayexperience short temperature transients above 400'F but stable temperatures are significantlyless, so it is expected that the electrical performance would be maintained throughout the event.The only long term measurement utilizing these penetrations is containment pressure and this canbe measured outside containment if necessary. There was no degradation of mechanicalperformance of the electrical penetrations (maintaining the seal) in either test program.

19D.8.2.12 Cables

The hydrogen bum equipment experiments documented by EPRI NP-4354 included twenty-fourdifferent cable types qualified for nuclear plants. Electrical testing on these cables after all thepre-mixed and continuous injection tests concluded that all (fifty two samples) of the cablespassed the electrical tests while submerged. These tests consisted of ac (at rated voltage) and dc(at three times rated voltage) withstand tests and insulation resistance tests at 500 volts. Due tothe exposure to many events, some cable samples had extensive damage in the form of charring,cracking and bulging of the outer jackets and still performed satisfactorily. The cables tested arerepresentative of cables specified for the AP1000 and are only exposed to short singletemperature transients in their respective locations. Proper performance can be expected. Theonly long term measurement utilizing cables is containment pressure, which can be measuredoutside containment if necessary.

19D.8.2.13 Assessment of Equipment for Sustained Burning

The equipment necessary for equipment survivability in sustained burning environments isdefined in Tables 19D-3 through 19D-5. The equipment in Table 19D-3 includes equipment andinstrumentation operation during Time Frame 1 - core uncovery and heatup, and is prior to therelease of significant quantities of hydrogen. Therefore, it does not have to be qualified forsustained hydrogen burning. Table 19D-7 specifies the equipment and instrumentation used inTime Frames 2 and 3 to provide reasonable assurance of achieving a controlled stable state.

19D.8.3 Equipment Located Outside Containment

Other functions defined for severe accident management are performed outside containment andthe equipment is not subjected to the harsh environment of the event. This equipment includes,but is not limited to:

* TheSteamline radiation monitor,* Transmitters for monitoring steamline pressure,ST-he-p~assive containment cooling system flow and tank level,SThe eContainment atmosphere sampling function,

* The-CV$M- akeup pumps and flow measurement,S 4the-RNS pumps and flow measurement,

* SFS pumps and flow measurement,*SFS MON' fcr- injectien to the IIWSTI," RNS MOVs fer injection from . ask loading pit to RCS* MFW pumps and valves,




* SFW pumps and valves and condensae,*Fire water- and serviee water to feed steam generators* Steam generator PORVs and main steam dump-b_vpass valves for depressurization,* Recirculation pumps, PCS valves and fire water pumps and valves for containment heat

removal,* Containment isolation valves (outside containment),* Auxiliary building radiation monitor,* MOV and manual valve from RNS hot leg suction lines to the spent fuel pool and* Fire water, fire pumps, valves and flow measurement used to provide containment spray and

backup containment cooling.

19D.9 Conclusions of Equipment Survivability Assessment

The equipment defined for severe accident management was reviewed for performance duringthe environments postulated for these events. Survivability of the equipment was evaluated basedon design basis event qualification testing, severe accident testing, and the survival time requiredfollowing the initiation of the severe accident. The equipment that is qualified for design basisevents, has a high probability of surviving postulated severe accident events and performingsatisfactorily for the time required.

APIOO- This assessment provides reasonable assurance that equipment, both electrical andmechanical, used to mitigate the consequences of severe accidents and achieve a controlled,stable state can perform over the time span for which they are needed.

19D.10 References

19D-11 "Framework for AP600-AP 1000 Severe Accident Management Guidance,"-WCAP-4-3944APP-GW-GL-027, Revision 30, Janua"y 4 998June 2006.

19D-2 AP600-AP 1000 Emergency Response GuidelinecOperating Procedures.

1 .9D-3 Westinghouse Ov,%er's Gr-etup "AP 1000 Severe Accident ManagementGuidaneeGuidelines," APP-GW-GJR-400. June-January 31 4-9942007.




Table 19D-1

DEFINITION OF EQUIPMENT SURVIVABILITY TIME FRAMES

Time Frame Beginning Time Ending Time Comments

0 Accident safe, stable state • Bounded by design basis equipmentinitiation or qualification environment

core uncovery

1 Core uncovery controlled, stable * Core uncovery and heatupstate * Bounded by design basis equipment

or qualification environmentrapid claddingoxidation

2 Rapid cladding controlled, stable * In-vessel core melting and relocation

oxidation state • Entry into SAMG

orvessel failure

3 Vessel failure controlled, stable * Ex-vessel core relocationstateorcontainment failure




Table 19D-2

AP1000 HIGH LEVEL ACTIONS RELATIVE TO ACCIDENT MANAGEMENT GOALS

ktaken frzm iaeleic 1, r-erzrcnee 19+ 1)

Goal Element High Level Action*

Controlled, stable core water inventory in RCS * inject into RCS0 depressurize RCS

water inventory in containment • inject into containment

heat transfer to IRWST 0 initiate PRHR

heat transfer to SGs • inject into RCS0 inject into SGs

__ depr-essthie SGsheat transfer to containment & inject into RCS

* inject into containment0 depressurize RCS0 initiate PRHR

Controlled, stable heat transfer from containment • depressurize containment

containment * vent containment• water on outside containment

isolation of containment • inject into SGs0 depressurize RCS

hydrogen prevention/control 0 bum hydrogen0 pressurize containment* depressurize RCS* inject into containment* vent containment* water on outside containment

core concrete interaction prevention • inject into containment

high pressure melt ejection prevention • inject into containment0 depressurize RCS

creep rupture prevention 0 depressurize RCS0 inject into SGs

containment vacuum prevention • pressurize containment

Terminate fission product isolation of containment • inject into SGs

release • depressurize RCS

reduce fission product inventory • inject into containment• depressurize RCS

reduce fission product driving force • depressurize containment0 water on outside containment

Note:* See Tables 19D-3, 19D-4 and 19D-5


oo -

0

0I-

0

rI'j

C

U,

U,

U,

0 ~

o -~

0

~.o

1*.,



Table 19D-3 (Sheet 2 of 3)

EQUIPMENT AND INSTRUMENTATION OPERATION PRIOR TO END OF TIME FRAME 1 -CORE UNCOVERY AND HEATUP

Action Ka ument Instrumentation PU rose Comment

Depressurize SGs 0 SG PORV * steamline pressure * depressurize RCS 0 requires injection into SGs to

* main steam bypass * RCS pressure 0 minimize pressure prevent creep rupture

* SG WR water level differential across SG tubes

Inject Into 0 IRWST drains * core-exit t/c's 0 prevent vessel failure * manual cavity flooding actionContainment • containment water level in EOP

0 IRWST water level

Containment Isolation o containment isolation system 0 containment isolation system 0 containment integrity 0 containment isolation system

0 containment shell valve position often automatic

0 penetrations 0 containment pressure * manual action in EOP

Control Hydrogen 0 igniter 0 containment hydrogen monitors 0 containment integrity 0 manual igniter action in EOP

* containment atmosphere samp

* ling functions

* containment pressure

Containment Heat 0 PCS water 0 containment pressure 0 containment integrity * PCS water automaticRemoval 0 external water * PCS flowrate 0 alleviate environmental

* PCS tank level challenge to equipment

0 long term heat transfer path





EOUIPMENT AND INSTRUMENTATION OPERATION PRIOR TO END OF TIME FRAME 1 -CORE UNCOVERY AND HEATUP

Action Eq uipment Instrumentation Purpose Comment

Accident Monitoring * SG radiation * accident management * required by 10 CFR 50.34(f)

* containment pressure * emergency response*

* containment temperature * emergency action levels*

* containment hydrogen monitors

* containment water level

• containment radiation

• containment atmospheresampling functions

• auxiliary building radiation

* core-exit t/c's

* RCS pressure

* IRWST water level

Note that the instrumentation required for emergency response and emergency action levels is an open item because the EALs are not yet developed.





EOUIPMENT AND INSTRUMENTATION OPERATION DURING TIME FRAME 2 -IN-VESSEL CORE MELTING AND RELOCATION

Action Equipment Instrumentation Purpose Comment

Inject into RCS * CMT * RCS pressure cool core debris in-vessel RCS injection needed to cool in-

* accumulator * containment pressure vessel debris for reasonable

* IRWST * CVS flow assurance of controlled, stable state

* CVS * RNS flow* RNS * RCS temperature

Decay Heat Removal * via SGs * SG WR water level decay heat removal

* steamline pressure

* core-exit t/c's

* RCS RTDs

Inject Into containment spray . containment water level prevent vessel failure containment spray only actuated onContainment * overflow IRWST high containment radiation in

9 RNS SAMG which occurs in TimeSIRWST drains Frame 2

Inject to SGs * MFW * SG WR water level * isolate containment in SGTR * also requires RCS depressurization

* SFW * steamline pressure * scrub fission products for containment isolation

Depressurize RCS * ADS . RCS Pressure * prevent vessel failure 0 needed for in-vessel retention of

* aux pressurizer spray * containment integrity core debris

* reactor vessel head vent * needed for prevention of TI-SGTR

. try to recover in Time Frame 2, ifnot successful in Time Frame 1

Tier 2 Material l9D-28 Revision 14Tier 2 Material 19D-28 Revision 14




EQUIPMENT AND INSTRUMENTATION OPERATION DURING TIME FRAME 2 -IN-VESSEL CORE MELTING AND RELOCATION

Action Equipment Instrumentation Purose Comment

Depressurize SGs * not needed in Time Frame 2

Containment Heat * PCS water * PCS flowrate * containment integrity * active operation completed in TimeRemoval * external water * PCS tank level Frame 1; needs to be continued in Time

Frame 2* containment spray * containment water level

containment pressure

Containment Isolation * containment shell * containment pressure * containment integrity containment isolation system active

* penetrations operation completed in Time Frame 1

Control Hydrogen * igniters * containment hydrogen * containment integrity active operation continues in Timemonitors Frame 2

" containment atmosphere * monitors only required initially to verifysampling function hydrogen igniter operation

" containment pressure

Control Fission containment spray * containment water level * scrub fission products * containment spray only actuated on highProduct Releases containment radiation in SAMG which

occurs in Time Frame 2





EQUIPMENT AND INSTRUMENTATION OPERATION DURING TIME FRAME 2 -IN-VESSEL CORE MELTING AND RELOCATION

Action Eguipment Instrumentation ]rpose Comment

Accident Monitoring • SG radiation • accident management active operation continues in Time

* containment pressure * emergency response* Frame 2

* containment temperature * emergency action levels*

* containment hydrogen

monitors

* containment water level

* containment radiation

* containment atmosphere

sampling functions

* auxiliary building

radiation

* RCS pressure

* Note that the instrumentation required for emergency response and emergency action levels is an open item because the EALs are not yet developed.





EQUIPMENT AND INSTRUMENTATION OPERATION DURING TIME FRAME 3 -EX-VESSEL CORE RELOCATION


Inject into RCS * not needed in Time Frame 3

Decay heat removal * not needed in Time Frame 3

Inject into SGs * not needed in Time Frame 3

Depressurize RCS * not needed in Time Frame 3

Depressurize SGs * do not want to depressurize SGs inTime Frame 3

Inject Into * containment spray * containment water level e cool ex-vessel core debris to * only get to Time Frame 3 if thereContainment * overflow IRWST prevent or mitigate is no water in containment or if

0 CVS consequences of CCI RCS depressurization fails

* scrub fission products releasedfrom ex-vessel core debris

e SFS

* IRWST drains

Containment Heat * PCS water * PCS flowrate * containment integrity * active operation completed inRemoval * external water * PCS tank level Time Frame 1; needs to be

* containment spray * containment water level continued in Time Frame 3

* containment pressure

Containment Isolation * containment shell * containment pressure * containment integrity * active operation of containment

" penetrations * containment temperature isolation system completed inTime Frame 1

" RNS hot leg suction MOVs * containment pressure * containment vent * manual action within SAMG

* SFP water level





EQUIPMENT AND INSTRUMENTATION OPERATION DURING TIME FRAME 3 -EX-VESSEL CORE RELOCATION


Control Hydrogen o igmiters * containment atmosphere containment integrity * active operation continues insampling function Time Frame 3

0 containment pressure * PARs may be effective in TimeFrame 3 if imniters are noteffective

Control Fission * containment spray * containment water level scrub fission products 9 containment spray only actuatedProduct Releases on high containment radiation in

SAMG which occurs in TimeFrame 2

Accident Monitoring * SG radiation * accident management * active operation continues in

0 containment pressure * emergency response* Time Frame 3

0 containment temperature o emergency action levels*

• containment hydrogenmonitors

0 containment water level

0 containment radiation

9 containment atmospheresampling fimctions

o auxiliary buildingradiation

* Note that the instrumentation required for emergency response and emergency action levels is an open item because the EALs are not yet developed.

Table 19D 3 (Sheet 1 of 2)



19. Probabilistic Risk Assessment API000 Design Control Document

• T ?Thl

E ~U! P ~Ai' P i AND~ 1N S 9P UlYIIE A 0 - -- -1AllUP10 - - -R-1 0'RU1U1' i'kUUI 0U FIJ UT PIE FL tR'J 1J--if-•,'rblr• l"•Tl"If•l[ 71"•1r'1%7 -- -•r It- • v-t

Aetion Equipmniet Instr-Umcintatio Fur-pose flieInjee-iuR~ .~x .eere~t~tt~e~ 'reeore orolinig einjection must often be recoverdtob

OGNIesuS succoceful in severe aeraident

eRNS NS-Dew

_____________________ 'RAIST water level

Inetlt PXS reeir-e 96e efeeit t rS 6pr3event Vessel failure -manual cavity flooding action in ERGGentanme SFS injectioni to refuelin~g -containment water level

ewA'ty *IRWST- water level

Dccay heat r-emeval Initiate-Pp4R -IRWST- Water lee oestablish heat s-nk einjection sourcee maust often be r-eeovered to beH1igh pfess*Ife 'SG WR watcr lo1 'make SGs available to successful in scverc accident

P1FWeteamline proessure depressurie RGSSFSAI eprevent cr-eep rupture

.be~w Pess+3fe-eendensate

servieev.'ater

Depressurize RGS *PressurizeF spray .RGS-pfesstife 'facilitate injection to RCS -ADS often automti*ADS 00FO Kit te's long te~m heat t,%isfer path*PRR X eGSRT-s pr-event creep ruptfe 'RCS depressurization required prior. to

*Via 8GS eIRWSTAwater lee 'orntainment integrity cl.ading oxdto- opeetcepmtr

'isolate break in SGTFR 'uses intact SG orp~qURsprcvent vessel failur e 'requifes injetio-n to- conta-in-ment tob





EQUIPMENT AND !NST-RUMENT-ATION OPERATIO10 N RRIOR TO END OF TIME FRAME 1CORE UNCOVERY AND HEATUP

AtPOOR Eqiiipmni4 InstrUmentatio PUFposeCo mn

Dersu.z SG PORVI 'taline pr-essuroe 'faeilitate ifjection to SGS erequires injcotion inte.SGs to prevent ereep______________ *RG~pfwsure 'depressurize RCS Fupure

Containment Heat Removal *PGS water 'cet fOSUeOpntainmen~t intgrt 'PC-S vVater AAR;n Auto;Ainatl.eeitefnal-water GpgS flewraEm'leiteeni-ronmental

*.(;gStankew 1hlcg toL euipmfenit______________________ __________________*long term heat trandeferath

Conntainment Tq(;latitn 'containment isolationB 'cnan t isolation econtainment integiy'otimn isoalation system oftenSysten system valve position a*uteimafiG

'containment shell 'conftainment prossuro 'm ual action in ERG

centgl Hteiege 'containent hydrogen 'oentainment intgrt 'manual ignte aetion in ERG

'containment pesur

Acceident Monitoring SG -*adiatien 'accident management 'requiroed by 10 CFR 50.3 4(f)'containment pressure 'emergency response'containment temperatufe -emergency action levels'conitainment hydroegen

'containment w.ater level'contaiffnment radiation





EQUIPMENT AND INSTRUAMENTATION OPERATION DURING T-IME FRA 2INAWVES-SEL CORE MELTING AND RELOCATION

Aetion Equ~ipmenet Instr-umentatio FHP-u see gommeni

kjeet -ne RG8 .GVS -RGS pressure 'coo~l core4 deb:i& 'RGS injection needed to cool in veseel debrie ferRN 'c1on9ýeftainmfentt prescuro r-easenable assurance ef eontrolled, stable etatc

.GVg-fiew

Inject Inte Containment 'active operation completed in Time Frame 1

Decay heat remeval GPH HX*IWST- water lee 00ool creGF debris *also requires RGS depressurization fcr suscess at*Hiigh-Presswie eSG WR water lee 'isslate containment in SG-injeetien

NIIIesteamline pressur-e SGTRSFW 'scrub fission products

obe~wPEOeesufCoendensate-Fire Wate*

__ Se 4e -W aveeWter-__

Deprssuize GS'active operation completed in Time Frame 1

DeprewrizeSGS'active eper-ation completed in Time Frame 1

Containment Heat Removal .4CS flevfate 'active operation completed in Time Frame 1__ .P4CS ankje3Vej __

Containment Isolation 'cnn ent shl cnanetpesr cnanent integrity 'containnment isolation system active operation____________________ _______________________ cmpleted in Time Frame 1

'con Hdee *gier eftainmnent hydrogen coentainment intert 'ateentncntinues in Timne Frame 2memiters emonmitor- only required initially to ver-ify

'cont-ainBment atmosphere hydrogen igniter operation





EQUIPAIENT AND !NSTRLIUMNTATION OPERATION DURING TIME FRAME 21N VESSEL CORE MELTING AND RELOCATION

Aefien Equipmenet InstrmcntaiCommentes

Gete isinOfe (Spay) pamp espray flew~ate esrbarsl manual aetion within SMAAG-sprayvalve cOentainmffent precr

Produet Release&

Accident Meniteoing 'containmffent pressure eaccident managemn 'active operatin continuce in Time Frame 2'cnti~nttemperature eemergency response'cona~ atmaosphere 'cmergency action levels

'auxi bldg. r-adiationMonintors

-SG radiation meor~torc


APP-GW-VPC-020

19. Probabilistic Risk Assessment

Revision 0

AP1000 Design Control Document

Table 19D 5 (Sheet 1 ef 2)

EQUIPMENT AND INSTTRUMIENTATTION OPERATION DURING TIME FRAME 3EX VESSEL CORE RELOCATION

Action Equipmient InAstrumcPmtation PurposeCo mn

hajet ine RGtncat needed in Time Frame 3

Der.ay heat rm .val ,injectien of CGNTs and accumulaters in TimeFrame 1 PrOv~ides reasenableA accuranee etwater eeverage te x vesseler-edebfis

4eetintoSGS net needed in Time Frame 3

Depressu6.ze RGSnet needed in Time Frame 3

Gnet needed in Time Frame 3

Centainment Heat Remeval .PCS flevffate 'active eperatien eempleted in Time Frame 1*PcG4an1E4evel __

Centainment Iselatien 'conitainment shel 'Gentainment prEOcUree -eentainment integrity ea~tive eperation of centainment irelatien_______________________________ __________________ system cempleted inif Time F-r-am 1

'fShot leg suoie 'containmfenit 3Vent 'manual aetien within SANIG

'co91ntargenmente~ atmosphere 'containment intgrt atieoperation eontinues in Time Frame 3





E Q UI P ET AN D I N S TRUM-EU N T-ATIO-N O-P ERATIO0N D U FANG TIMEA4- F R-A1' -W 3E X VEES8S EL CO0RE -RELOC-AT-ION

Aetion Equipment I"Ist*uMeNtAtio P-UFPOe em e

Gel4e issi~en 'S~yPM pa lAeeecrub fissien preducts 'active eper-atign continues

Pr-eduet Release

Accident Nienitog 'conftaifimfent pressuro 'accident management eactive oper-ation coat flues in Time Frame4Gnaimn tepeatue 'emergoeny response'contaiament atmosphere emeraegeney action levels

'aux bldg. radiation monitOrS*SG r-adiation moneitors&


APP-GW-VPC-020

19. Probabilistic Risk Assessment

Revision 0

AP1000 Design Control Document

TABLE 19D-6 NOT INCLUDED IN THE DCD.





SUSTAINED HYDROGEN COMBUSTION SURVIVABILITY ASSESSMENT

EQUIPMENT AND SUSTAINED HYDROGEN COMBUSTION SURVIVABILITYINSTRUMENTATION ASSESSMENT

Equipment

PXS equipment (injection) The PXS equipment utilized for introduction of cooling water includes componentredundancy and is separated into two delivery flow paths. The two flow paths arephysically separated into two trains such that if one train is disabled due to asustained bum from DVI or other line break within that subsystem, the othersubsystem will function.

CVS equipment (injection) The equipment providing for CVS injection is located within the CVScompartment with the exception of the CVS makeup isolation valve. Inaccordance with the above, a sustained bum will not occur within the CVScompartment and, therefore, the equipment within this compartment utilized forCVS makeup will be operable. The CVS makeup isolation valve is normally inthe correct position for severe accident scenario and is considered operable.

RNS equipment (injection) Injection via the RNS is dependent only upon check valves within containmentand, therefore, is not susceptible to sustained burning effects.

Main Feedwater (high The operability of main feedwater system to inject high pfersufe-feedwater topres..ure in.jetioninto the steam generators is not dependent upon equipment located within containment

and, therefore, is not susceptible to sustained burning effects.

Startup Feedwater (high The operability of startup feedwater system to inject high-"press-re-feedwater topresure in....jtin inte the steam generators is not dependent upon equipment located within containment

and, therefore, is not susceptible to sustained burning effects.

Condensate (low pressure The operability of the condensate system to provide makeup for- lew pr-essureinjectien into the SG) fcedwater- to steam gener-ator-s is net dependent upen equipment located within

e.ntai.nent and, therefore, is not suseeptiblc te sustained buing cffcets.

Fire Water-(le.-pfesstife The operability of the fire water system to provide makeup for lew pr-esstiieinjection into the SG), feedwater, to steam generato.s, for- containment spray and for externalcontainment spray, and containment vessel cooling is not dependent upon equipment located withinexternal containment vessel containment and, therefore, is not susceptible to sustained burning effects.cooling

Sen'iee Water- (low; The oper-ability of the serc wae ytem to proevidc makeup fcr- low pressure-pressure iinjection into tefcedwaere to steam generators is not dependent upon cquipmenft located within8G) containment and, therefore, is niet susceptiblc to sustained burning effects-.







Equipment

Containment Shell The operability .f the . .ntain•. .ent shell du.ing sustained bu.ing is addresed byReference 19D 5.As discussed in Section 19.41.7 of this document, hydrogenplumes are located away from the containment shell to mitigate the threat to thecontainment integrity.

Igniters Igniters are specified and designed to withstand the effects of sustained burningand, therefore, are considered operable for these events.

Instrumentation

RCS Pressure There are four RCS pressurizer pressure transmitters. Two transmitters are locatedat a distance greater than 75 feet from the vent from the PXS valve/accumulatorroom and are; therefore; beyond the distance that potentially causes operabilityconcerns from a sustained flame. The other two transmitters are located in adifferent room from the fourth stage ADS valves. This precludes radiative heating,which could potentially cause operability concerns.

Containment Pressure There are three extended range containment pressure transmitters. The threetransmitters are located such that they cannot all be exposed to a sustained flamefrom either of the vents from the PXS valve/accumulator room into themaintenance floor at the base of the CMTs. Therefore, continued operability ofthe containment pressure function is provided.

SG 1 Wide Range Level There are four steam generator wide range levels for SG 1. Two of thetransmitters are located at a distance of greater than 20 feet from a CMT and are,therefore, beyond the distance that could potentially cause operability concernsfrom a sustained flame from the vent from the PXS valve/accumulator room intothe maintenance floor at the base of the CMT. The other two transmitters arelocated over 20 feet below the fourth stage ADS valves. This precludes radiativeheating, which could potentially cause operability concerns.

SG 2 Wide Range Level Based on the layout of the four steam generator wide range levels for SG 2, atleast two of the transmitters will not be exposed to a sustained flame from eitherof the vents from the PXS valve/accumulator room into the maintenance floor atthe base of the CMTs. Therefore, continued operability of the SG 2 wide rangelevel indication function is provided.







Instrumentation

Containment Hydrogen There are 3 distributed containment hydrogen monitors. There are no sustainedMonitors burns that could potentially affect the two sensors that are located at an elevation

of 164 feet or the sensor located within the dome.

Containment Atmosphere The capabilities to perform containment atmosphere sampling are discussed inSampling Function Section 9.3.3.1.2.2 - Post-Accident Sampling. Successful containment

atmosphere sampling is dependent on the availability of either of the hot legsample source isolation valves and the containment isolation valves in series withthe isolation valve. The sample isolation valve from reactor coolant hot legnumber 1 is located in a different room from the fourth stage ADS valves. Thisprecludes radiative heating, which could potentially cause operability concerns.The sample isolation valve from reactor coolant hot leg number 2 is located in adifferent room from the fourth stage ADS valves. This precludes radiative heating,which could potentially cause operability concerns. The containment isolationvalves are located less than 20 feet from a CMT. However, a steel shroud aroundbase of the CMT prevents a sustained flame existing on the containment side ofthat CMT and, therefore, affecting the operability of either of the containmentisolation valves.


AP1000 COL Standard Technical Report Submittal of APP-GW ...Westinghouse Westinghouse Nuclear Power...

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Transcript of AP1000 COL Standard Technical Report Submittal of APP-GW ...Westinghouse Westinghouse Nuclear Power...