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NUREG-2236, Vol. 3, Confirmatory Thermal-Hydraulic Analysis to Support Specific Success Criteria in the Standardized Plant Analysis Risk Models-Duane Arnold, Appendices F to H
ML20300A240
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Issue date: 10/31/2020
From: Buell R, Shawn Campbell, Suzanne Dennis, Don Helton, Khatib-Rahbar M, Laura Kozak, Krail A, Jose Pires, Frederick Sock
Energy Research, Idaho National Lab, Office of Nuclear Regulatory Research
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NUREG-2236, Vol. 3
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NUREG-2236 Volume 3 Confirmatory Thermal-Hydraulic Analysis to Support Specific Success Criteria in the Standardized Plant Analysis Risk Models-Duane Arnold Appendices F to H Office of Nuclear Regulatory Research

AVAILABILITY OF REFERENCE MATERIALS IN NRC PUBLICATIONS NRC Reference Material Non-NRC Reference Material As of November 1999, you may electronically access Documents available from public and special technical NUREG-series publications and other NRC records at libraries include all open literature items, such as books, the NRCs Public Electronic Reading Room at journal articles, transactions, Federal Register notices, http://www.nrc.gov/readi ng-rm.html. Publicly released Federal and State legislation, and congressional reports.

records include, to name a few, NUREG-series Such documents as theses, dissertations, foreign reports publications; Federal Register notices; applicant, and translations, and non-NRC conference proceedings licensee, and vendor documents and correspondence; may be purchased from their sponsoring organization.

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The NRC Technical Library NRC publications in the NUREG series, NRC Two White Flint North regulations, and Title 10, Energy, in the Code of 11545 Rockville Pike Federal Regulations may also be purchased from one Rockville, MD 20852-2738 of these two sources.

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request as follows:

The NUREG series comprises (1) technical and U.S. Nuclear Regulatory Commission administrative reports and books prepared bythe staff Office of Administration (NUREG-XXXX) or agency contractors Multimedia, Graphics and Storage & Distribution Branch (NUREG/CR-XXXX), (2) proceedings of conferences Washington, DC20555-0001 (NUREG/CP-XXXX), (3) reports resulting from E-mail: distribution.resource@nrc.gov international agreements (NUREG/IA-XXXX), (4) brochures (NUREG/BR-XXXX), and (5) compilations of Facsimile: (301) 415-2289 legal decisions and orders of the Commission and Atomic and Safety Licensing Boards and of Directors Some publications in the NUREG series that are decisions under Section 2.206 of NRCs regulations posted at the NRCs Web site address (NUREG-0750).

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found on a Web site bear the date the material was Neither the U.S. Government nor any agency thereof, nor any employee, makes anywarranty, expressed or implied, accessed, the material available on the date cited or assumes anylegal liabilityor responsibilityfor any third may subsequently be removed from thesite. partys use, or the results of such use, of any information, apparatus, product, or process disclosed in this publication, or represents that its use by such third party would not infringe privately owned rights.

SR-CR 10/2017

NUREG-2236 Volume 3 Confirmatory Thermal-Hydraulic Analysis to Support Specific Success Criteria in the Standardized Plant Analysis Risk Models-Duane Arnold Appendices F to H Manuscript Completed: May 2019 Date Published: October 2020 Prepared by:

S. Campbell,1 S. Dennis,1 D. Helton,1 L. Kozak,1 J. Pires,1 F. Sock1 M. Khatib-Rahbar,2 A. Krall2 R. Buell3 U.S. Nuclear Regulatory Commission1 Energy Research, Inc.2 P.O. Box 2034 Rockville, MD 20847 Idaho National Laboratory3 P.O. Box 1625 Idaho Falls, ID 83415 Office of Nuclear Regulatory Research

ABSTRACT This report extends the work documented in NUREG-2187, Confirmatory Thermal-Hydraulic Analysis to Support Specific Success Criteria in the Standardized Plant Analysis Risk Models Byron Unit 1, issued January 2016, to the Duane Arnold Energy Center. Its purpose is to produce an additional set of best estimate thermal-hydraulic calculations that can confirm or enhance specific success criteria for system performance and operator timing found in the agencys probabilistic risk assessment tools. Along with enhancing the technical basis for the agencys independent standardized plant analysis risk (SPAR) models, these calculations are expected to be a useful reference to model end users for specific regulatory applications.

This report first describes major assumptions used in this study. It then discusses the major plant characteristics for the Duane Arnold Energy Center, in addition to the MELCOR model used to represent the plant. Finally, the report presents the results of MELCOR calculations for selected initiators and compares these results to SPAR success criteria, the licensees success criteria, or other generic studies.

The study results provide additional timing information for several probabilistic risk assessment sequences, confirm many of the existing SPAR modeling assumptions, and give a technical basis for a few specific SPAR modeling changes, including the following potential changes:

  • Degraded high-pressure injection and relief valve Criteria (non-anticipated transient without scram): A single control rod drive pump injecting at the postscram increased injection rate is sufficient for reactor pressure vessel (RPV) water inventory makeup.

Additionally, two control rod drive pumps injecting at the postscram injection rateprovide enough makeup to the RPV to facilitate a cooldown of the RPV to cold shutdown conditions. This increased injection is currently not queried in the SPAR models but could be added.

  • Mitigating strategies usage: If diverse and flexible coping strategies (FLEX) are not available, success of long-term cooling for these scenarios is only possible with both anticipatory venting and condensate storage tank (CST) availability. Currently, CST availability is not queried in the SPAR models. This could be added for scenarios for which no alternate injection is available. For loss-of-offsite-power scenarios, FLEX injection led to success in all scenarios that gave FLEX credit. Given the ability of FLEX to prevent core damage, this confirms that the SPAR models should have FLEX equipment added.

Depending upon the size of containment failure, wetwell and drywell pressure will fall, potentially to the point of allowing high-pressure injection restart following its loss. This action could be added to the SPARmodels.

  • Safe and stable end-state considerations: If the CST is unavailable, the long-term availability of high-pressure injection is questionable at best. CST should be queried when high-pressure injection systems are the source of long-term makeup. Additionally, increased postscram control rod drive hydraulic system injection is adequate for makeup. This increased injection is a candidate for inclusion in the SPAR model.

Depressurizing when reaching the heat capacity limit curve is important, since the rate of iii

seal leakage, as well as the rate of injection, is pressure dependent. This depressurization is a candidate for consideration in the SPAR models.

iv

FOREWORD The U.S. Nuclear Regulatory Commission (NRC) uses its standardized plant analysis risk (SPAR) models to support many risk-informed initiatives. A number of processes ensure the fidelity and realism of these models, including cross-comparison with industry models, review and use by a wide range of technical experts, and confirmatory analysis. This reportprepared by the staff of the Office of Nuclear Regulatory Research, in consultation with the staff of the Office of Nuclear Reactor Regulation; experts from Energy Research, Inc. and Idaho National Laboratory; and the agencys senior reactor analystsrepresents a major confirmatory analysis activity.

Probabilistic risk assessment (PRA) models for nuclear power plants rely on underlying modeling assumptions known as success criteria and sequence timing assumptions. These criteria and assumptions determine what combination of system and componentavailabilities will lead to postulated core damage, as well as the timeframes during which components must operate or operators must take particular actions. This report investigates certain thermal- hydraulic aspects of a particular SPAR model (which is generally representative of other models within the same class of plant design), with the goal of further strengthening the technical basis for decisionmaking that relies on the SPAR models. This report augments the existing collection of contemporary Level 1 PRA success criteria analyses and, as such, supports (1) maintaining and enhancing the SPAR models that the NRC develops, (2) supporting the NRCs risk analysts when addressing specific issues in the accident sequence precursor program and the significance determination process, and (3) informing other ongoing and planned initiatives. This analysis employs the MELCOR computer code and uses a plant model developed for this project.

The analyses summarized in this report provide the basis for confirming or changing success criteria in the SPAR model for the Duane Arnold Energy Center. Based on further evaluation, these results could apply to similar plants, while future analyses could apply to other design classes, as occurred in the past (see NUREG-2187, Confirmatory Thermal-Hydraulic Analysis to Support Specific Success Criteria in the Standardized Plant Analysis Risk ModelsByron Unit 1, issued January 2016). The staff expects to continue its focus on confirming success criteria and other aspects of PRA modeling using its state-of-the-art tools (e.g., the MELCOR computer code) as it develops and improves its risk tools.

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TABLE OF CONTENTS ABSTRACT .................................................................................................................................... iii FOREWORD .................................................................................................................... v LIST OF FIGURES .......................................................................................................... ix LIST OF TABLES............................................................................................................ xi ACKNOWLEDGMENTS ................................................................................................xiii ABBREVIATIONS AND ACRONYMS ........................................................................... xv 1 BACKGROUND........................................................................................................ 1-1 1.1 Confirmatory Success Criteria Project ............................................................................. 1-1 1.2 Hazard, Mode, and Radiological Source Scope .............................................................. 1-2 1.3 Issues To Be Investigated ............................................................................................... 1-2 1.4 Plant Selection ................................................................................................................ 1-3 2 MAJOR ASSUMPTIONS AND PEER REVIEW DESCRIPTION............................... 2-1 2.1 Major Assumptions .......................................................................................................... 2-1 2.2 Description of the DAEC MELCOR Model ....................................................................... 2-3 2.3 Shakedown and Benchmarking of the DAEC MELCOR Model ....................................... 2-7 2.3.1 Steady State ...................................................................................................... 2-7 2.3.2 Comparison to Select Licensing-Basis Analysis ................................................ 2-8 2.3.3 Application of the Baseline SmallLoss-of-Coolant-Accident Sequence ............ 2-8 2.3.4 Application of the Baseline FLEX Sequence ................................................... 2-11 2.3.5 Application of a Baseline Station Blackout Sequence ..................................... 2-18 2.3.6 Updated Shakedown Based upon Latest Deck Revision................................. 2-24 3 SUCCESS CRITERIA FOR SITUATIONS WITH DEGRADED HIGH-PRESSURE INJECTION AND RELIEF VALVE CRITERIA FOR NON-ANTICIPATED TRANSIENT WITHOUT SCRAM.................................................................................... 3-1 3.1 Issue Description ............................................................................................................. 3-1 3.2 Transient Sequence ........................................................................................................ 3-3 3.2.1 Calculation Matrix Development ........................................................................ 3-3 3.2.2 MELCOR Simulation Results............................................................................. 3-7 3.3 Small Loss-of-Coolant Accident Sequence........................................................................... 3-11 3.3.1 Calculation Matrix Development ....................................................................... 3-11 3.3.2 MELCOR Simulation Results............................................................................3-13 3.4 Conclusions Drawn from MELCOR Results ................................................................... 3-16 4 MITIGATING STRATEGIES (FLEX) USAGE IN LOSS-OF-ALTERNATING-CURRENT-POWER SCENARIOS ............................................................................. 4-1 4.1 Issue Description .............................................................................................................. 4-1 4.1.1 DAEC Post-Fukushima Actions Related to Mitigating Strategies........................ 4-2 4.1.2 The Scenario Assumed for Mitigating Strategies Formulation ............................ 4-2 4.1.3 DAEC Plant Modifications To Comply with the Post-Fukushima Orders ............ 4-4 4.2 Station Blackout Sequence .............................................................................................. 4-6 4.2.1 Calculation Matrix Development .........................................................................4-6 vii

4.2.2 MELCOR Simulation Results ...........................................................................4-10 4.3 Loss-of-Main-Feedwater Sequence ...............................................................................4-14 4.3.1 Calculation Matrix Development ....................................................................... 4-14 4.3.2 MELCOR Simulation Results ........................................................................... 4-18 4.4 Conclusions Drawn from MELCOR Results ................................................................... 4-22 5 EMERGENCY CORE COOLING SYSTEM INJECTION FOLLOWING CONTAINMENT FAILURE OR VENTING ................................................................. 5-1 5.1 Issue Description ............................................................................................................. 5-1 5.2 Station Blackout Sequence ............................................................................................. 5-3 5.2.1 Calculation Matrix Development ........................................................................ 5-3 5.2.2 MELCOR Simulation Results ............................................................................5-5 5.3 Loss-of-Main-Feedwater Scenario ................................................................................5-10 5.3.1 Calculation Matrix Development ...................................................................... 5-10 5.3.2 MELCOR Simulation Results .......................................................................... 5-12 5.4 Conclusions Drawn from MELCOR Results .................................................................. 5-16 6 SAFE AND STABLE END-STATE CONSIDERATIONS .......................................... 6-1 6.1 Issue Description .............................................................................................................6-1 6.2 Station Blackout Sequence ............................................................................................. 6-2 6.2.1 Calculation Matrix Development ........................................................................6-2 6.2.2 MELCOR Simulation Results ........................................................................... 6-4 6.3 Loss-of-Main-Feedwater Scenario ..................................................................................6-7 6.3.1 Calculation Matrix Development ........................................................................6-7 6.3.2 MELCOR Simulation Results............................................................................ 6-8 6.4 Conclusions Drawn from MELCOR Results ..................................................................6-11 7 APPLICATION OF MELCOR RESULTS TO SPAR MODEL.................................... 7-1 8 CONCLUSIONS ....................................................................................................... 8-1 9 REFERENCES ......................................................................................................... 9-1 APPENDIX A MELCOR VERSIONS.......................................................................... A-1 APPENDIX B CONTAINMENT VENTING.................................................................. B-1 APPENDIX C CHAPTER 3 FIGURES ......................................................................... C-1 APPENDIX D CHAPTER 4 FIGURES......................................................................... D-1 APPENDIX E CHAPTER 5 FIGURES ......................................................................... E-1 APPENDIX F GRADUAL OVERPRESSURE FAILURE MODES AND LOCATIONS IN MARK I, MARK II, AND MARK III CONTAINMENT SYSTEMS .................................................................. F-1 APPENDIX G CHAPTER 6 FIGURES ..........................................................................G-1 APPENDIX H EVENT TREES ..................................................................................... H-1 viii

LIST OF FIGURES Figure 2-1 Recirculation Line Coolant Temperature during Controlled Depressurization of the RCS ....................................................................................................................2-14 Figure 2-2 RPV Pressure (Case 1) ......................................................................................... 2-16 Figure 2-3 RCIC Flow (Case 1) .............................................................................................. 2-16 Figure 2-4 Drywell Pressure (Case 1) .................................................................................... 2-17 Figure 2-5 Wetwell Water Temperature (Case 1) ................................................................... 2-17 Figure 2-6 FLEX Pump Flow (Case 1) ................................................................................... 2-18 Figure 2-7 Wetwell Water Temperature (NRC) ......................................................................2-22 Figure 2-8 Containment Pressure (NRC) ...............................................................................2-22 Figure 2-9 Vessel Water levels (NRC) ...................................................................................2-23 Figure 2-10 FLEX Pump Flow (NRC) ...................................................................................... 2-23 Figure 2-11 RPV Pressure (Case 1, Updated) ........................................................................ 2-25 Figure 2-12 RCIC Flow (Case 1, Updated).............................................................................. 2-25 Figure 2-13 Drywell Pressure (Case 1, Updated) .................................................................... 2-26 Figure 2-14 Wetwell Water Temperature (Case 1, Updated) .................................................. 2-26 Figure 2-15 FLEX Pump Flow (Case 1, Updated) ................................................................... 2-27 ix

LIST OF TABLES Table 1-1 Major Plant Characteristics for DAEC .................................................................... 1-3 Table 2-1 Major Assumptions in the MELCOR Calculations .................................................. 2-1 Table 2-2 Structures Included in the DAEC MELCOR Model................................................. 2-3 Table 2-3 Systems Included in the DAEC MELCOR Model ................................................... 2-4 Table 2-4 Other Components Included in the DAEC MELCOR Model ................................... 2-5 Table 2-5 Operator Action Surrogates Included in the DAECMELCOR Model ...................... 2-5 Table 2-6 Default MELCOR Modeling Values ........................................................................ 2-5 Table 2-7 Comparison of MELCOR-Predicted Steady-State to Plant Conditions ................... 2-7 Table 2-8 Boundary Conditions for LOOP/SLOCAValidation Calculation .............................. 2-9 Table 2-9 Boundary Conditions for the FLEX Validation ...................................................... 2-13 Table 2-10 Boundary Conditions for the SBO Validation........................................................ 2-14 Table 2-11 Timing of Important Events for SBO Validation .................................................... 2-20 Table 3-1 PRA Sequences of Interest for DepressurizationTRANS ................................... 3-4 Table 3-2 Calculation MatrixHPI and SRV Criteria for Non-ATWSTRANS...................... 3-4 Table 3-3 Initial and Boundary ConditionsHPI and SRV Criteria for Non-ATWS TRANS ..................................................................................................................3-5 Table 3-4 Timing of Significant Events and the Maximal Peak Cladding Temperature Reached in the TRANS-30 with NominalCRDHS Injection ...................................3-8 Table 3-5 Sensitivity Study MatrixHPI and SRV Criteriafor Non-ATWS ...........................3-10 Table 3-6 PRA Sequences of Interest for DepressurizationSLOCA ................................. 3-11 Table 3-7 Calculation MatrixHPI and SRV Criteria for Non-ATWSSLOCA ................... 3-12 Table 3-8 Initial and Boundary ConditionsHPI and SRV Critera for Non-ATWS SLOCA................................................................................................................. 3-12 Table 3-9 Timing of Significant Events and the Maximal Peak Cladding Temperature Reached in the 1.8-Inch Recirculation Line SLOCA Cases ..................................3-14 Table 3-10 Sensitivity Study MatrixHPI and SRV Criteriafor Non-ATWS ........................... 3-15 Table 4-1 SBO Sequence of Interest for FLEX-Based Diverse Injection ................................ 4-6 Table 4-2 Calculation MatrixMitigating StrategiesSBO ................................................... 4-7 Table 4-3 Initial and Boundary ConditionsMitigating StrategiesLOOPGR ..................... 4-10 Table 4-4 LOOPGR Results................................................................................................. 4-10 Table 4-5 Sensitivity Study MatrixMitigating StrategiesSBO ......................................... 4-13 Table 4-6 LOMFW Sequence of Interest for FLEX-Based Diverse Injection .........................4-15 Table 4-7 Calculation MatrixMitigating StrategiesLOMFW-25 ....................................... 4-15 xi

Table 4-8 Initial and Boundary ConditionsMitigating StrategiesLOMFW ......................... 4-17 Table 4-9 LOMFW Results and Key Timings ......................................................................... 4-18 Table 4-10 Sensitivity StudyMatrixMitigating StrategiesLOMFW ...................................... 4-20 Table 5-1 Calculation MatrixECCS InjectionSBO Sequence ............................................ 5-3 Table 5-2 Initial and Boundary ConditionsECCS InjectionSBO Sequence.......................... 5-5 Table 5-3 LOOPGR Results .................................................................................................... 5-5 Table 5-4 Sensitivity Study MatrixECCS InjectionSBO Sequence .................................... 5-8 Table 5-5 Calculation MatrixECCS InjectionLOMFW Sequence..................................... 5-10 Table 5-6 Initial and Boundary ConditionsECCSInjectionLOMFW Sequence ................ 5-11 Table 5-7 LOMFW Results .................................................................................................... 5-12 Table 5-8 Sensitivity Study MatrixECCS InjectionLOMFW Sequence ............................ 5-14 Table 6-1 Calculation MatrixSafe and StableSBO Sequence ........................................... 6-2 Table 6-2 Initial and Boundary ConditionsSafe and StableSBO Sequence ...................... 6-4 Table 6-3 LOOPGR Results .................................................................................................... 6-4 Table 6-4 Sensitivity Study MatrixSafe and StableSBO Scenario. .................................... 6-6 Table 6-5 Calculation MatrixSafe and StableLOMFW Sequence ..................................... 6-7 Table 6-6 Initial and Boundary ConditionsSafe and StableLOMFW Sequence ................ 6-8 Table 6-7 LOMFW Results ...................................................................................................... 6-9 Table 6-8 Sensitivity Study MatrixSafe and StableLOMFW Scenario ............................. 6-10 Table 7-1 Mapping of MELCOR Analyses to the DAEC SPAR(8.50) Model ........................... 7-1 Table 7-2 Potential Success Criteria Updates Based on DAEC Result .................................... 7-2 xii

ACKNOWLEDGMENTS This report is the result of the efforts of many members of the U.S. Nuclear Regulatory Commission staff and the staff of its contractors, Energy Research, Inc., and Idaho National Laboratory. Furthermore, the report benefited greatly from the contributions of senior risk analysts and other selected agency staff members in specific areas of the project. The authors would especially like to recognize the support from Mahesh Chawla, James Corson, Ron Harrington, Tarek Zaki, and Joseph Staudenmeier. The authors also appreciate the assistance provided by the licensees staff at the Duane Arnold Energy Center.

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ABBREVIATIONS AND ACRONYMS ac alternating current ADAMS Agencywide Documents Access andManagement System ADS automatic depressurization system AIP alternate injection procedure (EOP)

ANS American Nuclear Society AOP abnormal operating procedure ASP accident sequence precursor ATWS anticipated transient without scram BWR boiling-water reactor C Celsius CD core damage CDF core damage frequency CDS condensate system CFR Code of Federal Regulations CRDHS control rod drive hydraulic system CST condensate storage tank DAEC Duane Arnold Energy Center dc direct current ECCS emergency core cooling system ED emergency depressurization EDG emergency diesel generator ELAP extended loss of ac power EOP emergency operating procedure ESF engineered safety feature ESFAS engineered safety features actuation system F Fahrenheit FLEX diverse and flexible copingstrategies FSG FLEX support guideline HCL heat capacity limit HCV hardened containment vent HCVS hardened containment vent system HPCI high-pressure coolant injection HPI high-pressure injection IORV inadvertent open relief valve IPE individual plant examination ISG interim staff guidance LCO limiting condition for operation LOCA loss-of-coolant accident LOCHS loss of condenser heat sink xv

LODCA loss of vital dc bus A LODCB loss of vital dc bus B LOIAS loss of instrument air system LOMFW loss of main feedwater LOOP loss of offsite power LOOPGR loss of offsite power grid related LOOPPPC loss of offsite power plant centered LOOPWR loss of offsite power weather related LORWS loss of river water system LPCI low-pressure coolant injection LPCS low-pressure core spray LPI low-pressure injection MAAP modular accident analysis program MFW main feedwater MLOCA medium loss-of-coolant accident MSIV main steam isolation valve MSL main steamline NCV noncited violation NEI Nuclear Energy Institute NPSH net positive suction head NRC U.S. Nuclear Regulatory Commission PB Peach Bottom PCPL primary containment pressure limit PCS power conversion system PCT peak clad temperature PID proportional-integral-derivative PRA probabilistic risk assessment RCIC reactor core isolation cooling RCS reactor coolant system RHR residual heat removal RPS reactor protection system RPV reactor pressure vessel RWCU reactor water cleanup SAMP severe accident management procedure SBO station blackout SC success criterion/criteria SDP significance determination process SEP site emergency plan SFP spent fuel pool SLC standby liquid control SLOCA small loss-of-coolant accident xvi

SNL Sandia National Laboratories SP suppression pool SPAR standardized plant analysis risk SRV safety/relief valve TAF top of active fuel TRANS transient UFSAR updated final safety analysis report UHS ultimate heat sink WW wetwell xvii

APPENDIX F GRADUAL OVERPRESSURE FAILURE MODES AND LOCATIONS IN MARKI, MARK II, AND MARK III CONTAINMENT SYSTEMS

GRADUAL OVERPRESSURE FAILURE MODES ANDLOCATIONS IN MARK I, MARK II, AND MARK III CONTAINMENT SYSTEMS F.1 INTRODUCTION This appendix is an extensive review of several documents, such as individual plant examination (IPE) reports, NUREGs, and final safety analysis reports (UFSARs) prepared for boiling-water reactors with Mark I, II, and III containment types, to determine how these types of containments will respond to gradual internal, long-term pressure.

The evaluation of these responses to such pressure includes determining the types of failures that will occur and the location of such failures, as well as the leakage rate associated with each failure type.

This review of existing studies, reports, and other documents excludes the effects of rapid pressurization and depressurization of the primary containment and assumes core melt has not occurred.

F.2 REFERENCES

1. U.S. Nuclear Regulatory Commission (NRC), NUREG/CR-6906, Containment Integrity Research at Sandia National LaboratoriesAn Overview, July2006.
2. Iowa Electric Light & Power Co., Duane Arnold Energy Center, Individual Plant Examination (IPE), November 1992.
3. Philadelphia Electric Company, Peach Bottom Atomic Power Station Units 2 and 3, Individual Plant ExaminationVolumes 1 and 2, August1992.
4. Carolina Power & Light Company, Brunswick Steam Electric Plant Units 1 and 2, Individual Plant ExaminationVolumes 1 and 2, August1992.
5. Boston Edison Company, Pilgrim Nuclear Power Station Units 2 and 3, Individual Plant Examination for Internal Events Per GL-88-20, September 1992.
6. Tennessee Valley Authority, Browns Ferry Nuclear Plant Unit 2 Probability Risk Assessment, Individual Plant Examination Volumes 1, 2 and 3, September 1992.
7. Public Service Electric and Gas Company., Hope Creek Generating Station,Individual Plant Examination, April 1994.
8. Philadelphia Electric Company, Limerick Generating Station Units 1 & 2,Individual Plant Examination, July 1992.
9. Washington Public Power Supply System Report No: WPPSS-FTS-133 Revision 1, Individual Plant Examination, July 1994.
10. Pennsylvania Power & Light Company, Susquehanna Steam Electric Station,Report No. NPE-91-001, Individual Plant ExaminationVolume 3, December 1991.

F-1

11. Niagara Mohawk Power Corporation, Nine Mile Point Nuclear StationUnit 2, Individual Plant Examination (IPE), July 1992.
12. Illinois Power Company, Clinton Power Station, Individual Plant Examination Final Report, September 1992.
13. Entergy Operations, Inc., Grand Gulf Nuclear Station, Individual Plant Examination Summary Report, December 1992.
14. The Cleveland Electric Illuminating Co., Perry Nuclear Power Plant, Individual Plant Examination, July 1992.
15. Gulf States Utilities, River Bend Station, Individual Plant ExaminationVolume 2 of 2, January 1993.

F.3 DISCUSSION F.3.1 Mark I Containments The Mark I containments can be divided into two groups, as summarized in Table 3 of NUREG/CR-6906, Containment Integrity Research at Sandia National LaboratoriesAn Overview, issued July 2006 (Reference 1); namely, a freestanding steel primary containment or a reinforced concrete primary containment with a steel liner. As described in References 2 through 7, both of these Mark I containments are pressure-suppression containment systems, consisting of a primary and a secondary containment. These two containment structures house the reactor pressure vessel, the reactor recirculation loops, and other branch connections of the reactor coolant system; a pressure suppression chamber; a vent system connecting the drywell and the pressure suppression chamber; isolation valves; containment cooling systems; and other service equipment.

The primary containment structure is a low-leakage, pressure-suppression containment system; in the event of a primary system pipe failure within the drywell, a mixture of drywell atmosphere and steam would be forced through the vents into the suppression pool, resulting in steam condensation and pressure reduction. The two major structural components of the primary containment system are the drywell and the suppression chamber (wetwell). Both the drywell and pressure suppression chamber are designed for an internal pressure range of 0.39-0.43 MPa (56-62 pounds per square inch, gauge (psig)), coincident with a temperature of 138 degrees Celsius (C) (281 degrees Fahrenheit (F)).

The secondary Mark I containment has several configurations. In some Mark I containments, the secondary containment building is used to house support systems, whereas in others, the secondary containment system consists of four subsystems: the reactor building, the reactor building isolation and control system, the standby gas treatment system, and the off-gas stack.

In all cases, the secondary containment building is designed to provide secondary containment when the primary containment is operable and when the primary containment is open. The secondary containment system is designed to be sufficiently leak-tight to allow the standby gas treatment system to maintain the reactor building at a subatmospheric pressure of 0.64 centimeters (0.25 inches) of water when the standby gas treatment system is exhausting F-2

reactor building atmosphere.

F.3.1.1 Primary Containment Ultimate Capability The following discusses containment ultimate capabilities under sustained overpressure and various temperature levels. The work presented in this section is based on the analyses performed by Chicago Bridge and Iron (CB&I) and detailed in Reference 2 for Duane Arnold and in Reference 3 for Peach Bottom, a similar Mark I containment. References 4 through 7 represent other reviewed documents.

Before the publication of the IPE reports for Duane Arnold and Peach Bottom, Mark I containment performance was evaluated for high-pressure and low-temperature conditions.

References 2 and 3 reviewed a significant body of studies, including the work done by CB&I, and grouped their findings in the following three categories related to internal pressure:

(1) containment capability at low temperature (below 260 degrees C [500 degrees F])

(2) containment capability at intermediate temperature (between 260 degrees C

[500 degrees F] and 427 degrees C [800 degrees F])

(3) containment capability at high temperatures (above 482 degrees C [900 degreesF])

F.3.1.2 Containment Failure Sizes The referenced IPE reports define primary containment failure sizes as belonging to three ranges:

(1) negligible failure (intact)a failure resulting in a small leak rate that equates to an equivalent cross-sectional area leak of slightly less than 3.14 square inches (in2)

(2) small failurea failure causing a leak emanating from an opening that is estimated to have a cross-sectional area between 3.14 in2 and 1.0 square feet (ft2)

(3) large failurea failure creating a hole that is greater than 1.0 ft2insize F.3.1.3 Containment Capability at Low Temperature (below 260 degrees C [500 degrees F])

References 2 and 3 both show that extensive review of Mark I containment evaluations concludes that, for temperatures below 171 degrees C (340 degrees F), a reasonable assessment of the mean containment pressure capability is 0.97 MPa (140 psig). The following are some of the general conclusions about low-temperature (i.e., less than 171 degrees C

[340 degrees F]) containment performance that could be drawn from the many studies reviewed:

  • The ultimate pressure capability of the Mark I containment is two to three times greater than the design pressure.
  • The most probable containment failure modes as a result of pressurization (aspressure exceeds 0.97 MPa (140 psig) but temperature is still less than 171 degreesC

[340 degrees F]) are (1) a rupture (ductile tear) in the wetwell airspace, (2) a rupture (ductile tear) in the wetwell water space, or (3) a break in the drywell head.

F-3

  • These failure sizes are considered negligible (containment integrity is maintained),

defined in References 2 and 8 as an opening with a diameter less than 5.1 centimeters (2 inches) (or an area of 3.14 in2).

Review of the IPE reports listed in References 2 through 7 leads to a general conclusion that, for temperatures below 171 degrees C (340 degrees F), a reasonable assessment of the mean Mark I containment pressure capability is 0.97 MPa (140 psig). As stated above, as the pressure exceeds this limit, material yielding in the wetwell airspace begins, resulting in tearing in the wetwell shell (wetwell airspace). Leakage through the drywell closure head could begin about the same time or a bit later than the time that the tearing in the wetwell shell starts.

Leakage through the vent line bellows could also happen as the pressure increased beyond the 0.97-MPa (140-psig) limit. As these failure sizes increase, depressurization of the containment will begin.

F.3.1.4 Containment Capability at Intermediate Temperature (between 260 degrees C

[500 degrees F] and 427 degrees C [800 degrees F])

In this intermediate temperature range, the reduction in material strength and seal properties degrades the containment pressure capability. Seals are used around containment penetrations and around the drywell closure head. Based on the review of several studies, analysts concluded that primary containment failure in the 260-degree-C (500-degree F) to 427-degree-C (800-degree-F) range would occur at a pressure range of 0.43 to 0.61 MPa (63 to 88 psig),

dominated by the drywell head seal failure and opening of the drywell flange. This failure is described in Reference 2, as a leakage dominated failure mode, which means that it is a small failure of approximately 18 in2 to 19.5 in2.

The probabilities of other failure modes at these drywell temperatures and pressures were substantially less. For example, other containment penetrations were also examined as part of the review of the Pilgrim study detailed in Reference 5. Penetrations located in the torus (wetwell) were excluded since the temperature there was expected to be significantly lower than that in the drywell during severe accident conditions. Other penetrations, such as personnel airlock, equipment hatch, and electrical penetration, were shown to have very durable seals that could withstand temperatures of at least 371 degrees C (700 degrees F) and would not deteriorate before significant degradation of the drywell closure head seal.

F.3.1.5 Containment Capability at High Temperature (above 482 degrees C [900 degrees F])

Based on computer analyses for accidents in which core melt has occurred, there is very little confidence that the containment can withstand such high temperatures without significant material degradation. Based on the results of the studies performed by the Industry Degraded Core Rulemaking Program (as described in Section 4.4 of References 2 and 3), and by CB&I for Duane Arnold, the general conclusion is that containment strength becomes suspect at temperatures that exceed 482 degrees C (900 degrees F), and the drywell would fail under any appreciable pressure load at this temperature.

F.3.1.6 Summary and Conclusions A detailed review of the IPE reports in References 2 through 7 leads to the following three conclusions about the Mark I containment failure characterization:

(1) for drywell temperatures below 260 degrees C (500 degreesF):

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  • The mean ultimate pressure capability of the Mark I containment isabout 0.97 MPa (140 psig), and it is two to three times greater than the design pressure of 0.39 MPa (56 psig).
  • The most probable containment failure modes caused by pressurization (as pressure exceeds the design pressure but temperature is still lessthan 171 degrees C [340 degrees F]) are (1) a rupture (ductile tear) in the wetwell airspace, (2) a rupture (ductile tear) in the wetwell water space, or (3) a break in the drywell closure head. The leakage rate is considered negligible (an opening with a cross-sectional area less than 3.14 in2).

(2) for drywell temperatures between 260 degrees C (500 degrees F) and 427 degrees C (800 degrees F):

  • Primary containment failure in the drywell temperature range of 260 degrees C (500 degrees F) to 427 degrees C (800 degrees F) was estimated to occur at a pressure range of 0.43 to 0.61 MPa (63 to 88 psig), dominated by the drywell head seal failure and opening of the drywell flange. This failure is described asa leakage dominated failure mode, which means that it is a small failure of approximately 18 in2 to 19.5 in2.

(3) at high drywell temperature (e.g., above 482 degrees C [900 degrees F]):

  • Computer analyses for accidents in which core melt has occurred demonstrate that there is very little confidence that the containment can withstand such high temperatures without significant material degradation. The general conclusions are that the strength of the containment becomes suspect at temperatures that exceed 482 degrees C (900 degrees F), and the primary containment would fail under any appreciable pressure load at thistemperature.

F.3.2 Mark II Containments The Mark II primary containment is also a pressure-suppression containment system, as described in References 8 through 11, which houses the reactor pressure vessel, the reactor recirculation loops, and other branch connections of the reactor coolant system. The reactor enclosure exterior walls, roof, floor, and penetrations form the secondary containment. The primary containment of the Columbia plant (Reference 9) consists of a freestanding steel structure housing a steel drywell and wet well, whereas the primary containments of the Limerick, Susquehanna, and Nine Mile Point Unit 2 plants (References 8, 10, and 11) are made from reinforced concrete with steel liner plate and both the drywell and wetwell are reinforced concrete structures. Like the Mark I containment, the two major structural components of the Mark II primary containment system are the drywell and the suppression chamber (wetwell).

Both the drywell and pressure suppression chamber are designed for an internal pressure range of 0.31 to 0.38 MPa (45 to 55 psig), coincident with a temperature of 171 degrees C (340 degrees F) for the drywell and a range of 104 degrees C (220 degrees F) to 132 degrees C (270 degrees F) for the suppression chamber.

The Mark II secondary containment has several configurations. Although some Mark II secondary containments are very compartmentalized, in general, the secondary containment F-5

includes both the reactor enclosure and the refueling area. Blowout panels in the side of the reactor enclosure are designed to relieve excessive pressure in the building.

F.3.2.1 Primary Containment UltimateCapability Based on the information in References 8 through 11, the following discusses the three categories of the effect of temperature and pressure on the ultimate capabilities of the three categories of Mark II primary containments:

(1) containment capability at low temperature (below 204 degrees C [400 degrees F])

(2) containment capability at intermediate or moderate temperature(between 204 degrees C [400 degrees F] and 482 degrees C [900 degrees F])

(3) containment capability at high temperatures (above 482 degrees C [900 degreesF])

As stated in NUREG/CR-6906 (Reference 1), failure size is one of the critical factors in the characterization of containment performance. The referenced IPE studies identified three possible failure sizes:

(1) a leaka containment breach (typically a cross-sectional area of 0.1 ft2) that would arrest a gradual pressure buildup but would not result in containment depressurizationin less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> (2) a rupturea containment breach (corresponding to a hole size in excess of approximately 1.0 ft2) that would arrest a gradual pressure buildup and would result in containment depressurization within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> (3) a catastrophic rupturea containment breach that results in the loss of a substantial portion of the containment boundary, including major penetrations attached to the containment wall F.3.2.2 Containment Capability at Low Temperature (below 204 degrees C [400 degrees F])

An extensive review of the IPEs (References 8 through 11) showed that the structural behavior of the typical Mark II containments under low temperatures tends to be consistent. For temperatures below 204 degrees C (400 degrees F), a reasonable assessment of the structural capability of the containment at low temperature exceeded pressures of 0.83 MPa (120 psig) and probably 0.97 MPa (140 psig).

The most probable containment failure modes caused by pressurization (as pressure exceeds 0.97 MPa (140 psig) but temperature is still less than or equal to 171 degrees C

[340 degrees F]) are (1) a rupture (ductile tear) in the wetwell airspace, (2) a rupture (ductile tear) in the equipment hatch, or (3) a break in the drywell head. These failures are defined as leak-before-break failures, where failure will first occur as tearing of limited size that progressively increases to gross failure as pressure increases towards the 171-degree C (340-degree F) level. The dominant failure modes at these temperatures (about 171 degrees C

[340 degrees F]) and pressure (about 0.97 MPa [140 psig]) were leakage caused by rupture in the wetwell below the waterline and rupture in the drywell head seal.

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F.3.2.3 Containment Capability at Intermediate or Moderate Temperature(between 204 degrees C [400 degrees F] and 482 degrees C [900 degrees F])

In this intermediate temperature range, the containment pressure capability is degraded by the reduction in material strength and properties of the seal used around containment penetrations and around the drywell closure head. Based on the review of several studies, analysts concluded that primary containment failure in the drywell temperature range of 204 degrees C (400 degrees F) to 482 degrees C (900 degrees F) was estimated to occur at a pressure range of 0.41 to 1.26 MPa (60 to 138 psig), dominated by rupture in the wetwell below the water line and the drywell head seal failure and opening of the drywell flange. This failure of the drywell closure head seal is described in Reference 8 as a leakage dominated failure mode, which is equivalent to an opening of 14 in2 to 87 in2.

F.3.2.4 Containment Capability at High Temperature (above 482 degrees C [90 degrees F])

Computer analyses have calculated drywell temperatures above 482 degrees C (900 degrees F) for accidents in which core melt has occurred, the core has slumped into the drywell floor, and core debris cooling is unavailable. At such temperatures, other studies have postulated that the material (steel and concrete) properties may have changed sufficiently to cause containment structural degradation such that the integrity of the primary containment could not be maintained under any internal pressure. The general conclusion is that the strength of the containment becomes suspect at temperatures that exceed 482 degrees C (900 degrees F), and the primary containment will experience catastrophic rupture under any appreciable pressure load at this temperature.

F.3.2.5 Summary and Conclusions A detailed review of the IPE reports, listed in References 8 through 11, leads to the following three conclusions about the Mark II containment failure characterization:

(1) for temperatures below 204 degrees C (400 degrees F):

  • A review of the IPEs presented in References 8 through 11 concluded that the structural behavior of the typical Mark II containments under low temperatures tends to be consistent, and a reasonable assessment of the structuralcapability of the containment at low temperature exceeded pressures of 0.83MPa (120 psig) and probably 0.97 MPa (140 psig).
  • The dominant failure modes at these temperatures (about 171 degrees C

[340 degrees F]) and pressure (about 0.97 MPa [140 psig]) were leakage caused by rupture in the wetwell below the waterline and rupture in the drywell head seal, with the leakage area size as defined in the previoussection.

(2) for temperatures between 204 degrees C (400 degrees F) and 482 degrees C (900 degrees F):

  • In this intermediate temperature range, the primary containment pressure capability is degraded by the reduction in material strength and properties of the seal used around containment penetrations and around the drywell closure head.

Based on the review of several studies, analysts concluded thatprimary F-7

containment failure in the drywell temperature range of 204 degrees C (400 degrees F) to 482 degrees C (900 degrees F) would occur at a pressure range of 0.41 to 0.95 MPa (60 to 138 psig), dominated by rupture in the wetwell below the water line and the drywell head seal failure and opening of the drywell flange, equivalent to an opening of 14 in2 to 87 in2.

(3) at temperatures above 482 degrees C (900 degrees F):

  • Studies have suggested that, at drywell temperatures above 482 degrees C (900 degrees F), the material (steel and concrete) properties may havechanged sufficiently to cause containment structural degradation such that the integrity of the primary containment could not be maintained under any internal pressure, and the primary containment will experience catastrophic rupture under any appreciable pressure load at thistemperature.

F.3.3 Mark III Containments The IPEs listed in References 12 through 15 describe two types of Mark III primary containment.

Both are pressure-suppression containment systems, which house the reactor pressure vessel, the drywell, and the suppression pool (wetwell).

The primary containment of both Clinton (Reference 12) and Grand Gulf (Reference 13) consists of a right circular cylinder with a hemispherical domed roof and a flat base slab. The primary containment wall is constructed from reinforced concrete, completely lined with steel plate. The drywell is also a right circular cylinder located within and concentric to the steel-lined, reinforced-concrete containment. The drywell is designed for an internal pressure of 0.21 MPa (30 psig) coincident with an internal temperature of 166 degrees C (330 degrees F). The pressure suppression pool is located between the drywell weir wall and the containment wall.

Like the containment wall, it is designed for an internal pressure of 0.10 MPa (15 psig),

coincident with a temperature of 85 degrees C (185 degrees F) for the drywell and a temperature range of 104 degrees C (220 degrees F) to 132 degrees C (270 degrees F) for the suppression chamber.

The primary containment of both Perry (Reference 14) and River Bend (Reference 15) is a freestanding cylindrical steel containment vessel that encloses the drywell and the suppression pool (wetwell). The freestanding steel containment for both plants is designed for an internal pressure of 0.10 MPa (15 psig, coincident with an accident internal temperature of 85 degrees C (185 degrees F). The drywell of both of these plants is designed for an internal pressure range of 0.17 to 0.20 MPa (25 psig to 30 psig) with a coincident temperature of 166 degreesC (330 degrees F). Part of their pressure suppression pools is located inside the drywell, and the major parts are located outside the drywell between the outer drywell wall and the inner steel containment wall.

F.3.3.1 Primary Containment UltimateCapability References 12 through 15 did not consistently account for the effects of temperature and pressure on the ultimate capabilities of the Mark III containment, as was done in References 2 through 11 for the Mark I and II primary containments.

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The Perry IPE (Reference 14) did not explicitly consider the effects of temperature in determining the ultimate capacities of the primary containment boundary nor the drywell boundary. It noted the following, however:

  • Most applicable design codes required the design accident concrete surface temperatures to be below 177 degrees C (350 degrees F), after which the concrete starts to lose some of its strength. Section 8.0 of the Perry IPE (Reference 14) discusses the effects of high temperature on concrete, with Table 17, presented in the samereport, showing the impact on the compressive strength of concrete for temperatures ranging from 93 degrees C (200 degrees F) to 871 degrees C (1,600 degrees F) over a 48-hour exposure.
  • The strength of steel decreases linearly from its value at 21 degrees C (70 degrees F) to about 80 percent of this value at 427 degrees C (800 degrees F). In general, the strength of the reinforcing steel, part of the reinforced concrete, is more significant and thus the capacity of reinforced concrete will be impacted by the effects of high temperatures on steel.
  • The seals around the major penetrations in the containment and drywell, such as the personnel airlock, equipment hatches, and drywell head, are fabricated from ethylene propylene rubber, with a failure temperature of about 316 degrees C (600 degrees F),

but an inflated ethylene propylene seal has been known to fail atapproximately 241 degrees C (465 degrees F).

However, the River Bend IPE (Reference 15) evaluated the median pressure capacities for three temperature conditions: 21 degrees C (70 degrees F), 149 degrees C (300 degrees F),

and 427 degrees C (800 degrees F).

Containment Failure Definition and Sizes The failure characterization for the two types of Mark III containment is described (as expected) differently for the two cases.

Mark III Containments with a Reinforced Concrete Primary Containment with Steel Liner Unlike Mark II containments, the failure sizes associated with overpressurization of the Mark III containment with a reinforced concrete primary containment with steel liner were not well defined in IPE reports for Clinton (Reference 12) and Grand Gulf (Reference 13). To attribute a generalized size to the containment breach, the IPEs assumed failures of the containment shell or equipment hatch were gross failures or rupture (i.e., failures that were large enough to cause rapid depressurization of the containment). On the other hand, failure of the containment liner was considered a leakagefailure that would prevent further pressurization of the containment but allow for slow and gradual depressurization.

Mark III Containments with a Freestanding Steel Primary Containment For the Mark III containments with a freestanding steel primary containment, the failure pressures are defined as the pressure associated with mean yield stress in the structural components (even though higher pressures are possible, based on the ultimate strength of the materials). The Perry IPE (Reference 14) defined the failure sizes as belonging to three ranges:

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(1) leakagea containment breach, typically with a cross-sectional area of 0.1 ft2, that would result in containmentdepressurization (2) rupturea containment breach corresponding to a hole with an area from 0.1 ft2 to 7.0 ft2 that would result in containment depressurization (3) gross rupturea containment breach corresponding to a hole with an area greater than 7.0 ft2 River Bend (Reference 15) also has a freestanding steel primary containment and, asdescribed in its IPE report, failure modes associated with gross structural failure would result in rapid depressurization of the primary containment, and thus no leakage areas are estimated for these types of failures. For nonstructural failure modes, leakage associated with these modes could be described as follows:

  • insignificant leakage area
  • leakage area less than or equal to 12 in2
  • leakage area between 12 in2 and 32 in2 Containment Capability at Various Temperatures Mark III Containment with a Reinforced Concrete Primary Containment with Steel Liner Clinton and Grand Gulf are the two power stations that have the Mark III containment with a reinforced concrete primary containment with steel liner.

As stated in Section 4.4.9 of the Clinton IPE (Reference 12), the primary containment would have a 50-percent probability of failure at 0.647 MPa (93.8 psig), with the likely failure mode being tearing of the steel liner in the vicinity of one of the major containment penetrations (such as the personnel airlocks or the equipment hatches). The personnel airlocks and equipment hatches have higher capacities that the steel liner surrounding them. As the pressure increases, failure of the containment shell (hoop rebar) will occur around midheight, at significantly higher pressure. Finally, approximately 14 percent of the failures in the liner will occur below the Water level in the suppression chamber and the rest will occur above the Water level.

The Grand Gulf IPE report (Reference 13) provides, in Tables 4.4.1-1 and 4.4.1-2 (reproduced herein), ultimate static pressure capacities for both the primary containment and the drywell boundaries, for various failure mechanisms. These capacities are based on specified material strengths and do not account for thermal loads. The failure capacities given in Table 4.4.1 of Reference 13 for the various locations around the major containment penetrations are significantly less than the 0.647 MPa (93.8 psig) capacity (at 50 percent probability of failure) stated earlier for Clinton, a similar Mark III primary containment. The present data on the ultimate pressure capacity of a Mark III reinforced concrete primary containment with steel liner are limited and as such, failure pressure ranges may have to be developed for various failure modes and incident temperatures.

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Source: Grand Gulf Nuclear StationIndividual Plant Examination Summary Report (Reference 13)

F-11

Source: Grand Gulf Nuclear StationIndividual Plant Examination Summary Report (Reference 13)

Mark III Containment with a Freestanding Steel Primary Containment Perry and River Bend are the two power stations that have the Mark III containment with a freestanding steel primary containment. References 14 and 15 evaluated both the failure modes for the containment and the drywell for both plants, and the ultimate pressure capacities varied for both. The failure capacities evaluated for Perry make no mention of the temperature levels associated with these failure pressure capacities. Therefore, the assumption should be made that these pressure capacities are at room temperature (approximately 21 degrees C

[70 degrees F]).

STEEL CONTAINMENT Containment Vessel Wall The study described in Reference 14 determined that the failure pressure capacity of the Perry containment cylinder wall would occur at a pressure level of 0.597 MPa (86.6 psig) with a 5-percent probability of failure (with no mention of the temperature level), whereas the study described in Reference 15 determined the failure of the River Bend containment at the same F-12

location would occur at 0.861 MPa (125 psig), 0.765 MPa (111 psig), and 0.58 MPa (84 psig) for 21 degrees C (70 degrees F), 149 degrees C (300 degrees F), and 427 degrees C (800 degrees F), respectively.

Containment Vessel Dome Similarly, the analysts determined the failure of the containment dome would occur at a pressure level of 0.5983 MPa (86.77 psig) with a 5-percent probability of failure (with no mention of the temperature level), whereas the failure of the River Bend containment dome would occur at 0.827 MPa (120 psig), 0.738 MPa (107 psig), and 0.55 MPa (80 psig) for 21 degrees C (70 degrees F), 149 degrees C (300 degrees F), and 427 degrees C (800 degrees F), respectively.

The failure modes for these locations of the steel containment vessel (wall and dome) for both plants are considered structural failures, with no leakage area assigned to them, as defined earlier.

Equipment Hatch The failure pressure capacity of the equipment hatch at Perry is 0.419 MPa (60.8 psig), equal to a 5-percent probability of failure. For the River Bend plant, the controlling failure mode was determined to be leakage through the seals. The median pressure at which leakage could be expected would occur at pressure levels 0.34 MPa (49 psig) and 0.27 MPa (39 psig) for 21 degrees C (70 degrees F), and 149 degrees C (300 degrees F), respectively. At temperatures higher than 149 degrees C (300 degrees F), leakage through the seals would begin at an internal pressure level of 0.23 MPa (33 psig).

Personnel Airlock The Perry IPE determined the maximum pressure the airlock could resist would be 0.648 MPa (94.0 psig). For the River Bend plant, the controlling failure mode would be leakage through the inflatable seals. The median pressure at which leakage could be expected was 0.12 MPa (17 psig) and 0.19 MPa (28 psig) for 21 degrees C (70 degrees F) and 149 degrees C (300 degrees F), respectively. At 204 degrees C (400 degrees F), leakage pressure through the seals would be 0.23 MPa (34 psig). Estimates for leakage around the personnel doorswere 12 in2 at 149 degrees C (300 degrees F) and the leakage area increasedtoapproximately 32 in2 as the temperature rose higher than 316 degrees C (600 degrees F).

DRYWELL Drywell Wall As stated in Reference 15, the failure pressure capacity of the River Bend drywell was controlled by yielding of the hoop reinforcing steel at pressure levels 0.861 MPa (125 psig),

0.765 MPa (111 psig), and 0.58 MPa (84 psig), coincident with temperature levels 21 degrees C (70 degrees F), 149 degrees C (300 degrees F), and 427 degrees C (800 degrees F). The mean yield failure pressure for the drywell wall, based on hoop capacity, would be 0.679 MPa (98.5 psig) for Perry (Reference 14).

Drywell Head F-13

The governing failure mode of the River Bend drywell head was shear failure caused by the pin tearing through the tongue-and-groove joint of the upper cylinder. The failure pressure capacities associated with this failure mode are 1.19 MPa (173 psig), 0.896 MPa (130 psig),

and 0.67 MPa (97 psig), coincident with temperature levels 21 degrees C (70 degrees F),

149 degrees C (300 degrees F), and 427 degrees C (800 degrees F). The mean yield failure pressure for the Perry drywell head was 0.536 MPa (77.8 psig), controlled by the flange capability.

Equipment Hatch and Personnel Airlock Combination The drywell for both of these plants has one personnel airlock and one combination personnel airlock and equipment hatch. As stated in Section 4.4.3.5 of the River Bend IPE, the critical failure mode for this combination of airlock and hatch is leakage through the personnel doors.

Incipient leakage through the door seals was expected at internal pressure levels of 29 psig and 42 psig, coincident with temperatures of 21 degrees C (70 degrees F) and 149 degrees C (300 degrees F), respectively. Severe degradation of the seals around the door was expected at temperatures higher than 316 degrees C (600 degrees F). Estimated leakage area around the personnel doors was 12 in2 at 149 degrees C (300 degrees F), and the leakage area increased to approximately 32 in2 as the temperature rose higher than 316 degrees C (600 degrees F).

The personnel airlock for Perry is similar to the containment airlock, with a mean yield pressure of 0.7391 MPa (107.2 psig), whereas the pressure was 0.583 MPa (84.7 psig) for the equipment hatch.

F.3.3.2 Summary and Conclusions A detailed review of the IPE reports listed in References 12 through 15 resulted in the following conclusions about the Mark III containment failure characterization:

Mark III Containment with a Reinforced Concrete Primary Containment with Steel Liner (Clinton and Grand Gulf)

The primary containment for both of these plants would have a 50-percent probability of failure at a pressure range of 0.39 to 0.646 MPa (56 psig to 93.8 psig), with the likely failure mode being tearing of the steel liner in the vicinity of one of the major containment penetrations (such as the personnel airlocks or the equipment hatches). The personnel airlocks and equipment hatches have higher capacities that the steel liner surrounding them. As the pressure increases, failure of the containment shell (hoop rebar) would occur around midheight, at significantly higher pressure. Such failures would be considered limited in size such that containment pressurization is prevented, and a gradual depressurization would occur. Failure around the airlocks and hatches would be structural failures resulting in rapid depressurization of the containment.

Mark III Containment with a Freestanding Steel Primary Containment (Perry and River Bend)

A review of the IPE reports for both of these plants concluded that the pressure capacity of their freestanding steel primary containment was in the range of 0.27 and 0.46 MPa (39 psig and 67 psig), coincident with a temperature range of 21 degrees C (70 degrees F) to 149 degrees C F-14

(300 degrees F). Failure for both of these containments occurred at around penetrations in the steel containment.

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APPENDIX G DETAILED CHAPTER 6 ANALYSIS RESULTS

DETAILED CHAPTER 6 ANALYSIS RESULTS G.1 LOOP Scenarios G.1.1 Case 1: LOOPGR-38-9, CST Available, Initial CST Level Decreased to 24 ft.,

Nominal Recirculation Pump Seal Leakage Figure G - 1 Flow rate of the containment vents G-1

Figure G - 2 Flow rate of the FLEX pump Figure G - 3 Flow rate of the HPCI/RCIC pumps G-2

Figure G - 4 Flow rate of the recirculating pump seal leakage Figure G - 5 Water level in the CST G-3

Figure G - 6 RPV Downcomer water level Figure G - 7 Water level in the wetwell G-4

Figure G - 8 Pressure in the RPV Figure G - 9 Pressure in the wetwell G-5

Figure G - 10 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 11 Water temperature in the wetwell G-6

Figure G - 12 Peak temperature of the fuel cladding as a function of time G.1.2 Case 2: LOOPGR-38-9, CST Available, Initial CST Level Decreased to 24 ft., 200 gpm Recirculation Pump Seal Leakage Figure G - 13 Flow rate of the containment vents G-7

Figure G - 14 Flow rate of the FLEX pump Figure G - 15 Flow rate of the HPCI/RCIC pumps G-8

Figure G - 16 Flow rate of the recirculating pump seal leakage Figure G - 17 Water level in the CST G-9

Figure G - 18 RPV Downcomer water level Figure G - 19 Water level in the wetwell G-11

Figure G - 20 Pressure in the RPV Figure G - 21 Pressure in the wetwell G-11

Figure G - 22 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 23 Water temperature in the wetwell G-12

Figure G - 24 Peak temperature of the fuel cladding as a function of time G.1.3 Case 3: LOOPGR-38-9, CST Available, Initial CST Level Increased to 36 ft.,

Nominal Recirculation Pump Seal Leakage Figure G - 25 Flow rate of the containment vents G-13

Figure G - 26 Flow rate of the FLEX pump Figure G - 27 Flow rate of the HPCI/RCIC pumps G-14

Figure G - 28 Flow rate of the recirculating pump seal leakage Figure G - 29 Water level in the CST G-15

Figure G - 30 RPV Downcomer water level Figure G - 31 Water level in the wetwell G-16

Figure G - 32 Pressure in the RPV Figure G - 33 Pressure in the wetwell G-17

Figure G - 34 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 35 Water temperature in the wetwell G-18

Figure G - 36 Peak temperature of the fuel cladding as a function of time G.1.4 Case 4: LOOPGR-38-9, CST Available, Initial CST Level Increased to 36 ft., 200 gpm Recirculation Pump Seal Leakage Figure G - 37 Flow rate of the containment vents G-19

Figure G - 38 Flow rate of the FLEX pump Figure G - 39 Flow rate of the HPCI/RCIC pumps G-21

Figure G - 40 Flow rate of the recirculating pump seal leakage Figure G - 41 Water level in the CST G-21

Figure G - 42 RPV Downcomer water level Figure G - 43 Water level in the wetwell G-22

Figure G - 44 Pressure in the RPV Figure G - 45 Pressure in the wetwell G-23

Figure G - 46 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 47 Water temperature in the wetwell G-24

Figure G - 48 Peak temperature of the fuel cladding as a function of time G.1.6 Case 5: LOOPGR-38-9, CST Unavailable, Initial Wetwell Level Decreased to 10.1 ft., Nominal Recirculation Pump Seal Leakage Figure G - 49 Flow rate of the containment vents G-25

Figure G - 50 Flow rate of the FLEX pump Figure G - 51 Flow rate of the HPCI/RCIC pumps G-26

Figure G - 52 Flow rate of the recirculating pump seal leakage Figure G - 53 Water level in the CST G-27

Figure G - 54 RPV Downcomer water level Figure G - 55 Water level in the wetwell G-28

Figure G - 56 Pressure in the RPV Figure G - 57 Pressure in the wetwell G-29

Figure G - 58 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 59 Water temperature in the wetwell G-31

Figure G - 60 Peak temperature of the fuel cladding as a function of time G.1.6 Case 6: LOOPGR-38-9, CST Unavailable, Initial Wetwell Level Decreased to 10.1 ft., 200 gpm Recirculation Pump Seal Leakage Figure G - 61 Flow rate of the containment vents G-31

Figure G - 62 Flow rate of the FLEX pump Figure G - 63 Flow rate of the HPCI/RCIC pumps G-32

Figure G - 64 Flow rate of the recirculating pump seal leakage Figure G - 65 Water level in the CST G-33

Figure G - 66 RPV Downcomer water level Figure G - 67 Water level in the wetwell G-34

Figure G - 68 Pressure in the RPV Figure G - 69 Pressure in the wetwell G-35

Figure G - 70 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 71 Water temperature in the wetwell G-36

Figure G - 72 Peak temperature of the fuel cladding as a function of time G.1.7 Case 7: LOOPGR-38-9, CST Unavailable, Initial Wetwell Level Decreased to 10.4 ft., Nominal Recirculation Pump Seal Leakage Figure G - 73 Flow rate of the containment vents G-37

Figure G - 74 Flow rate of the FLEX pump Figure G - 75 Flow rate of the HPCI/RCIC pumps G-38

Figure G - 76 Flow rate of the recirculating pump seal leakage Figure G - 77 Water level in the CST G-39

Figure G - 78 RPV Downcomer water level Figure G - 79 Water level in the wetwell G-41

Figure G - 80 Pressure in the RPV Figure G - 81 Pressure in the wetwell G-41

Figure G - 82 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 83 Water temperature in the wetwell G-42

Figure G - 84 Peak temperature of the fuel cladding as a function of time G.1.8 Case 8: LOOPGR-38-9, CST Unavailable, Initial Wetwell Level Decreased to 10.4 ft., 200 gpm Recirculation Pump Seal Leakage Figure G - 85 Flow rate of the containment vents G-43

Figure G - 86 Flow rate of the FLEX pump Figure G - 87 Flow rate of the HPCI/RCIC pumps G-44

Figure G - 88 Flow rate of the recirculating pump seal leakage Figure G - 89 Water level in the CST G-45

Figure G - 90 RPV Downcomer water level Figure G - 91 Water level in the wetwell G-46

Figure G - 92 Pressure in the RPV Figure G - 93 Pressure in the wetwell G-47

Figure G - 94 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 95 Water temperature in the wetwell G-48

Figure G - 96 Peak temperature of the fuel cladding as a function of time G.1.9 Case 9: LOOPGR-38-9, RCIC Injection from CST Initially with Swap to FLEX Injection at 7 hrs., Initial CST Level Decreased to 24 ft., Nominal Recirculation Pump Seal Leakage Figure G - 97 Flow rate of the containment vents G-49

Figure G - 98 Flow rate of the FLEX pump Figure G - 99 Flow rate of the HPCI/RCIC pumps G-51

Figure G - 100 Flow rate of the recirculating pump seal leakage Figure G - 101 Water level in the CST G-51

Figure G - 102 RPV Downcomer water level Figure G - 103 Water level in the wetwell G-52

Figure G - 104 Pressure in the RPV Figure G - 105 Pressure in the wetwell G-53

Figure G - 106 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 107 Water temperature in the wetwell G-54

Figure G - 108 Peak temperature of the fuel cladding as a function of time G.1.10 Case 10: LOOPGR-38-9, RCIC Injection from CST Initially with Swap to FLEX Injection at 7 hrs., Initial CST Level Decreased to 24 ft., 200 gpm Recirculation Pump Seal Leakage Figure G - 109 Flow rate of the containment vents G-55

Figure G - 110 Flow rate of the FLEX pump Figure G - 111 Flow rate of the HPCI/RCIC pumps G-56

Figure G - 112 Flow rate of the recirculating pump seal leakage Figure G - 113 Water level in the CST G-57

Figure G - 114 RPV Downcomer water level Figure G - 115 Water level in the wetwell G-58

Figure G - 116 Pressure in the RPV Figure G - 117 Pressure in the wetwell G-59

Figure G - 118 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 119 Water temperature in the wetwell G-60

Figure G - 120 Peak temperature of the fuel cladding as a function of time G.1.11 Case 11: LOOPGR-38-9, RCIC Injection from Wetwell Initially with Swap to FLEX Injection at 7 hrs., Initial Wetwell Level Decreased to 10.4 ft., Nominal Recirculation Pump Seal Leakage Figure G - 121 Flow rate of the containment vents G-61

Figure G - 122 Flow rate of the FLEX pump Figure G - 123 Flow rate of the HPCI/RCIC pumps G-62

Figure G - 124 Flow rate of the recirculating pump seal leakage Figure G - 125 Water level in the CST G-63

Figure G - 126 RPV Downcomer water level Figure G - 127 Water level in the wetwell G-64

Figure G - 128 Pressure in the RPV Figure G - 129 Pressure in the wetwell G-65

Figure G - 130 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 131 Water temperature in the wetwell G-66

Figure G - 132 Peak temperature of the fuel cladding as a function of time G.1.12 Case 12: LOOPGR-38-9, RCIC Injection from Wetwell Initially with Swap to FLEX Injection at 7 hrs., Initial Wetwell Level Decreased to 10.4 ft., 200 gpm Recirculation Pump Seal Leakage Figure G - 133 Flow rate of the containment vents G-67

Figure G - 134 Flow rate of the FLEX pump Figure G - 135 Flow rate of the HPCI/RCIC pumps G-68

Figure G - 136 Flow rate of the recirculating pump seal leakage Figure G - 137 Water level in the CST G-69

Figure G - 138 RPV Downcomer water level Figure G - 139 Water level in the wetwell G-70

Figure G - 140 Pressure in the RPV Figure G - 141 Pressure in the wetwell G-71

Figure G - 142 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 143 Water temperature in the wetwell G-72

Figure G - 144 Peak temperature of the fuel cladding as a function of time G.2 LOMFW Scenarios G.2.1 Case 13: LOMFW-25, RCIC Lost at 4 hrs., Nominal CRDHS Injection, Nominal Recirculation Pump Seal Leakage Figure G - 145 Flow rate of the containment vents G-73

Figure G - 146 Flow rate of the control rod drive hydraulic system Figure G - 147 Flow rate of the HPCI/RCIC pumps G-74

Figure G - 148 Flow rate of the recirculating pump seal leakage Figure G - 149 RPV Downcomer water level G-75

Figure G - 150 Pressure in the RPV Figure G - 151 Plant status relative to the HCL curve (Graph 4 of the EOPs)

G-76

Figure G - 152 Water temperature in the wetwell Figure G - 153 Peak temperature of the fuel cladding as a function of time G-77

G.2.2 Case 14: LOMFW-25, RCIC Lost at 4 hrs., Nominal CRDHS Injection, 200 gpm Recirculation Pump Seal Leakage Figure G - 154 Flow rate of the containment vents Figure G - 155 Flow rate of the control rod drive hydraulic system G-78

Figure G - 156 Flow rate of the HPCI/RCIC pumps Figure G - 157 Flow rate of the recirculating pump seal leakage G-79

Figure G - 158 RPV Downcomer water level Figure G - 159 Pressure in the RPV G-81

Figure G - 160Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 161 Water temperature in the wetwell G-81

Figure G - 162 Peak temperature of the fuel cladding as a function of time G.2.3 Case 15: LOMFW-25, RCIC Lost at 4 hrs., One Train ofCRDHS Injection, Nominal Recirculation Pump Seal Leakage Figure G - 163 Flow rate of the containment vents G-82

Figure G - 164 Flow rate of the control rod drive hydraulic system Figure G - 165 Flow rate of the HPCI/RCIC pumps G-83

Figure G - 166 Flow rate of the recirculating pump seal leakage Figure G - 167 RPV Downcomer water level G-84

Figure G - 168 Pressure in the RPV Figure G - 169 Plant status relative to the HCL curve (Graph 4 of the EOPs)

G-85

Figure G - 170 Water temperature in the wetwell Figure G - 171 Peak temperature of the fuel cladding as a function of time G.2.4 Case 16: LOMFW-25, RCIC Lost at 4 hrs., One Train ofCRDHS Injection, 200 gpm Recirculation Pump Seal Leakage G-86

Figure G - 172 Flow rate of the containment vents Figure G - 173 Flow rate of the control rod drive hydraulic system G-87

Figure G - 174 Flow rate of the HPCI/RCIC pumps Figure G - 175 Flow rate of the recirculating pump seal leakage G-88

Figure G - 176 RPV Downcomer water level Figure G - 177 Pressure in the RPV G-89

Figure G - 178 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 179 Water temperature in the wetwell G-91

Figure G - 180 Peak temperature of the fuel cladding as a function of time G.2.5 Case 17: LOMFW-25, RCIC Lost at 6 hrs., Nominal CRDHS Injection, Nominal Recirculation Pump Seal Leakage Figure G - 181 Flow rate of the containment vents G-91

Figure G - 182 Flow rate of the control rod drive hydraulic system Figure G - 183 Flow rate of the HPCI/RCIC pumps G-92

Figure G - 184 Flow rate of the recirculating pump seal leakage Figure G - 185 RPV Downcomer water level G-93

Figure G - 186 Pressure in the RPV Figure G - 187 Plant status relative to the HCL curve (Graph 4 of the EOPs)

G-94

Figure G - 188 Water temperature in the wetwell Figure G - 189 Peak temperature of the fuel cladding as a function of time G.2.6 Case 18: LOMFW-25, RCIC Lost at 6 hrs., Nominal CRDHS Injection, 200 gpm Recirculation Pump Seal Leakage G-95

Figure G - 190 Flow rate of the containment vents Figure G - 191 Flow rate of the control rod drive hydraulic system G-96

Figure G - 192 Flow rate of the HPCI/RCIC pumps Figure G - 193 Flow rate of the recirculating pump seal leakage G-97

Figure G - 194 RPV Downcomer water level Figure G - 195 Pressure in the RPV G-98

Figure G - 196 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 197 Water temperature in the wetwell G-99

Figure G - 198 Peak temperature of the fuel cladding as a function of time G.2.7 Case 19: LOMFW-25, RCIC Lost at 6 hrs., One Train ofCRDHS Injection, Nominal Recirculation Pump Seal Leakage Figure G - 199 Flow rate of the containment vents G-101

Figure G - 200 Flow rate of the control rod drive hydraulic system Figure G - 201 Flow rate of the HPCI/RCIC pumps G-101

Figure G - 202 Flow rate of the recirculating pump seal leakage Figure G - 203 RPV Downcomer water level G-102

Figure G - 204 Pressure in the RPV Figure G - 205 Plant status relative to the HCL curve (Graph 4 of the EOPs)

G-103

Figure G - 206 Water temperature in the wetwell Figure G - 207 Peak temperature of the fuel cladding as a function of time G.2.8 Case 20: LOMFW-25, RCIC Lost at 6 hrs., One Train ofCRDHS Injection, 200 gpm Recirculation Pump Seal Leakage G-104

Figure G - 208 Flow rate of the containment vents Figure G - 209 Flow rate of the control rod drive hydraulic system G-105

Figure G - 210 Flow rate of the HPCI/RCIC pumps Figure G - 211 Flow rate of the recirculating pump seal leakage G-106

Figure G - 212 RPV Downcomer water level Figure G - 213 Pressure in the RPV G-107

Figure G - 214 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 215 Water temperature in the wetwell G-108

Figure G - 216 Peak temperature of the fuel cladding as a function of time G.3 Sensitivity Analyses G.3.1 Case 1a: Sensitivity to LOOPGR-38-9 Case 1 with HPCI Available Instead of RCIC Figure G - 217 Flow rate of the containment vents G-109

Figure G - 218 Flow rate of the FLEX pump Figure G - 219 Flow rate of the HPCI/RCIC pumps G-111

Figure G - 220 Flow rate of the recirculating pump seal leakage Figure G - 221 Water level in the CST G-111

Figure G - 222 RPV Downcomer water level Figure G - 223 Water level in the wetwell G-112

Figure G - 224 Pressure in the RPV Figure G - 225 Pressure in the wetwell G-113

Figure G - 226 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 227 Water temperature in the wetwell G-114

Figure G - 228 Peak temperature of the fuel cladding as a function of time G.3.2 Case 5a: Sensitivity to LOOPGR-38-9 Case 5 with HPCI Available Instead of RCIC Figure G - 229 Flow rate of the containment vents G-115

Figure G - 230 Flow rate of the FLEX pump Figure G - 231 Flow rate of the HPCI/RCIC pumps G-116

Figure G - 232 Flow rate of the recirculating pump seal leakage Figure G - 233 Water level in the CST G-117

Figure G - 234 RPV Downcomer water level Figure G - 235 Water level in the wetwell G-118

Figure G - 236 Pressure in the RPV Figure G - 237 Pressure in the wetwell G-119

Figure G - 238 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 239 Water temperature in the wetwell G-121

Figure G - 240 Peak temperature of the fuel cladding as a function of time G.3.3 Case 5b: Sensitivity to LOOPGR-38-9 Case 5 with RCIC Lostwhen NPSH Below the Rated Head Figure G - 241 Flow rate of the containment vents G-121

Figure G - 242 Flow rate of the FLEX pump Figure G - 243 Flow rate of the HPCI/RCIC pumps G-122

Figure G - 244 Flow rate of the recirculating pump seal leakage Figure G - 245 Water level in the CST G-123

Figure G - 246 RPV Downcomer water level Figure G - 247 Water level in the wetwell G-124

Figure G - 248 Pressure in the RPV Figure G - 249 Pressure in the wetwell G-125

Figure G - 250 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 251 Water temperature in the wetwell G-126

Figure G - 252 Peak temperature of the fuel cladding as a function of time G.3.4 Case 11a: Sensitivity to LOOPGR-38-9 Case 11 with RCICLost when NPSH Below the Rated Head Figure G - 253 Flow rate of the containment vents G-127

Figure G - 254 Flow rate of the FLEX pump Figure G - 255 Flow rate of the HPCI/RCIC pumps G-128

Figure G - 256 Flow rate of the recirculating pump seal leakage Figure G - 257 Water level in the CST G-129

Figure G - 258 RPV Downcomer water level Figure G - 259 Water level in the wetwell G-131

Figure G - 260 Pressure in the RPV Figure G - 261 Pressure in the wetwell G-131

Figure G - 262 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 263 Water temperature in the wetwell G-132

Figure G - 264 Peak temperature of the fuel cladding as a function of time G.3.5 Case 15a: Sensitivity to LOMFW-25 Case 15 with RCIC Injection from the Wetwell Figure G - 265 Flow rate of the containment vents G-133

Figure G - 266 Flow rate of the control rod drive hydraulic system Figure G - 267 Flow rate of the HPCI/RCIC pumps G-134

Figure G - 268 Flow rate of the recirculating pump seal leakage Figure G - 269 RPV Downcomer water level G-135

Figure G - 270 Pressure in the RPV Figure G - 271 Plant status relative to the HCL curve (Graph 4 of the EOPs)

G-136

Figure G - 272 Water temperature in the wetwell Figure G - 273 Peak temperature of the fuel cladding as a function of time G.3.6 Case 15b: Sensitivity to LOMFW-25 Case 15 with RPV Depressurization Ending at 150psig G-137

Figure G - 274 Flow rate of the containment vents Figure G - 275 Flow rate of the control rod drive hydraulic system G-138

Figure G - 276 Flow rate of the HPCI/RCIC pumps Figure G - 277 Flow rate of the recirculating pump seal leakage G-139

Figure G - 278 RPV Downcomer water level Figure G - 279 Pressure in the RPV G-141

Figure G - 280 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 281 Water temperature in the wetwell G-141

Figure G - 282 Peak temperature of the fuel cladding as a function of time G.3.7 Case 15c: Sensitivity to LOMFW-25 Case 15 with RPV Emergency Depressurization when the HCL Curve is Reached Figure G - 283 Flow rate of the containment vents G-142

Figure G - 284 Flow rate of the control rod drive hydraulic system Figure G - 285 Flow rate of the HPCI/RCIC pumps G-143

Figure G - 286 Flow rate of the recirculating pump seal leakage Figure G - 287 RPV Downcomer water level G-144

Figure G - 288 Pressure in the RPV Figure G - 289 Plant status relative to the HCL curve (Graph 4 of the EOPs)

G-145

Figure G - 290 Water temperature in the wetwell Figure G - 291 Peak temperature of the fuel cladding as a function of time G-146

G.3.8 Case 15d: Sensitivity to LOMFW-25 Case 15 with MSIV Closureat the Start of the Transient Figure G - 292 Flow rate of the containment vents Figure G - 293 Flow rate of the control rod drive hydraulic system G-147

Figure G - 294 Flow rate of the HPCI/RCIC pumps Figure G - 295 Flow rate of the recirculating pump seal leakage G-148

Figure G - 296 RPV Downcomer water level Figure G - 297 Pressure in the RPV G-149

Figure G - 298 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 299 Water temperature in the wetwell G-151

Figure G - 300 Peak temperature of the fuel cladding as a function of time G.3.9 Case 16a: Sensitivity to LOMFW-25 Case 16 with MSIV Closureat the Start of the Transient Figure G - 301 Flow rate of the containment vents G-151

Figure G - 302 Flow rate of the control rod drive hydraulic system Figure G - 303 Flow rate of the HPCI/RCIC pumps G-152

Figure G - 304 Flow rate of the recirculating pump seal leakage Figure G - 305 RPV Downcomer water level G-153

Figure G - 306 Pressure in the RPV Figure G - 307 Plant status relative to the HCL curve (Graph 4 of the EOPs)

G-154

Figure G - 308 Water temperature in the wetwell Figure G - 309 Peak temperature of the fuel cladding as a function of time G-155

G.3.10 Case 17a: Sensitivity to LOMFW-25 Case 17 with HPCI Available Instead of RCIC Figure G - 310 Flow rate of the containment vents Figure G - 311 Flow rate of the control rod drive hydraulic system G-156

Figure G - 312 Flow rate of the HPCI/RCIC pumps Figure G - 313 Flow rate of the recirculating pump seal leakage G-157

Figure G - 314 RPV Downcomer water level Figure G - 315 Pressure in the RPV G-158

Figure G - 316 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 317 Water temperature in the wetwell G-159

Figure G - 318 Peak temperature of the fuel cladding as a function of time G.3.11 Case 17b: Sensitivity to LOMFW-25 Case 17 with an SRVFailing Open at 270 Cycles Figure G - 319 Flow rate of the containment vents G-161

Figure G - 320 Flow rate of the control rod drive hydraulic system Figure G - 321 Flow rate of the HPCI/RCIC pumps G-161

Figure G - 322 Flow rate of the recirculating pump seal leakage Figure G - 323 RPV Downcomer water level G-162

Figure G - 324 Pressure in the RPV Figure G - 325 Plant status relative to the HCL curve (Graph 4 of the EOPs)

G-163

Figure G - 326 Water temperature in the wetwell Figure G - 327 Peak temperature of the fuel cladding as a function of time G.3.12 Case 19a: Sensitivity to LOMFW-25 Case 19 with RCIC Injection from the Wetwell G-164

Figure G - 328 Flow rate of the containment vents Figure G - 329 Flow rate of the control rod drive hydraulic system G-165

Figure G - 330 Flow rate of the HPCI/RCIC pumps Figure G - 331 Flow rate of the recirculating pump seal leakage G-166

Figure G - 332 RPV Downcomer water level Figure G - 333 Pressure in the RPV G-167

Figure G - 334 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 335 Water temperature in the wetwell G-168

Figure G - 336 Peak temperature of the fuel cladding as a function of time G.3.13 Case 19b: Sensitivity to LOMFW-25 Case 19 with RPV Emergency Depressurization when the HCL Curve is Reached Figure G - 337 Flow rate of the containment vents G-169

Figure G - 338 Flow rate of the control rod drive hydraulic system Figure G - 339 Flow rate of the HPCI/RCIC pumps G-171

Figure G - 340 Flow rate of the recirculating pump seal leakage Figure G - 341 RPV Downcomer water level G-171

Figure G - 342 Pressure in the RPV Figure G - 343 Plant status relative to the HCL curve (Graph 4 of the EOPs)

G-172

Figure G - 344 Water temperature in the wetwell Figure G - 345 Peak temperature of the fuel cladding as a function of time G-173

G.3.14 Case 19c: Sensitivity to LOMFW-25 Case 19 with MSIVClosure at the Start of the Transient Figure G - 346 Flow rate of the containment vents Figure G - 347 Flow rate of the control rod drive hydraulic system G-174

Figure G - 348 Flow rate of the HPCI/RCIC pumps Figure G - 349 Flow rate of the recirculating pump seal leakage G-175

Figure G - 350 RPV Downcomer water level Figure G - 351 Pressure in the RPV G-176

Figure G - 352 Plant status relative to the HCL curve (Graph 4 of the EOPs)

Figure G - 353 Water temperature in the wetwell G-177

Figure G - 354 Peak temperature of the fuel cladding as a function of time G-178

Figure G - 306 Pressure in the RPV Figure G - 307 Plant status relative to the HCL curve (Graph 4 of the EOPs)

G-179

Figure G - 308 Water temperature in the wetwell Figure G - 309 Peak temperature of the fuel cladding as a function of time G-181

G.3.10 Case 17a: Sensitivity to LOMFW-25 Case 17 with HPCI Available Instead of RCIC Figure G - 310 Flow rate of the containment vents G-181

Figure G - 311 Flow rate of the control rod drive hydraulic system Figure G - 312 Flow rate of the HPCI/RCIC pumps G-182

Figure G - 313 Flow rate of the recirculating pump seal leakage Figure G - 314 RPV Downcomer water level G-183

Figure G - 315 Pressure in the RPV Figure G - 316 Plant status relative to the HCL curve (Graph 4 of the EOPs)

G-184

Figure G - 317 Water temperature in the wetwell Figure G - 318 Peak temperature of the fuel cladding as a function of time G-185

G.3.11 Case 17b: Sensitivity to LOMFW-25 Case 17 with an SRV Failing Open at 270 Cycles Figure G - 319 Flow rate of the containment vents G-186

Figure G - 320 Flow rate of the control rod drive hydraulic system Figure G - 321 Flow rate of the HPCI/RCIC pumps G-187

Figure G - 322 Flow rate of the recirculating pump seal leakage Figure G - 323 RPV Downcomer water level G-188

Figure G - 324 Pressure in the RPV Figure G - 325 Plant status relative to the HCL curve (Graph 4 of the EOPs)

G-189

Figure G - 326 Water temperature in the wetwell Figure G - 327 Peak temperature of the fuel cladding as a function of time G-191

G.3.12 Case 19a: Sensitivity to LOMFW-25 Case 19 with RCIC Injection from the Wetwell Figure G - 328 Flow rate of the containment vents G-191

Figure G - 329 Flow rate of the control rod drive hydraulic system Figure G - 330 Flow rate of the HPCI/RCIC pumps G-192

Figure G - 331 Flow rate of the recirculating pump seal leakage Figure G - 332 RPV Downcomer water level G-193

Figure G - 333 Pressure in the RPV Figure G - 334 Plant status relative to the HCL curve (Graph 4 of the EOPs)

G-194

Figure G - 335 Water temperature in the wetwell Figure G - 336 Peak temperature of the fuel cladding as a function of time G-195

G.3.13 Case 19b: Sensitivity to LOMFW-25 Case 19 with RPV Emergency Depressurization when the HCL Curve is Reached Figure G - 337 Flow rate of the containment vents G-196

Figure G - 338 Flow rate of the control rod drive hydraulic system Figure G - 339 Flow rate of the HPCI/RCIC pumps G-197

Figure G - 340 Flow rate of the recirculating pump seal leakage Figure G - 341 RPV Downcomer water level G-198

Figure G - 342 Pressure in the RPV Figure G - 343 Plant status relative to the HCL curve (Graph 4 of the EOPs)

G-199

Figure G - 344 Water temperature in the wetwell Figure G - 345 Peak temperature of the fuel cladding as a function of time 200

G.3.14 Case 19c: Sensitivity to LOMFW-25 Case 19 with MSIV Closure at the Start of the Transient Figure G - 346 Flow rate of the containment vents 201

Figure G - 347 Flow rate of the control rod drive hydraulic system Figure G - 348 Flow rate of the HPCI/RCIC pumps G-202

Figure G - 349 Flow rate of the recirculating pump seal leakage Figure G - 350 RPV Downcomer water level 203

Figure G - 351 Pressure in the RPV Figure G - 352 Plant status relative to the HCL curve (Graph 4 of the EOPs)

G-204

Figure G - 353 Water temperature in the wetwell Figure G - 354 Peak temperature of the fuel cladding as a function of time 205

APPENDIX H EVENT TREES

EVENT TREES Figure H-1 TRANS event treeDuane Arnold Energy Center (DAEC)

H-1

EVENT TREES (continued)

Figure H-2 Small loss-of-coolant accident event treeDAEC H-2

Figure H-3 Loss of offsite power (grid-related) event treeDAEC H-3

EVENT TREES (continued)

Figure H-4 Station blackout (SBO) event treeDAEC H-4

Figure H- 5 SBO-1 event treeDAEC H-5

EVENT TREES (continued)

Figure H-6 Loss of main feedwater event treeDAEC H-6

NUREG-2236 Volume 3 Confirmatory Thermal-Hydraulic Analysis To Support Specific Success Criteria in the Standardized Plant Analysis Risk ModelsDuane Arnold October 2020 Appendices F - H S. Campbell, S. Dennis, D. Helton, M. Khatib-Rahbar,A. Krall, L. Kozak, Technical R. Buell, F. Sock, J. Pires Office of Nuclear Regulatory Research U.S. Nuclear Regulatory Commission Washington, DC 20555 Office of Nuclear Regulatory Research U.S. Nuclear Regulatory Commission Washington, DC 20555 S. Dennis This report extends the work documented in NUREG-2187, Confirmatory Thermal-Hydraulic Analysis to Support Specific Success Criteria in the Standardized Plant Analysis Risk ModelsByron Unit 1, issued January 2016, to the Duane Arnold Energy Center. Its purpose is to produce an additional set of best estimate thermal-hydraulic calculations that can be used to confirm or enhance specific success criteria for system performance and operator timing found in the agencys probabilistic risk assessment tools. Along with enhancing the technical basis for the agencys independent standardized plant analysis risk (SPAR) models, these calculations are expected to be a useful reference to model end users for specific regulatory applications.

This report first describes major assumptions used in this study. It then describes the major plant characteristics for the Duane Arnold Energy Center, in addition to the MELCOR model used to represent the plant. Finally, the report presents the results of MELCOR calculations for selected initiators and compares these results to SPAR success criteria, the licensees success criteria, or other generic studies.

PRA, Success Criteria, MELCOR, thermal-hydraulic

Federal Recycling Program

NUREG-2236, Volume 3 Confirmatory Thermal-Hydraulic Analysis To Support Specific Success October 2020 Appendices F - H Criteria in the Standardized Plant Analysis Risk ModelsDuane Arnold