SCDAP/RELAP5 Thermal-Hydraulic 

Evaluations of the Potential for 

Containment Bypass During 

Extended Station Blackout 

Severe Accident Sequences in a 

Westinghouse Four-Loop PWR

Office of Nuclear Regulatory Research 

NUREG/CR-6995
SCDAP/RELAP5 Thermal-Hydraulic

Evaluations of the Potential for

Containment Bypass During

Extended Station Blackout

Severe Accident Sequences in a 

Westinghouse Four-Loop PWR 

Manuscript Completed: February 2010 

Date Published: March 2010 

Prepared by

C.D. Fletcher, R.M. Beaton, V. V. Palazov, and D.L. Caraher

R.W. Shumway (Consultant)

Information Systems Laboratories, Inc. 

10070 Barnes Canyon Road

San Diego, CA 92121

C. Boyd, NRC Point of Contact 

NRC Job Code Y6198 

Office of Nuclear Regulatory Research 

NUREG/CR-6995
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ABSTRACT 

The U.S. Nuclear Regulatory Commission has been conducting studies to evaluate the risk 

associated with steam generator tube failure during low probability severe accidents in 

pressurized-water reactors (PWRs) employing U-tube-type steam generators as part of the 

agency’s Steam Generator Action Plan (ML 011300073). The evaluations focus on station 

blackout events that include a series of unlikely events and conditions that result in a “high-drylow” plant condition. The high-dry-low condition refers to high primary side pressure along with 

a dried-out steam generator that is at low pressure. Failures of hot leg piping, pressurizer 

surge-line piping, and the reactor vessel lead to discharge of fission products into the 

containment. Failure of steam generator tubes prior to the failure of one of these other 

components leads to discharge of some fission products into the steam generator secondary 

system from where they may be discharged to the environment through the pressure-relief 

valves. This latter sequence is potentially more risk-significant since it involves a containment 

bypass scenario. The relative timing of these structural failures therefore affects the event 

sequence and whether the containment is bypassed. 

This report summarizes thermal-hydraulic evaluations performed using the SCDAP/RELAP5 

systems analysis code and a model representing a Westinghouse four-loop PWR. An 

assessment is made of the SCDAP/RELAP5 capabilities for predicting the phenomena and 

behavior important for this application. The plant model has benefitted from (1) extensive 

iterative comparisons with evaluations of natural circulation flows and turbulent mixing using a 

computational fluid dynamics code and (2) from comparison with experimental data for pertinent 

fluid-mixing behavior. This report documents the recent history of SCDAP/RELAP5 model 

improvements for this application, numerous sensitivity evaluations, estimates of the 

uncertainties in the calculated results, analyses of extended station blackout accident event 

sequences in a Westinghouse four-loop PWR, and a categorization of those event sequences 

based on containment bypass outcome. 
iv
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FOREWORD 

Steam generator tubes comprise a majority of the reactor coolant system pressure boundary 

and therefore their integrity is important to ensuring safe operation of the plants. During 

November 2000, after the Indian Point 2 steam generator leakage event, NRC developed a 

Steam Generator Action Plan (ML 011300073) to consolidate activities related to steam 

generators and to ensure that issues are appropriately tracked and resolved. In May 2001, this 

plan was revised to address a differing professional opinion on steam generator tube integrity. 

This plan is one facet of NRC's strategy to maintain safe operation of nuclear power plants and 

to increase public confidence in agency regulatory actions. 

One aspect of the Steam Generator Action Plan is the analysis of the risk of low probability 

severe accident-induced tube failures. Tube failure during a severe accident has the potential 

for radioactive release that bypasses containment. An important aspect of this analysis is the 

prediction of the thermal-hydraulic response of the reactor coolant system during postulated 

severe accident conditions as well as the prediction of the thermal-hydraulic loads that 

challenge specific reactor coolant system (RCS) components. This report describes the 

completion of a series of analyses involving hypothetical station blackout event sequences that 

lead to severe accidents. 

The sequences are set up by assuming multiple concurrent failures of systems and 

components. These assumptions are selected to cover the range of “high-dry-low” conditions 

(which refer to high reactor coolant system pressure and dry steam generators at low pressure) 

that challenge the integrity of the steam generator tubes. The analyses do not represent bestestimate plant behavior, nor do the results indicate the most-likely outcomes of the event 

sequences because several systems or operator actions can eliminate one or more of the high, 

dry, or low conditions. For example, high reactor coolant pump shaft seal leakage rates can 

eliminate the high reactor coolant system pressure condition, operation of the turbine-driven 

auxiliary feedwater system can eliminate the dry steam generator condition, and maintenance of 

the steam generator secondary pressure boundary can eliminate the low steam generator 

pressure condition. Considerations such as these are ultimately accounted for in an integrated 

probabilistic risk assessment of severe accident-induced steam generator tube failures currently 

being performed by the Office of Nuclear Regulatory Research, Division of Risk Analysis. 

The predictions provide a screening tool for the potential of severe accident induced tube 

failures and some conservatism is applied to ensure that potential scenarios are considered. 

The predictions provide valuable insights into what variables or factors affect the timing of 

induced failures for the steam generator tubes as well as other RCS components. In addition to 

providing a more complete perspective on the potential for consequential steam generator tube 

rupture, these predictions demonstrate the effectiveness of operator actions and safety systems 

to reduce or eliminate the risk of induced tube failures. 
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TABLE OF CONTENTS 

ABSTRACT.................................................................................................................................. iii

FOREWORD................................................................................................................................. v

EXECUTIVE SUMMARY ............................................................................................................ xv

ACKNOWLEDGEMENTS .......................................................................................................... xxi

NOMENCLATURE....................................................................................................................xxiii

1. INTRODUCTION...............................................................................................................1

1.1 Objective of This Report.................................................................................................3

1.2 Description of a Base Case Station Blackout Accident Scenario...................................3

1.3 Plant Behavior During the Base Case Accident Scenario..............................................4

1.4 Definition of SG Tube Failure Margin and Criteria for Judging Occurrence of 

Containment Bypass ......................................................................................................6

1.5 Organization of This Report ...........................................................................................7

2. BACKGROUND ................................................................................................................9

2.1 NUREG-1570 Analyses, 1998-2000 ..............................................................................9

2.2 NUREG-1740 Independent Review and Steam Generator Action Plan, 2000-2001 .....9

2.3 Revised Station Blackout Base Case Event Sequence and Analysis, 2000-2003.......11

2.4 Sensitivity Analyses, 2004............................................................................................14

2.5 ACRS Review Meeting, 2004.......................................................................................16

2.6 Analyses to Support PRA, 2004-2005..........................................................................17

2.7 NRC and Consultant PIRT Evaluation and Peer Review, 2005...................................19

2.7.1 Independent Technical Review Issues....................................................................19

2.7.2 Identification of Dependent Variables for the Uncertainty Evaluation .....................20

2.7.3 Identification of Independent Variables for the Uncertainty Evaluation ...................20

2.8 Revised Base Case Calculation and Evaluation of Primary Coolant System Energy 

Flow, 2006....................................................................................................................25

2.9 Evaluation of Uncertainties in SCDAP/RELAP5 Simulations, 2006.............................26

2.10 Public Peer Review Meeting, 2007 ..............................................................................27

3. DESCRIPTION OF ANALYSIS METHODS ....................................................................31

3.1 SCDAP/RELAP5 Code Description..............................................................................31

3.2 RELAP5 Assessments Pertinent for the Containment Bypass Application..................32

3.2.1 Loop Seal Behavior.................................................................................................32

3.2.2 Pressurizer Filling, Draining and Relief Valve Behavior ..........................................37

3.3 SCDAP Assessments Pertinent for the Containment Bypass Application ...................42

3.3.1 Models for PWR Fuel Assembly Heat-Up Behavior ................................................42

3.3.2 Models for Fuel Rod Cladding Oxidation.................................................................44

3.3.3 Models for Fuel Rod Ballooning and Rupture .........................................................46

3.4 Description of SCDAP/RELAP5 Westinghouse Four-Loop Plant Model, Including 

Features Benefitting from Supporting CFD Analyses...................................................46

4. WESTINGHOUSE FOUR-LOOP PLANT STATION BLACKOUT BASE CASE 

ANALYSIS.......................................................................................................................57

4.1 Full-Power Steady State Calculation............................................................................57
viii

4.2 Transient Station Blackout Calculation.........................................................................58

5. KEY SENSITIVITIES.......................................................................................................77

5.1 RCP Shaft Seal Leakage Behavior ..............................................................................77

5.1.1 Leakage Rate Increases Due to Seal Failures at 13 Minutes .................................78

5.1.2 Leakage Rate Increases Due to Seal Failures When RCPs Experience Saturated 

Fluid Conditions....................................................................................................................80

5.2 Effect of Variations in Turbine-Driven Auxiliary Feedwater Operation and SG Steam 

Leakage .......................................................................................................................80

5.3 Mitigative Operator Intervention ...................................................................................86

5.3.1 Pre-Core Damage Operator Action .........................................................................86

5.3.2 Post-Core Damage Operator Action .....................................................................101

5.4 Sensitivity of Results to Assumed Split of SG Tubes into Hot and Cold Sections .....103

5.5 Effects Related to Opening SG Tube and HL Rupture Flow Paths............................103

6. GROUPING OF EXTENDED SBO EVENT SEQUENCES INTO CONTAINMENT 

BYPASS, POTENTIAL FOR CONTAINMENT BYPASS, AND NO CONTAINMENT 

BYPASS CATEGORIES ...............................................................................................109

6.1 Categorization of Event Sequences Without Operator Intervention...........................111

6.2 Categorization of Event Sequences with Operator Intervention.................................119

7. CONCLUSIONS............................................................................................................123

8. REFERENCES..............................................................................................................127

APPENDIX A – RESULTS OF 2004 SENSITIVITY ANALYSES.............................................. A-1

APPENDIX B – ANALYSES TO SUPPORT PRA..................................................................... B-1

APPENDIX C – EVALUATION OF PRIMARY COOLANT SYSTEM ENERGY FLOW ............ C-1

APPENDIX D - ESTIMATES OF UNCERTAINTIES IN THE SCDAP/RELAP5 SIMULATIONS ....

...................................................................................................................................... D-1

APPENDIX E – EFFECT OF MODELING REACTOR VESSEL OUTLET NOZZLE CARBON 

STEEL SAFE END........................................................................................................ E-1
ix

LIST OF FIGURES 

Figure 1.1 Schematic of Westinghouse Four-Loop Pressurized Water Reactor ....................2

Figure 1.2 Potential Coolant Loop Natural Circulation Flow Patterns During System 

Heat-Up .................................................................................................................5

Figure 3.1 Steam Emissivity as a Function of Temperature and Optical Depth ...................35

Figure 3.2 Break Flow for ROSA-IV Test SB-CL-18.............................................................35

Figure 3.3 Hot Leg Loop Seal Collapsed Levels for the PMK CAMP-CLB Experiment........36

Figure 3.4 Cold Leg Loop Seal Collapsed Levels for the PMK CAMP-CLB 

Experiment ..........................................................................................................36

Figure 3.5 Pressurizer Level for MIT ST4 Pressurizer Insurge Experiment .........................39

Figure 3.6 RCS Pressure for APEX-CE-13 Stuck-Open Pressurizer SRV Experiment........39

Figure 3.7 Pressurizer Level for APEX-CE-13 Stuck-Open Pressurizer SRV 

Experiment ..........................................................................................................40

Figure 3.8 Pressurizer PORV Flow for MIST 360499 Feed-and-Bleed Cooling 

Experiment ..........................................................................................................41

Figure 3.9 RCS Pressure for MIST 360499 Feed-and-Bleed Cooling Experiment...............41

Figure 3.10 RCS Pressure for LOBI BT-56 Loss-of-Feedwater Experiment ..........................43

Figure 3.11 Pressurizer Surge Line Flow for LOBI BT-56 Loss-of-Feedwater 

Experiment ..........................................................................................................43

Figure 3.12 Intact Loop Cold Leg Density for LOBI BT-56 Loss-of-Feedwater 

Experiment ..........................................................................................................44

Figure 3.13 Fuel Rod Temperature at the 0.75-m Elevation for CORA-7 Test.......................45

Figure 3.14 Reactor Vessel Nodalization ...............................................................................48

Figure 3.15 Coolant Loop Nodalization Excluding Provisions for Countercurrent 

Natural Circulation...............................................................................................49

Figure 3.16 Coolant Loop Nodalization With Provisions for Countercurrent Natural 

Circulation ...........................................................................................................50

Figure 3.17 Surge Line Connections to the Split Hot Leg During Countercurrent 

Natural Circulation...............................................................................................51

Figure 4.1 Reactor Coolant System Pressure ......................................................................60

Figure 4.2 Steam Generator Secondary Pressures..............................................................60

Figure 4.3 Reactor Coolant Pump Shaft Seal Leakage Flows .............................................61

Figure 4.4 Steam Generator Secondary Liquid Masses.......................................................61

Figure 4.5 Total Pressurizer PORV Flow..............................................................................62

Figure 4.6 Pressurizer SRV Flow .........................................................................................62

Figure 4.7 Pressurizer Level.................................................................................................63

Figure 4.8 Reactor Coolant Pump Loop Seal Void Fractions...............................................63

Figure 4.9 SG 1 Hot and Cold Average Tube Flows ............................................................65

Figure 4.10 Hot Leg 1 Upper and Lower Section Flows.........................................................65

Figure 4.11 Vessel Circulation Flows .....................................................................................67

Figure 4.12 Hot Leg Discharge Coefficients...........................................................................67

Figure 4.13 Recirculation Ratios ............................................................................................68

Figure 4.14 Hot Mixing Fractions............................................................................................68

Figure 4.15 Cold Mixing Fractions..........................................................................................69

Figure 4.16 SG Power Fractions ............................................................................................69

Figure 4.17 Hydrogen Generation Rate .................................................................................71

Figure 4.18 Loop 1 Structure Temperatures ..........................................................................71
x

Figure 4.19 Correspondence Between Loop 1 Structure Temperatures and Failure 

Times...................................................................................................................73

Figure 4.20 Hot Leg and Pressurizer Surge Line Creep Rupture Damage Indexes...............73

Figure 4.21 SG 1 Average Tube and Hot Leg 1 Creep Rupture Damage Indexes ................74

Figure 4.22 SG 1 Hottest Tube and Hot Leg 1 Creep Rupture Damage Indexes ..................74

Figure 5.1 Case 153 SG Secondary Pressures....................................................................89

Figure 5.2 Case 153 SG Water Masses...............................................................................90

Figure 5.3 Case 153 RCS Pressure .....................................................................................90

Figure 5.4 Case 153A SG Pressures ...................................................................................92

Figure 5.5 Case 153A SG Water Masses.............................................................................92

Figure 5.6 Case 153A RCS Pressure...................................................................................93

Figure 5.7 Case 161 RCS Pressure .....................................................................................95

Figure 5.8 Case 161 SG Secondary Pressures....................................................................95

Figure 5.9 Case 161m and Case 161mA HL Vapor Temperatures......................................98

Figure 5.10 Case 161m and Case 161mA RCS Pressures....................................................98

Figure 5.11 Case 165m and Case 161m RCS Pressures......................................................99

Figure 5.12 Case 165m and Case 161m SG 2 Pressures .....................................................99

Figure 6.1 Map of Containment Bypass Outcome for No Operator Intervention and 

Variations in SG Steam Leakage and RCP Shaft Seal Leakage Which 

Increases at 13 Minutes ....................................................................................115

Figure 6.2 Map of Containment Bypass Outcome for No Operator Intervention and 

Variations in SG Steam Leakage and RCP Shaft Seal Leakage Which 

Increases When the RCP Fluid Reaches the Saturation Temperature.............115

Figure 6.3 Map of Containment Bypass Outcome for No Operator Intervention and 

Variations in Temporary TDAFW System Operation and RCP Shaft Seal 

Leakage Which Increases at 13 Minutes...........................................................118

Figure 6.4 Map of Containment Bypass Outcome for No Operator Intervention and 

Variations in Temporary TDAFW System Operation and RCP Shaft Seal 

Leakage Which Increases When the RCP Fluid Reaches the Saturation 

Temperature......................................................................................................118

Figure 6.5 Map of Containment Bypass Outcome for No Operator Intervention and 

Variations in Temporary TDAFW System Operation and SG Steam 

Leakage.............................................................................................................119

Figure 6.6 Map of Containment Bypass Outcome for Pre-Core Damage Operator 

Intervention........................................................................................................122

Figure 6.7 Map of Containment Bypass Outcome for Post-Core Damage Operator 

Intervention........................................................................................................122

Figure C.1 Control Volume Arrangement for the Energy Balance Analysis........................ C-2

Figure C.2 Average Total Core Power Generated During the Five Phases of the SBO 

Accident Heat-Up Period................................................................................... C-6

Figure C.3 Portion of the Integrated Core Power Retained in the Fuel During the Five 

Phases of the SBO Accident Heat-Up Period ................................................... C-6

Figure C.4 Portion of the Integrated Core Power Transferred to the Core Fluid During 

the Five Phases of the SBO Accident Heat-Up Period...................................... C-7

Figure C.5 Change in Reactor Vessel Fluid Energy During the Five Phases of the 

SBO Accident Heat-Up Period .......................................................................... C-7

Figure C.6 Change in Pressurizer Fluid Energy During the Five Phases of the SBO 

Accident Heat-Up Period................................................................................... C-8

Figure C.7 Change in Fluid Energy in RCS Regions Other Than the Reactor Vessel 

and Pressurizer During the Five Phases of the SBO Accident Heat-Up 

Period ................................................................................................................ C-8
xi

Figure C.8 Integrated Flow of Energy Through the Pressurizer PORVs and Reactor 

Coolant Pump Shaft Seal Leaks During the Five Phases of the SBO 

Accident Heat-Up Period................................................................................... C-9

Figure C.9 Integrated Heat Transfer Rate from SG Tubes to Fluid During the Five 

Phases of the SBO Accident Heat-Up Period ................................................. C-11

Figure C.10 Integrated Heat Transfer Rate from All Structures (Except SG Tubes) to 

Fluid During the Five Phases of the SBO Accident Heat-Up Period ............... C-11

Figure D.1 Mass Flow Rates Through One of the Two Pressurizer PORVs for the 

Relief Valve Flow Area Sensitivity Cases........................................................ D-18

Figure D.2 RCS Pressures for the Relief Valve Flow Area Sensitivity Cases................... D-18

Figure D.3 Hot Leg 1 Discharge Coefficient Responses for the Hot Leg Discharge 

Coefficient Sensitivity Cases ........................................................................... D-20

Figure D.4 Hot Leg 1 Upper Section Flow Rates for the Hot Leg Discharge 

Coefficient Sensitivity Cases ........................................................................... D-20

Figure D.5 Integrated SG Power Fractions for the Hot Leg Discharge Coefficient 

Sensitivity Cases ............................................................................................. D-21

Figure D.6 Loop 1 Recirculation Ratio Responses for the Recirculation Ratio 

Sensitivity Cases ............................................................................................. D-21

Figure D.7 Loop 1 Integrated SG Power Fractions for the Recirculation Ratio 

Sensitivity Cases ............................................................................................. D-22

Figure D.8 Loop 1 Hot Mixing Fraction Responses for the Mixing Fraction Sensitivity 

Cases .............................................................................................................. D-23

Figure D.9 Loop 1 Cold Mixing Fraction Responses for the Mixing Fraction Sensitivity 

Cases .............................................................................................................. D-24

Figure D.10 Integrated SG 1 Power Fractions for the Mixing Fraction Sensitivity Cases ... D-24

Figure D.11 Mass Flow Rates in SG 1 Hot Average Tube for the Tube Split Sensitivity 

Cases .............................................................................................................. D-25

Figure D.12 Fluid Velocities in SG 1 Hot Average Tube for the Tube Split Sensitivity 

Cases .............................................................................................................. D-25

Figure D.13 SG 1 Hot Average Tube Wall Inside Surface Heat Transfer Coefficients 

for the Tube Split Sensitivity Cases................................................................. D-27

Figure D.14 Tube Wall Temperatures in SG 1 Hot Average Tube for the Tube Split 

Sensitivity Cases ............................................................................................. D-27

Figure D.15 SG 1 Hot Average Tube Outer Surface Heat Transfer Coefficients for the 

Tube Outer Wall Heat Transfer Sensitivity Cases........................................... D-28

Figure D.16 SG 1 Hot Average Tube Wall Temperatures for the Tube Outer Wall Heat 

Transfer Sensitivity Cases............................................................................... D-28

Figure D.17 Fuel Rod Cladding Oxidation Powers for the Oxidation Sensitivity Cases...... D-30

Figure D.18 Hot Leg 1 Upper Section Fluid Temperatures for the Oxidation Sensitivity 

Cases .............................................................................................................. D-30

Figure D.19 Flow Rates at Top of Central Core Region for the Vessel Circulation 

Sensitivity Cases ............................................................................................. D-31

Figure D.20 Total Fuel Rod Cladding Oxidation Power for the Vessel Circulation 

Sensitivity Cases ............................................................................................. D-32

Figure D.21 Hot Leg 1 Upper Section Fluid Temperatures for the Vessel Circulation 

Sensitivity Cases ............................................................................................. D-32

Figure D.22 Hot Leg 1 Upper Section Average Wall Temperatures for the Vessel 

Circulation Sensitivity Cases ........................................................................... D-33

Figure D.23 Heat Fluxes from Outer Surface of Reactor Vessel to Containment for the 

RCS Heat Loss Sensitivity Cases ................................................................... D-34

Figure D.24 Pressurizer Level Responses for the RCS Heat Loss Sensitivity Cases ........ D-34
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Figure D.25 Pump 1 Leakage Rates for the Symmetric Pump Shaft Seal Leak 

Sensitivity Cases ............................................................................................. D-35

Figure D.26 RCS Pressures for the Symmetric Pump Shaft Seal Leak Sensitivity 

Cases .............................................................................................................. D-37

Figure D.27 Hot Leg 1 Fluid Temperatures for the Symmetric Pump Shaft Seal Leak 

Sensitivity Cases ............................................................................................. D-37

Figure D.28 Single-Pump Leakage Rates for the Unsymmetrical Pump Shaft Seal 

Leak Sensitivity Cases .................................................................................... D-38

Figure D.29 RCS Pressures for the Unsymmetrical Pump Shaft Seal Leak Sensitivity 

Cases .............................................................................................................. D-38

Figure D.30 Hot Leg 1 Fluid Temperatures for the Unsymmetrical Pump Shaft Seal 

Leak Sensitivity Cases .................................................................................... D-39

Figure D.31 Pressurizer Surge Line Fluid Temperature for the Top Mounted Surge 

Line Sensitivity Case ....................................................................................... D-41

Figure D.32 SG 1 Pressure for the Stuck-Open SG Safety Relief Valve Sensitivity 

Case ................................................................................................................ D-41

Figure D.33 SG 2 Pressure for the Stuck-Open SG Safety Relief Valve Sensitivity 

Case ................................................................................................................ D-42

Figure D.34 Hot Leg 1 Fluid Temperature for the Stuck-Open SG Safety Relief Valve 

Sensitivity Case............................................................................................... D-42

Figure D.35 SG Secondary Pressures for the SG Secondary Leakage Sensitivity 

Cases .............................................................................................................. D-44

Figure D.36 Hot Leg 1 Inside Surface Heat Transfer Coefficient for the Hot Leg and 

Surge Line Heat Transfer Sensitivity Cases.................................................... D-44

Figure D.37 Hot Leg 1 Wall Temperature for the Hot Leg and Surge Line Heat 

Transfer Sensitivity Cases............................................................................... D-45

Figure D.38 SG 1 Hot Average Tube Wall Temperature for the Hot Leg and Surge 

Line Heat Transfer Sensitivity Cases .............................................................. D-45

Figure D.39 SG 1 Tubesheet Heat Transfer Coefficient for the Tubesheet Heat 

Transfer Sensitivity Cases............................................................................... D-47

Figure D.40 SG 1 Tubesheet Wall Temperature for the Tubesheet Heat Transfer 

Sensitivity Cases ............................................................................................. D-47

Figure D.42 Tube Leak Rate for the SG Tube Leakage Sensitivity Case........................... D-49

Figure D.43 Hot Leg 1 Upper Section Wall Temperature for the SG Tube Leakage 

Sensitivity Case............................................................................................... D-50

Figure D.44 SG 1 Average Tube Wall Temperature for the SG Tube Leakage 

Sensitivity Case............................................................................................... D-50

Figure D.45 Hot Leg Pressure for the SG Tube Leakage Sensitivity Case......................... D-51

Figure D.46 SG 1 Secondary Pressure for the SG Tube Leakage Sensitivity Case........... D-51
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LIST OF TABLES 

Table 2.1 Ranking Table of Items Important for the Containment Bypass Issue 

During SBO Severe Accident Scenarios in a Westinghouse Four-Loop 

PWR ....................................................................................................................21

Table 2.2 Base Case Values and Standard Deviations for the Dependent Variables.........26

Table 3.1 Summary of Measured and SCDAP-Calculated Hydrogen Production 

During Severe Accident Experiments..................................................................45

Table 3.2 Summary of Measured and SCDAP-Calculated Fuel Rod Rupture 

Behavior During Severe Accident Experiments...................................................46

Table 4.1 SCDAP/RELAP5 Full-Power Steady State Results.............................................57

Table 4.2 Sequence of Events from the SCDAP/RELAP5 SBO Base Case 

Calculation...........................................................................................................59

Table 4.3 Comparison of Target and SCDAP/RELAP5-Calculated SG Inlet Plenum 

Fluid Mixing and Flow Parameters ......................................................................70

Table 4.4 Summary of Calculated Creep Rupture Failure Times from the Base Case 

Calculation...........................................................................................................75

Table 5.1 Sensitivity of Results to Increased RCP Shaft Seal Leakage After 

13 Minutes...........................................................................................................79

Table 5.2 Sensitivity of Results to Increased Shaft Seal Leakage After Transition of 

RCP Fluid from Liquid to Steam..........................................................................81

Table 5.3 Results of Sensitivity Calculations Evaluating Variations in TDAFW 

System Operation and SG Secondary System Steam Leakage .........................83

Table 5.4 Results of Sensitivity Calculations Evaluating Pre-Core Damage 

Mitigative Operator Intervention ..........................................................................88

Table 5.5 Results of Sensitivity Calculations Evaluating Post-Core Damage 

Mitigative Operator Intervention ........................................................................102

Table 5.6 Results of Sensitivity Calculations Evaluating the Effects of Opening SG 

Tube Rupture and HL Rupture Flow Paths .......................................................104

Table 6.1 Characterization of Plant Fluid Conditions During Typical Non-LOCA 

Accident Sequences with Normal Operation of Safety Systems.......................110

Table 6.2 Characterization of Plant Fluid Conditions During an Extended Station 

Blackout Accident Sequence.............................................................................110

Table 6.3 Major Considerations and Influences on the Containment Bypass 

Outcome for Event Sequences Without Operator Intervention .........................113

Table 6.4 Pre-Core Damage Mitigative Operator Intervention Strategy............................121

Table 6.5 Post-Core Damage Mitigative Operator Intervention Strategy ..........................121

Table B.1 Summary of Assumptions for the Task 8 PRA Event Sequences, 

September 2004................................................................................................ B-2

Table B.2 Summary of SG Tube Failure Margin Results for the Task 8 PRA Event 

Sequences ........................................................................................................ B-4

Table B.3 Summary of Assumptions for the Phase 3 PRA Event Sequences, 

January 2005..................................................................................................... B-6

Table B.4 Summary of SG Tube Failure Margin Results for the Phase 3 PRA Event 

Sequences ........................................................................................................ B-8

Table C.1 Description of Control Volumes for the Energy Balance Analysis..................... C-3

Table D.1 Summary of Sensitivity Runs Implementing Variations in the Uncertainty 

Study Independent Variables ............................................................................ D-4

Table D.2 List of Sensitivity Calculations ........................................................................... D-8
xiv

Table D.3 Comparison of SCDAP/RELAP5-Calculated Results for Failure Times 

and Margins for the Cases Used in the Uncertainty Analysis.......................... D-16

Table D.4 Comparison of SCDAP/RELAP5-Calculated Results for Temperatures 

and Wall Heat Transfer Coefficients for the Cases Used in the Uncertainty 

Analysis ........................................................................................................... D-17

Table D.5 SCDAP/RELAP5-Calculated Results for Case 8G, Evaluating Sensitivity 

to SG Secondary Steam Leak Flow Area Assumptions .................................. D-46

Table D.6 Compilation of Differences Between the SCDAP/RELAP5-Calculated 

Results from the Sensitivity and Base Case Runs for the SG Tube Failure 

Margin and SG Tube Temperature Dependent Variables............................... D-56

Table D.7 Compilation of Differences Between the SCDAP/RELAP5-Calculated 

Results from the Sensitivity and Base Case Runs for the Hot Leg and 

Surge Line Temperature and Heat Transfer Coefficient Dependent 

Variables ......................................................................................................... D-57

Table D.8 Standard Deviations for the Dependent Variables Calculated Using Four 

Methods........................................................................................................... D-59

Table D.9 Base Case Values and Recommended Standard Deviations for the 

Dependent Variables....................................................................................... D-60
xv

EXECUTIVE SUMMARY 

The U.S. Nuclear Regulatory Commission (NRC) has been sponsoring research to evaluate the 

risks associated with steam generator (SG) tube failure during severe accidents in pressurizedwater reactors (PWRs) as part of the agency’s Steam Generator Action Plan. For PWRs with 

U-tube SGs, the natural circulation of superheated steam in the loop piping during specific low 

probability severe accident conditions could result in sufficient heating of the SG tubes to induce 

creep rupture failure under certain scenarios. To support an overall examination of the risk 

impacts of induced tube failure, thermal-hydraulic analyses have been performed. The 

analyses used the SCDAP/RELAP5 systems analysis computer code, aided by computational 

fluid dynamics (CFD) simulations, to examine the pressure and temperature conditions that 

challenge the integrity of the reactor coolant system pressure boundary and to estimate the 

timing of specific reactor coolant system component failures. 

These evaluations have focused on station blackout (SBO) severe accident scenarios in 

Westinghouse four-loop PWRs. The scenarios that challenge the tubes primarily involve a 

counter-current natural circulation flow pattern during conditions referred to as high-dry-low. 

The high-dry-low scenario refers to a set of conditions that includes a high pressure in the 

reactor coolant system (RCS), a loss of SG water inventory and a failure to provide a source of 

feedwater (dry), and a significant leak from the SG secondary side boundary that results in a 

low pressure on the secondary side of the SG tubes. Another condition posing a challenge to 

steam generator tubes is associated with full-loop natural circulation flows that are possible if 

the water in the loop seal is cleared and the reactor vessel downcomer is cleared. Based on 

our recent SCDAP/RELAP5 analysis, this condition is considered to be much less likely than the 

condition of counter-current natural circulation flow. 

During an SBO that results in the counter-current natural circulation flows, hot steam from the 

upper plenum of the reactor vessel (RV) enters the hot leg (HL) and flows toward the SG. This 

hot steam flows along the upper half of the HL and enters the SG inlet plenum (forming a hot 

rising plume) where it mixes with cooler steam. After significant mixing and entrainment of 

cooler steam, the forward-flowing steam enters a portion of the SG tubes and flows to the SG 

outlet plenum. With the loop seals filled with water, this steam cannot continue in the forward 

loop direction and must turn around in the SG outlet plenum and flow back to the inlet plenum 

and ultimately back through the lower half of the HL to the vessel upper plenum. This returning 

steam flow, which has passed through SG tubes in both directions, is significantly cooler than 

the flow leaving the vessel. Through mixing and entrainment, this steam flow helps to reduce 

the temperature of the hottest steam that enters the SG tubes. These natural-circulation-driven 

counter-current flow patterns carry the energy away from the RV and out into the loops where it 

heats up the RCS piping and SG tubes. The overall mass flow and heat-transfer rates, along 

with the amount of mixing and entrainment between the hottest and cooler flows, are significant 

factors in determining the timing of the RCS failures. 

A severe accident-induced failure of a SG tube releases radioactivity from the RCS into the SG 

secondary coolant system from where it may escape to the environment through the pressure 

relief valves. An environmental release in this manner is called “containment bypass,” which 

contrasts with releases into the containment that result from failures of HL piping, pressurizer 

surge-line piping, or the lower head of the RV. The potential for steam generator tube failure by 

creep rupture and containment bypass under the high-dry-low conditions is effectively 

eliminated if (1) the RCS pressure is reduced because of operator actions to intentionally 
xvi

depressurize the RCS or primary system leakage (eliminating the high-pressure condition), (2) 

feedwater flow is maintained (eliminating the dry condition and reducing RCS pressure), or (3) 

the SG secondary system retains pressure (eliminating the low-pressure condition on the 

secondary side). 

The clearing of a loop seal eliminates the counter-current flow pattern described above and 

creates a challenging environment for SG tubes. Loop seal clearing (along with a clearing of 

the fluid in the RV lower downcomer region) results in a direct natural circulation path around 

the coolant loop (RV, HL, SG, cold leg). Loop seals are more likely to clear when the water in 

the loop seals is heated and a rapid depressurization occurs. If loop seals are cleared and full 

loop natural circulation is established, the hot steam from the RV challenges the integrity of the 

SG tubes. 

The timing of the failure of the system components is significant. If a SG tube or tubes are 

predicted to fail prior to the HL or other RCS components, steam and radioactive fission 

products (released during core degradation) pass into the SG secondary system and provide a 

potential for containment bypass. Predictions indicate that a HL or other RCS component will 

fail shortly after a SG tube fails because the SG tube failures do not immediately depressurize 

the system. The subsequent failure of the RCS boundary significantly reduces the rate of mass 

flow from the primary system into the SG secondary system. Alternatively, if a HL or other RCS 

component of significant size fails prior to an SG tube, the release of contaminated steam would 

be completely into the containment because the resulting rapid RCS depressurization prevents 

subsequent failures of SG tubes and the associated containment bypass. 

Some previous NRC analysis indicated that an unflawed tube in the hottest region of the SG 

could fail just prior to the HL for certain high-dry-low conditions. After further review of the 

SCDAP/RELAP5 modeling approach, it was found that the HL radiation model was not 

appropriate under these conditions and also that the hottest tube prediction was biased toward 

higher temperatures. NRC addressed these issues with updated models as described in this 

report. The improved models predict HL failure prior to an unflawed tube in the hottest region of 

the SG. The updated predictions indicate that it requires the addition of a stress multiplier in the 

range of 1.5 to 2.0 to predict a hottest SG tube failure just prior to the HL failure under the base 

case high-dry-low conditions. The stress multiplier is used as a means to account for tubes with 

flaws or other degradation in the tube bundle. The stress multiplier of 2.0 is considered 

bounding for tube flaws in a typical steam generator. The hottest temperatures in the SG tube 

bundle are estimated based on CFD predictions of the natural circulation flows from the inlet 

plenum to the tube bundle. These current predictions have some identifiable conservatisms. 

First, the tube modeling assumes the potential flaws are just above the tube sheet in the hottest 

section of the tube bundle. In addition, the SCDAP/RELAP5 predictions use a simplified onedimensional HL failure model. Simulations that have accounted for the multidimensional 

aspects of the HL structure and thermal boundary conditions (ABAQUS calculations) have 

indicated earlier HL failure times. For the purposes of this report, the failure times for the hottest 

tube and the HL are reported directly from the SCDAP/RELAP5 model, and these provide a 

means of screening scenarios and evaluating sensitivities and uncertainties in the thermalhydraulic modeling. Best-estimate modeling of HL failure time should include the full impact of 

the thermal entrance effects on the heat-transfer coefficient and the details of the junction 

between the carbon steel material in the vessel outlet and the stainless steel HL. 

Event sequence scenario assumptions and modeling methods have significantly evolved over 

the years of research described in this report. This report documents the current predictions for 

system behavior during extended SBO scenarios. The objective of this report is to combine the 
xvii

findings from prior evaluations and selected new evaluations into a view of the Westinghouse 

four-loop PWR extended SBO severe accident event sequences that fall into the following three 

categories: 

1. Sequences resulting in containment bypass. 

2. Sequences providing a potential for containment bypass for which an outcome may be 

determined by initially comparing the degradation of tube strengths in a prototype SG 

against the SCDAP/RELAP5-predicted tube-failure margins. 

3. Sequences not resulting in containment bypass. 

This categorization of event sequences provides information that—when combined with results 

from RCS component analyses, probabilistic risk assessments, and environmental release 

evaluations—will permit an evaluation of risks due to containment bypass for Westinghouse 

four-loop plants. 

A model of a Westinghouse four-loop plant is developed for use with the SCDAP/RELAP5 

thermal-hydraulic system code and employed to perform simulations of accident-event 

sequences pertinent for the containment bypass issue. The SCDAP/RELAP5 code calculates 

fluid and structure conditions, such as pressures and temperatures, throughout the regions of a 

plant model. In addition, the code includes models for calculating the progression of coredamage behavior during severe accidents and simplified models for creep rupture behavior of 

RCS components. In the Westinghouse four-loop plant model, creep-rupture behavior is 

evaluated with SCDAP/RELAP5 to predict failure times for the HLs, pressurizer surge line, and 

SG tubes. The creep-rupture model allows one to specify a “stress multiplier.” A multiplier of 

1.0 provides a creep rupture failure prediction based on no degradation of the structural strength 

of the material. Multipliers greater than 1.0 represent degraded structural strengths associated 

with preexisting tube flaws or degradation that may exist. A stress multiplier of 2.0, for example, 

represents a degraded-strength condition for which the creep-rupture failure of a structure is 

predicted when the stress applied is only 50 percent of that required to fail the undegraded 

structure. The term “SG tube failure margin” as used in this report refers to the tube-stress 

multiplier in the model that results in prediction of SG tube creep-rupture failure coincident with 

the earliest failure of another RCS pressure boundary component, typically a HL. Therefore, 

tubes with higher stress multipliers are predicted to be the first RCS pressure-boundary 

components to fail, in which case containment bypass occurs. Two SG tube failure margins— 

one for the average tube and another for a tube in the hottest region of the SG—represent the 

key output from the SCDAP/RELAP5 event sequence simulations. 

Assessments are made of SCDAP/RELAP5 code capabilities for predicting the plant behavior 

during an SBO event. In these assessments, particular attention is paid to code capabilities for 

predicting phenomena important to these scenarios and for predicting the behavior deemed to 

be the most significant with respect to the timing of SG tube failures. In addition, estimates are 

made of the uncertainties associated with the SCDAP/RELAP5 predictions for key fluid and 

component conditions and for the SG tube failure margins. 

A base case SBO accident event sequence is defined to serve as a reference case from which 

sensitivity evaluations may be made to determine the event sequence, plant configuration, and 

plant condition parameters that have the most important influence on the SG tube failure 

margins. The base case event sequence was selected to ensure that the plant quickly entered 

the high-dry-low state so that this specific condition could be studied efficiently (i.e., the 
xviii

calculation transient time was shortest, in a bounding way). It is noted that this approach 

requires a significant number of assumptions that are conservative and are of low probability. 

The base case assumptions are listed below: 

 The accident is initiated by a loss of offsite alternating current (AC) power, which 

immediately results in reactor and turbine trips and the coast-down of the four reactor 

coolant pumps (RCPs). The diesel-electric generators fail to start and, as a result, all AC 

power sources are lost. Letdown flow is isolated, and the pressurizer level control and RCP 

seal injection functions of the charging system are lost. The high-pressure and low-pressure 

safety injection systems and RCP seal cooling are unavailable as a result of the AC power 

loss. 

 The accumulator systems are available for injecting coolant into the cold legs should the 

RCS pressure fall below the initial accumulator pressure. The main feedwater (MFW) flow 

stops and the motor-driven auxiliary feedwater (MDAFW) system is unavailable as a result 

of the AC power loss. The turbine-driven auxiliary feedwater (TDAFW) system is assumed 

to independently fail immediately, so no main or auxiliary feedwater system is operable. 

 A station battery life of 4 hours is assumed; after that time, all automatic and operator control 

over the pressurizer power operated relief valves (PORVs) and SG secondary system 

PORVs is lost. 

 A steam leak path, with a flow area of 3.23 cm2

 [0.5 in2], is assumed to be present in each of 

the four SGs; leakage through these paths into the turbine system depressurizes the SGs 

prior to core heatup. 

 The loss of RCP seal injection cooling flow is assumed to result in leakage of RCS coolant 

through shaft seals into the containment at 1.325-L/s [21.0-gpm] in each of the four RCPs. 

 No operator intervention is assumed to occur, whether by emergency procedures, severe 

accident management guidelines, or recent security-related mitigation measures. 

Beyond the SCDAP/RELAP5 base case event sequence simulation, many additional 

SCDAP/RELAP5 simulations are performed to evaluate the effects of variations in the event 

sequence assumptions, the plant configuration, the system operation, and mitigative operator 

intervention. Of particular interest are variations in the event sequence assumptions deemed to 

be most important for the containment bypass outcome—the RCP shaft seal leakage rate and 

the timing of seal failures, the size of the SG steam leakage flow paths, and the startup and 

continued operation of the TDAFW system or alternate feedwater makeup. 

Event sequences are categorized relative to the potential for containment bypass using the 

following criteria based on the SCDAP/RELAP5-predicted hottest SG tube failure margin: 

 Containment bypass is assumed if the 1.0-stress multiplier (i.e., undegraded) hottest SG 

tube is predicted to fail prior to the HL, pressurizer surge line, or RV. 

 A potential for containment bypass is assumed if the hottest SG tube failure margin is 

between 1.0 and 3.0. In this case, data for the actual SG tube strengths and their 

distribution resident in a prototype SG are needed to determine the outcome. 
xix

 Containment bypass is not indicated if the hottest SG tube failure margin is 3.0 or higher. 

The major findings of the extended SBO event sequence categorization for Westinghouse 

four-loop PWRs are summarized as follows. 

For situations where the operators are assumed to take no action: 

 Event sequences that do not involve secondary side depressurization (i.e., leakage from the 

secondary system of 0.64 cm2

/SG [0.1 in2/SG] and smaller) generally do not result in 

containment bypass. The reduced SG tube stresses resulting from the SG secondary 

pressures remaining elevated prevent SG tubes from failing prior to the HL, surge line, or 

RV. 

 Event sequences that assume RCP shaft seal leakage rates lower than 11.36 L/s [180 gpm] 

per pump generally provide a potential for containment bypass. Event sequences that 

assume RCP shaft seal leakage rates of 11.36 L/s [180 gpm] per pump and higher generally 

do not result in containment bypass. A high leak rate leads to lower RCS pressures, and the 

reduced SG tube stresses prevent SG tubes from failing prior to the HL, surge line, or RV. 

However, exceptions exist related to the time when RCP shaft seal failures are assumed to 

occur. For RCP shaft seal failures that occur late in the event sequences, loop seal clearing 

and, therefore, containment bypass can occur for leakage rates above 25.23 L/s [400 gpm] 

per pump. 

 Event sequences in which the TDAFW system operates and continues operating (or 

alternate feedwater is available) do not result in containment bypass. The outer surfaces of 

the SG tubes remain wet, and the RCS heat removal provided prevents system heatup. 

 For event sequences in which the TDAFW system is assumed to initially operate and later 

fail, the likelihood of tube rupture is predicted to be very similar to scenarios where the 

TDAFW does not operate at all because eventually, without other mitigation, the system may 

reach the high-dry-low condition. However, the timing of potential tube failures is 

significantly delayed by the initial operation of the TDAFW system. Challenges to continued 

TDAFW operation are a result of depletion of the station batteries or the depletion of the 

condensate storage tank inventory. Probabilistically, additional mitigation should be 

considered as well as the likelihood that auxiliary feedwater may not be maintained.

For situations where the operators take mitigative action: 

 An evaluation was performed for a strategy in which operators implement SG feed-andbleed cooling at 30 minutes into the event sequence (using the TDAFW system and opening 

the SG PORVs). The evaluation shows that this strategy is effective in the short term for 

preventing containment bypass. At a minimum, the onset of the RCS heatup is significantly 

delayed, thereby providing additional time for other plant recovery opportunities to be 

considered and implemented. In the long term, the SG PORVs fail closed when the 

batteries are depleted, and continued success of this strategy requires that a TDAFW water 

source remains available along with some capability for delivering the water into the SGs. 

For sequences in which the TDAFW system initially operates but later fails, no large 

changes in SG tube failure margins (relative to the no-intervention case) were predicted. 
xx

 An evaluation was also performed for a post-core damage strategy in which the 

operators depressurize the RCS by opening one or two pressurizer PORVs after 

plant instrumentation indicates that core cooling is inadequate. PORVs are opened 

at the time when the core exit temperature reaches 922 K (1,200 o

F) or 12 minutes 

later. The evaluation shows that opening only one PORV limits the cooling afforded 

to the RCS, the core fails early (prior to battery depletion), and containment bypass is 

avoided for both operator action times. The evaluations also show that the greater 

RCS cooling afforded by opening two PORVs prevents early core damage and also 

prevents early failure of the HL and SG tube structures. When the PORVs fail closed 

after battery depletion, the RCS begins repressurizing and reheating, and this 

subsequently leads to HL and SG tube failures. The SG tube failure margins seen 

for the operator intervention cases are significantly improved (relative to the nointervention cases), and containment bypass is seen to be avoided for both of the 

post-core damage operator action times. 
xxi

ACKNOWLEDGEMENTS 

The authors wish to acknowledge James Han and Osvaldo Font of NRC for their technical 

direction of the work described here. 

The authors wish to acknowledge David Bessette and Steve Long of NRC and consultants 

Marino DiMarzo and Peter Griffith for their helpful suggestions during reviews of the work 

described here. 

The authors wish to acknowledge the efforts of Colleen Amoruso of ISL for technical editing and 

other support needed to publish this report. 
xxii 
xxiii 

NOMENCLATURE 

AC alternating current 

ACRS Advisory Committee on Reactor Safeguards 

AFW auxiliary feedwater 

CCFL counter-current flow limiting 

CD hot leg discharge coefficient 

CE Combustion Engineering 

CFD computational fluid dynamics 

CST condensate storage tank 

ECC emergency core cooling 

EPRI Electric Power Research Institute 

FW feedwater 

HL hot leg 

HPI high-pressure injection 

INEL Idaho National Engineering Laboratory 

ISL Information Systems Laboratories, Inc. 

MDAFW motor-driven auxiliary feedwater 

MFW main feedwater 

MIT Massachusetts Institute of Technology 

NTR normalized temperature ratio 

NRC U. S. Nuclear Regulatory Commission 

NRR NRC Office of Nuclear Reactor Regulation 

PIRT phenomena identification and ranking table 

PORV power-operated relief valve 

PRA probabilistic risk assessment 

PWR pressurized-water reactor 

RCP reactor coolant pump 

RCS reactor coolant system 

RES NRC Office of Nuclear Regulatory Research 

RV reactor vessel 

SOARCA State-of-the-Art Reactor Consequences Analyses Project 

SBLOCA small break loss-of-coolant accident 

SBO station blackout 

SG steam generator 

SGAP Steam Generator Action Plan 

SL surge line 

SRV safety relief valve 

TDAFW turbine-driven auxiliary feedwater

1

1. INTRODUCTION 

The U. S. Nuclear Regulatory Commission (NRC) has been conducting studies to evaluate the 

risks associated with steam generator (SG) tube failure following low probability severe 

accidents in pressurized water reactors (PWRs). For PWRs with U-tube SGs, the natural 

circulation of superheated steam in the loop piping during severe accidents could result in 

sufficient heating of the SG tubes to induce creep rupture failure prior to hot leg (HL) or 

pressurizer surge line failure. To examine the risk impacts of induced SG tube rupture, severe 

accident thermal-hydraulic analyses have been performed. The analyses use the 

SCDAP/RELAP5 systems computer code, aided by computational fluid dynamics (CFD) 

simulations, to examine the pressure and temperature conditions imposed on the SG tubes and 

system piping. 

These evaluations have focused on tube integrity during station blackout (SBO) severe accident 

scenarios in Westinghouse four-loop PWRs. A schematic of a Westinghouse four-loop plant is 

shown in Figure 1.1. During these hypothetical accident scenarios a set of “high-dry-low” 

conditions is experienced. The reactor coolant system (RCS) loses its cooling water and 

remains at “high” pressure, the SG water inventory is lost and no source of feedwater is 

assumed available causing “dry” SG conditions. This type of event exposes the SG tubes to 

highly-superheated steam at the high RCS pressures associated with the opening set-point 

pressures of the pressurizer power operated relief valves (PORVs) and safety relief valves 

(SRVs). In the event the secondary coolant system is depressurized due to leaking relief valves 

or other system steam leaks, leading to “low” SG secondary pressures, this hypothetical event 

sequence provides a potential for SG tubes to contain high-pressure steam on the inside and 

low-pressure steam on the outside. This pressure differential, coupled with rapidly-increasing 

system temperatures caused by the uncovering and heat-up of the reactor core provide a 

potential for SG tube failure. 

A failure of a SG tube releases radioactivity from the RCS into the SG secondary coolant 

system, from where it has the potential to escape to the environment through the secondary 

coolant system pressure relief valves. An environmental release in this manner is called 

“containment bypass” which contrasts with releases into the containment that result from failure 

of HL or pressurizer surge line piping or of the reactor vessel (RV). 

The sequential order in which the system components fail is therefore of importance because 

(1) it affects the destination of the radioactive release and (2) it affects the thermal-hydraulic and 

stress conditions in the other components, and therefore their likelihood of subsequently failing. 

If a SG tube is the first component to fail, the release into the SG secondary system provides a 

potential for containment bypass but if a HL, the pressurizer surge line, or the RV is the first 

component to fail the release is instead made into the containment and the depressurization of 

the RCS prevents subsequent failures of SG tubes. However, analysis demonstrates that even 

if a SG tube is the first component predicted to fail, the HL is predicted to subsequently fail 

shortly thereafter, thereby mitigating the release of radioactivity into the secondary side and 

directing most of the radioactive release into the containment. 
2

Figure 1.1 Schematic of Westinghouse Four-Loop Pressurized Water Reactor 
3

1.1 Objective of This Report

Extensive evaluations of the containment bypass issue for Westinghouse four-loop plants have 

been performed over the past 12 years. The objective of this report is to coalesce the findings 

from those former evaluations, along with selected additional evaluations, into a view of the 

SBO severe accident event sequences that fall into each of the following three categories: 

 Sequences resulting in containment bypass. 

 Sequences with a potential to result in containment bypass, for which an 

outcome may be determined by comparing the degradation of tube strengths in a 

prototype SG against the SCDAP/RELAP5-predicted tube failure margins. 

 Sequences not resulting in containment bypass. 

This categorization of event sequences provides information that (when combined with results 

from pertinent SG tube structural analyses, probabilistic risk assessments and environmental 

release evaluations) permits an evaluation of risks due to containment bypass for Westinghouse 

four-loop plants. This work is currently underway within the Office of Nuclear Regulatory 

Research, Division of Risk Analysis. 

To explain the process by which the event sequence categorization is performed, a base case 

SBO accident scenario is first defined for the purpose of illustrating the thermal hydraulic 

technical issues associated with the containment bypass issue. The base case event sequence 

is not considered a most-likely accident scenario. The expected plant behavior during the base 

case event sequence is discussed in order to explain the relevant technical issues and describe 

criteria by which and event-sequence outcome relative to the three above categories can be 

judged. 

1.2 Description of a Base Case Station Blackout Accident Scenario

The Westinghouse four-loop plant conditions at the start of the base case accident scenario 

represent full-power operation of the plant with 10% of the 3,388, 1.97-cm [0.775-in] inner 

diameter, tubes plugged in each SG: a reactor power of 3,250 MW, a RCS pressure of 

15.51 MPa [2,250 psia], an average RCS temperature of 567.7 K [562.2°F], a total coolant loop 

flow rate of 17,010 kg/s [135 Mlbm/hr] and a SG secondary system pressure of 4.964 MPa 

[720 psia]. 

The accident event is initiated by a loss of off-site alternating current (AC) power, which 

immediately results in reactor and turbine trips and the coast-down of the four reactor coolant 

pumps (RCPs). The diesel-electric generators fail to start and as a result all AC power sources 

are lost. Letdown flow is isolated and the pressurizer level control and RCP seal injection 

functions of the charging system are lost. The high-pressure and low-pressure safety injection 

systems are unavailable as a result of the AC power loss. The accumulator systems are 

available for injecting coolant into the cold legs should the RCS pressure fall below the initial 

accumulator pressure, 4.24 MPa [615 psia]. The main feedwater (MFW) flow stops and the 

motor-driven auxiliary feedwater (MDAFW) system is unavailable as a result of the AC power 

loss. The turbine-driven auxiliary feedwater (TDAFW) system is assumed to independently fail, 

so no MFW or auxiliary feedwater (AFW) system is available. A station battery life of four hours 
4

is assumed; after that time all automatic and operator control of the pressurizer PORVs and SG 

secondary system PORVs is lost. 

Because the feedwater and steam flow paths are isolated at the beginning of the event 

sequence, the SG secondary system pressures initially rise. The SG secondary water inventory 

boils and the SG PORVs open to limit the SG secondary system pressure increase. Minor 

steam leak paths from the SGs are assumed to be present. Constant steam leak flow areas of 

3.23 cm2

 [0.5 in2] are assumed in each SG, resulting in a leakage rate that is about 0.7% of the 

full-power steam flow rate. The effect of these steam leaks is to slowly depressurize the SGs 

over a period of about two hours following the time when the SG water inventories have been 

completely boiled away. 

The loss of RCP seal injection cooling flow is assumed to result in leakage of RCS coolant 

through the RCP shaft seals and into the containment starting at the beginning of the SBO 

event sequence. An initial 1.325-L/s [21.0-gpm] shaft seal leak rate is assumed in each of the 

four RCPs. This rate is considered to be a postulated minimum flow rate under conditions 

where RCP seal cooling is lost and not recovered. The seal leak path characteristics and flow 

areas are assumed not to change over the course of the event sequence and the leak flow rates 

are therefore subsequently determined by the transient fluid conditions in the RCPs and 

containment. It is noted that this shaft seal leakage rate is considered to be the postulated 

minimum flow following a loss of seal injection flow. Other higher shaft seal leak rates may also 

be experienced as a result of various possible seal hardware failures. 

1.3 Plant Behavior During the Base Case Accident Scenario

The low-probability SBO base case accident event scenario described in Section 1.2 results in a 

severe accident because none of the systems that normally provide core cooling are assumed 

to be operable nor is any alternate equipment (e.g., security-related mitigation methods) 

assumed to be available. During the initial portion of the accident scenario, buoyancy-driven 

coolant-loop natural circulation carries hot water from the core through the SGs, transferring 

heat to the SG secondary water inventory. The SG water inventory is boiled and the steam is 

released through the SG PORVs. Since the MFW and AFW systems are not operative, the 

secondary water inventory declines and is eventually fully depleted. After that time, the core 

decay power heats and swells the RCS water, increasing its temperature and pressure. During 

this process, the RCS pressure increase is limited by the opening of the pressurizer PORVs and 

SRVs. However, the RCS fluid lost through those valves (as well as through the RCP shaft 

seals) is not recoverable and the RCS coolant inventory continuously declines. Eventually, the 

RCS inventory loss becomes extreme, the core uncovers and the fuel starts to heat up. The 

fuel heat-up leads to an exothermic oxidation reaction between the steam and the fuel rod 

cladding that adds heat to the fuel in addition to the heat generated from the fission product 

decay process. 

The basic physical processes of this event sequence during the period when the steam 

temperatures are rising regard the transport of hot steam from the core outward into the other 

regions of the RV and coolant loops. Figure 1.2 shows two coolant loop natural circulation flow 

patterns that may be encountered subsequent to the uncovering and heat-up of the reactor 

core. The flow patterns differ based upon whether or not the loop seals (the cold leg piping 

connecting the outlets of the SGs to the inlets of the RCPs) remain liquid-plugged. 

If liquid is cleared from a loop seal (along with the region of the RV lower plenum that extends 

above the bottom of the core barrel, the “downcomer skirt”), the loop natural circulation flow 
5

pattern on the left side of Figure 1.2 develops. Hot steam is transported from the core through 

the HLs, SG tubes and cold legs in the normal direction of flow (i.e., that seen during plant 

operation). This flow pattern transports the hot steam directly (without benefit of mixing) through 

all of the SG tubes, leading to SG tube failure prior to HL or pressurizer surge line failure. 

However, if a loop seal remains liquid-plugged, the more complex flow pattern shown on the 

right side of Figure 1.2 develops instead. Hot steam is transported through the upper portion of 

the HL cross section to the SG inlet plenum, where it is mixed with cooler steam emanating from 

circulations set up as shown within the SGs, with some of the tubes flowing in the normal 

direction and the remaining tubes flowing in the reverse direction. The mixing process within 

the SG inlet plenum determines the temperatures of the steam entering the SG tubes and the 

steam that is returned to the RV through the lower portion of the HL cross section. Fluid mixing 

in the SG inlet plenum buffers the entry of hot steam into the SG tubes, thus delaying SG tube 

failure and making it more likely that some other component (HL, pressurizer surge line or RV) 

will be the first to fail. 

The issues of primary interest for containment bypass are: (1) do the loop seals in all coolant 

loops remain liquid plugged and if so (2) does the fluid mixing in the SG inlet plenum sufficiently 

slow the SG tube heat-up process so that the HL, pressurizer surge line or RV will fail prior to a 

SG tube? The analyses in this report address these issues, evaluating them for the base case 

and other accident event sequences. 

Figure 1.2 Potential Coolant Loop Natural Circulation Flow Patterns During System 

Heat-Up 
6

1.4 Definition of SG Tube Failure Margin and Criteria for Judging Occurrence 

of Containment Bypass

Predictions of structural failure are made based on the structure configuration, its material 

properties and the fluid conditions that are locally present. The SCDAP/RELAP5 

thermal-hydraulic system code calculates the local fluid conditions, such as pressures and 

temperatures, throughout the fluid regions of a model which represents a power plant. The 

code also includes models for calculating the creep rupture failure of structural components and 

these are used to predict failure times for the HLs, pressurizer surge line, and SG tubes for the 

Westinghouse four-loop plant model. It is noted that the SCDAP/RELAP5-calculated 

predictions of structural failures are intend to provide a screening tool to assess structural failure 

issues. These predictions are not intended to supplant failure evaluations using more detailed 

analysis tools. 

The SCDAP/RELAP5 creep rupture model allows one to specify a “stress multiplier.” A 

multiplier of 1.0 provides a creep rupture failure prediction based on no degradation of the 

structural strength of the material. Multipliers greater than 1.0 represent degraded structural 

strengths. A stress multiplier of 3.0, for example, represents a degraded-strength condition for 

which the creep-rupture failure of a structure is predicted when the stress applied is only 33.3% 

of that required to fail the undegraded structure. A stress multiplier of 3.0 is considered to be a 

conservative upper bound for screening the steam generator tube failures. (The meaning of 

“stress multiplier” as used in this report is the same as “stress magnification factor” as used in 

the previous NUREG-1570 analysis described in Section 2.1). In the SCDAP/RELAP5 

Westinghouse plant model, creep rupture failure calculations are performed for the “average” 

SG tubes and HLs in all four coolant loops, and for the pressurizer surge line and “hottest” SG 

tube in the pressurizer-loop SG. The terms average and hottest SG tubes, respectively, refer to 

tube models which transport fluids that are at the average and highest temperatures among all 

of the SG tubes. 

For the Westinghouse four-loop plant model, a stress multiplier of 1.0 is used for the HL and 

pressurizer surge line structure calculations while stress multipliers from 1.0 to 7.5 (in 

increments of 0.5) are used for the SG tube calculations. Therefore creep rupture predictions 

for the HL and pressurizer surge line structures are based on undegraded material strengths 

while the creep rupture predictions for the SG tubes are based on a spectrum of material 

strengths, from undegraded to highly-degraded. The purpose of evaluating a spectrum of SG 

tube strengths is to consider parametrically in the analysis a distribution of SG tube material 

strengths. Stress multipliers up to 7.5 are not realistic for any steam generator but these values 

are tracked so that sensitivities to various modeling parameters could be established. The 

actual distributions vary from plant to plant, as functions of the tube material specifications, time 

in service, and other factors. 

The term “SG tube failure margin” as used in this report refers to the tube stress 

multiplier in the model which results in prediction of SG tube creep rupture failure 

coincident with the earliest failure of another RCS pressure boundary component (HL, 

pressurizer surge line, or RV). 

Tubes with higher stress multipliers are therefore predicted to be the first RCS pressure 

boundary component to fail, in which case RCS fluid flows into the SG secondary system, 

leading to containment bypass. Two SG tube failure margins, one for the average tube and 

another for the hottest tube, are the key results of the event sequence simulations. 
7

In the more recent SCDAP/RELAP5 analyses described in this report, a HL is typically predicted 

to fail prior to the pressurizer surge line. In some of the SCDAP/RELAP5 simulations, the core 

damage process is accelerated and core fuel rod melting and refreezing, core flow blockage 

and relocation of molten core materials to the lower head of the RV are predicted prior to HL, 

pressurizer surge line or SG tube failures. The prediction of core damage that significantly 

alters the configuration of the core is taken as a proxy for RV failure. The challenge to SG tubes 

integrity is removed if core fuel damage is sufficient to entirely block the flow of steam through 

the core (thereby stopping the robust flow of hot steam to the SGs) or sufficient to convert the 

core into an uncoolable molten mass that slumps into the lower head region of the RV (in which 

case the flow of core heat into the steam virtually ceases). 

Criteria are needed in order to judge whether or not containment bypass is predicted to occur 

for a particular event sequence. The criteria used in this report are based on the 

SCDAP/RELAP5 predicted hottest SG tube failure margin: 

 Containment bypass is indicated if the 1.0-stress multiplier (i.e., 

undegraded) hottest SG tube is predicted to fail prior to the HL. (For these 

challenging event sequences the definition for the “SG tube failure margin” 

is changed to instead indicate the time in seconds by which the hottest SG 

tube failure precedes the HL failure). 

 A potential for containment bypass is indicated if the hottest SG tube 

failure margin is between 1.0 and 3.0. In this case, data for the actual SG 

tube strengths and their distribution resident in a prototype SG is needed 

in order to determine the outcome. 

 Containment bypass is not indicated if the hottest SG tube failure margin is 

3.0 or higher.

These criteria and the results of SCDAP/RELAP5 simulations for SBO event sequences are 

used to group the event sequences into the three categories of containment bypass behavior 

described in Section 1.1. It is noted that the criteria are somewhat arbitrary and are necessarily 

subject to uncertainties related to the characteristics of SG tubes actually resident in a specific 

SGs, as well as uncertainties in SCDAP/RELAP5 modeling such as are described in 

Sections 2.9 and 5.4 of this report. 

1.5 Organization of This Report

Section 2 of this report provides background on prior thermal-hydraulic containment bypass 

evaluations. Section 3 describes the thermal-hydraulic analysis methods used, including 

descriptions of the SCDAP/RELAP5 computer code, assessments of its capabilities pertinent for 

the containment bypass application and aspects of the modeling which have benefitted from 

ongoing CFD analyses. Section 4 summarizes the SCDAP/RELAP5 model of the 

Westinghouse four-loop plant and the detailed results from the base case SBO accident 

calculation. Section 5 describes key sensitivity analyses performed to evaluate variations in the 

event sequence assumptions, plant configuration, system operation and mitigative operator 

intervention. The categorization of event sequences into the three above categories is 

performed in Section 6; the information provided in this section is considered to be the main 

product of the detailed research summarized in this report. Conclusions are presented in 
8

Section 7 and references are provided in Section 8. Details of supporting analyses are provided 

in the appendixes of this report. 
9

2. BACKGROUND 

This section describes background studies, reviews and preliminary SCDAP/RELAP5 sensitivity 

evaluations into the containment bypass issue performed over the period from 1995 through 

2007. The material presented here is intended to provide a historical perspective on the 

SCDAP/RELAP5 containment bypass systems analysis research. This perspective is useful 

both for understanding the evolution of the SCDAP/RELAP5 model and for summarizing the 

results from prior sensitivity evaluations, many of which remain pertinent today. 

2.1 NUREG-1570 Analyses, 1998-2000

An assessment of PWR containment bypass potential attributable to SG tube rupture induced 

by severe accidents was first made by an ad hoc NRC working group. This group began work 

in 1995 and published its findings in NUREG-1570, March 1998 (Reference 2.1). The study 

drew upon risk and thermal-hydraulic analyses for various core damage sequences and 

concluded that the primary accident sequence of interest for containment bypass was a SBO 

event, coupled with a failure of AFW, the depressurization of at least one SG secondary system 

and no operator intervention. 

The containment bypass susceptibility for this type of event sequence was found to be limited to 

plants that employ U-tube type SGs, plants of Westinghouse and Combustion Engineering (CE) 

design. Experimental evidence (Reference 2.2) demonstrated that during this type of event 

sequence in Babcock and Wilcox design plants, which employ once-through type SGs, a flow of 

superheated gas does not reach the SG tube bundles and a heat-up of the SG tubes producing 

creep rupture tube failure is not encountered. 

The thermal-hydraulic analyses documented in NUREG-1570 were principally performed at the 

INEL using the SCDAP/RELAP5/MOD3.1 system code (Reference 2.3) and models of a 

Westinghouse three-loop plant and a CE plant. The purpose of these analyses was to provide 

the HL, pressurizer surge line and SG tube thermal-hydraulic conditions expected during SBO 

severe accident event sequences. Thermal-hydraulic calculations and analyses were 

performed for accident sequences identified by a Probabilistic Risk Assessment (PRA). 

Additional calculations and analyses were performed to address numerous other issues, such 

as variations in the accident sequence description, uncertainties in modeling the plant behavior 

and uncertainties in the boundary and initial conditions. 

The NUREG-1570 analyses also investigated the potential for loop seal clearing, which is of 

significance for the containment bypass issue as explained in Section 1.3. The analyses for 

both plants indicated: (1) loop seal clearing is not encountered prior to HL or pressurizer surge 

line failure when nominal 1.32 L/s [21 gpm] per pump RCP shaft seal leakage rates are 

assumed, and (2) loop seal clearing prior to HL or surge line failure is encountered when much 

larger RCP shaft seal leakage rates are assumed (15.8 L/s [250 gpm] for the Westinghouse 

plant and 13.9 L/s [220 gpm] for the CE plant). 

2.2 NUREG-1740 Independent Review and Steam Generator Action Plan, 

2000-2001

The Advisory Committee on Reactor Safeguards (ACRS) undertook an independent 

examination of the technical issues associated with voltage-based alternative repair criteria for 

SG tubes. The purpose of this examination was to provide comments and recommendations to 
10

the NRC for resolving a differing professional opinion concerning the adequacy of the repair 

approach documented in Generic Letter 95-05, Reference 2.4. This independent review was 

performed by an ad hoc subcommittee composed of ACRS members and consultants to assess 

the containment bypass potential attributable to SG tube rupture induced by severe accidents 

as documented in NUREG-1570. The ACRS subcommittee review was documented in 

NUREG-1740, Reference 2.5. The review findings related to thermal-hydraulic analysis of the 

containment bypass issue are summarized as follows: 

The reviewers reiterated the significance of loop seal behavior for the outcome of 

the analyses that was noted in NUREG-1570, adding that loop seal clearing 

considerations (including the potential for periodic clearing and refilling) increase 

the expected complexity of the plant response. 

The reviewers noted that the system computer codes (such as SCDAP/RELAP5) 

used for the analyses are lumped-parameter codes and do not make reliable 

predictions of natural circulation behavior or local phenomena involving fluid 

momentum. 

The reviewers noted that the system code input decks are “tuned” by 

benchmarking against experimental results, such as the Westinghouse oneseventh scale PWR model (Reference 2.6). They noted that such test results have 

been criticized because of improper scaling of the SG region of the test rig to the 

full-scale PWR SG. It was mentioned that one consequence of this scaling 

shortcoming could be overestimation of the mixing occurring in the SG inlet 

plenum, which would lead to delays in the heat-up and creep rupture failure of the 

SG tubes. They noted that the sensitivity studies regarding SG inlet plenum 

mixing performed as a part of the analyses have not evaluated the plausible 

ranges of parameter variations nor considered simultaneous variations of multiple 

parameters. 

Finally, the reviewers noted that the experiments did not consider the effects SG 

tube leakage and that related sensitivity studies have not considered the plausible 

range of variations in that parameter. 

In February, 2000 the NRC Office of Nuclear Reactor Regulation (NRR) provided a user need 

letter (Reference 2.7) to NRC Office of Nuclear Regulatory Research (RES) requesting that 

RES develop a confirmatory research program to address the thermal-hydraulic, 

dose-consequence and structural behavior of PWRs during postulated severe accidents. The 

letter included a request to develop models and methods that provide improved understanding 

of transient thermal-hydraulic conditions in the primary piping and SG tube regions of the 

reactor coolant system. 

The RES response to NRR, Reference 2.8, came in September 2000. The RES research plan 

built on the prior work performed in support of the NUREG-1570 assessment of containment 

bypass and included new work in the following areas: accident sequence variations, plant 

design differences, fluid mixing in the SG inlet plenum, tube-to-tube variation of the fluid 

conditions and the effects of variations in the core melt progression. The research plan included 

continued refinement and improvement of SCDAP/RELAP5 plant system models and accident 

sequence analysis performed with the upgraded models. The system analyses were to be 

complemented and enhanced with CFD models and analyses. The CFD models are employed 

to simulate local thermal-hydraulic behavior which is beyond the capabilities of the lumped-
11

parameter system models. The results of the CFD analyses also are employed to generate 

correlations and mixing parameters for the system model, thereby incorporating effects of the 

more-physical behavior generated with CFD into the system model. 

In May 2001, RES and NRR jointly developed a Steam Generator Action Plan (SGAP, 

Reference 2.9) to address the conclusions and recommendations contained in the 

NUREG-1740 ACRS review. The SGAP included thermal-hydraulic tasks to: perform system 

level analyses assessing the impact of plant sequence variations (Task 3.4a), re-evaluate 

existing system level code assumptions and simplifications (Task 3.4b), examine the 

one-seventh scale data to assess tube-to-tube variations and estimate those variations at the 

plant scale (Task 3.4c), perform a more rigorous uncertainty analysis regarding inlet plenum 

mixing behavior (Task 3.4d), examine the uncertainties related to the progression of the core 

melt process (Task 3.4f), and examine SG tube severe accident conditions using CFD methods 

including benchmarking of the model with the one-seventh scale test data, performing analysis 

of the local HL and SG behavior and addressing inlet plenum mixing effects of tube leakage and 

the HL-inlet plenum geometrical configuration (Task 3.4e). 

2.3 Revised Station Blackout Base Case Event Sequence and Analysis, 

2000-2003

Subsequent to the release of NUREG-1570, Idaho National Engineering Laboratory (INEL) 

performed SCDAP/RELAP5 analyses to support the SGAP. INEL evaluated SBO event 

sequence variations and modeling assumptions and the focus of the analysis was switched to 

Westinghouse four-loop plants. That switch was made because the four-loop plant is 

representative of a large number of PWRs; the understanding of the overall SGTR risk for the 

fleet of U. S. operating plants was thus broadened. 

INEL refined the SCDAP/RELAP5 Westinghouse four-loop plant model for simulating the SBO 

accident sequence, including benchmarking of SG inlet plenum fluid mixing behavior to the 

Westinghouse one-seventh scale natural circulation experiments (Reference 2.6) and 

implementing model features to switch between normal and recirculating natural circulation 

modes based on the status (open or water-plugged) of the loop seals and at the bottom of the 

RV downcomer skirt. INEL also introduced stress multipliers in the SCDAP/RELAP5 modeling 

of the creep rupture structural failures, allowing various extents of tube strength degradation to 

be parametrically included in the SCDAP/RELAP5 calculation results. 

In Reference 2.10 INEL used the refined Westinghouse four-loop plant model to evaluate 

behavior for a base case SBO accident scenario that included: loss of all on-site and off-site AC 

power, failure to start all diesel-electric generators, loss of all main and auxiliary feedwater, 15% 

tube plugging in all SGs, and a stuck-open PORV on the secondary side of the pressurizer-loop 

SG. INEL also evaluated the sensitivity of results to differences in design between the 

Westinghouse three-loop and four-loop plants, including the configuration of the HL-to-surge 

line connection, the loop seal geometry and the core bypass. INEL concluded that for the base 

case accident scenario in the Westinghouse four-loop plant the creep rupture failure of unflawed 

SG tubes will occur subsequent to the failure of the pressurizer surge line. However the margin 

was relatively small and SG tubes with stress multipliers greater than 2.0 were predicted to fail 

prior to the surge line. INEL also concluded that the plant behavior may be sensitive to the 

modeling of the fuel rod oxidation process, the modeling of the surge line-to-HL connection and 

the assumptions made regarding SG tube plugging and core bypass. 
12

After 2000, SCDAP/RELAP5 thermal-hydraulic analyses supporting the containment bypass 

project SGAP were performed by Information Systems Laboratories, Inc. (ISL) and were based 

on further refinements and improvements upon the INEL SCDAP/RELAP5 Westinghouse 

four-loop plant model from Reference 2.10. 

In Reference 2.11 ISL investigated additional variations in the accident sequence assumptions 

to look for changes in assumptions that could result in more limiting SG tube failure margins 

than were previously predicted. The effects of leakage through a pressurizer SRV (equivalent 

to 13% of the valve flow area) and leakage through the RCP shaft seals (leakage rates up to 

15.8 L/s [250 gpm] per pump) were investigated. The results indicated that these RCS 

leakages increased the SG tube failure margin and did not result in clearing of loop seals. The 

margin improvements were seen to result from the reduction of the RCS pressure caused by 

including the RCS leakages in the model. The effects of reducing SG tube plugging from 15% 

(assumed in the base case at that time) to 0% were investigated. As expected, decreasing the 

assumed number of plugged tubes was found to reduce tube temperatures and increase the SG 

tube failure margin, although the margin change was small. As a result of the evaluations in 

Reference 2.11, no changes were recommended for the base case accident sequence 

assumptions or for the SCDAP/RELAP5 modeling approach. 

In Reference 2.12 ISL investigated potential conservatisms in SCDAP/RELAP5 modeling of the 

Westinghouse four-loop SBO base case accident sequence. The effect of changes in the time 

step size and heat structure mesh size on the calculated base case results were independently 

investigated. The maximum time step size was reduced from 0.075 s to 0.005 s. The number 

of mesh intervals across the thickness of the HL wall was doubled. Neither the time-step size 

nor mesh-size variations were seen to significantly impact the calculation results. Another 

sensitivity run was made to determine the impact of increasing the heat transfer coefficient from 

the SG tube outer wall surface to the fluid in the SG boiler region by a factor of 5.0. This 

increase was intended to represent an upper bound for the heat transfer through this path, 

including effects due to steam-to-wall thermal radiation and tube-bundle induced turbulence not 

modeled with SCDAP/RELAP5. In the sensitivity run, coupling between the SG tube outer wall 

and the cooler steam in the SG boiler region was shown to significantly increase the SG tube 

failure margin (the stress multiplier required for tube failure to precede surge line failure 

increased from about 2.0 in the base case run to about 3.0 in the sensitivity run). Based on this 

result, it was concluded that steam-to-wall and wall-to-wall thermal radiation processes could in 

general affect the heat-up of structures and that the SCDAP/RELAP5 code should be upgraded 

to represent those processes. 

In Reference 2.13 ISL performed initial evaluations into expected tube-to-tube variations, the 

manner in which hot steam entering the SG inlet plenum from the HL is distributed among the 

inlets of the SG tubes. The buoyant hot steam rises as it emerges from the HL, flowing toward 

the bottom face of the tubesheet. Flow enters the hot SG tubes (i.e., those tubes through which 

flow is traveling in the upward direction). The issue relates both to the spreading of the hot 

steam region as it rises and to the mixing it encounters with cooler steam along the way. The 

cooler steam enters the SG inlet plenum through the cold SG tubes (i.e., those through which 

flow is traveling in the downward direction). Of specific interest is the hottest steam temperature 

that is expected to enter the hot tubes and the number of tubes that experience that hottest 

steam temperature. Up to this time, SCDAP/RELAP5 plant models had separated the SG tube 

bundle into hot and cold tube sections which were assumed to be passing steam of an average, 

not maximum, temperature. 
13

The evaluation of the tube-to-tube variation issue concluded, based on a review of the 

Westinghouse one-seventh scale test data (Reference 2.6), that mixing between the hot and 

cold steam flows primarily occurs locally near the connection between the HL and SG inlet 

plenum and little further decline in the steam temperature is seen from this point of mixing 

upward toward the tubesheet. A review of the literature showed that plume models predict a 

decay in temperature with distance from the source position and therefore a plume modeling 

approach does not appear to represent the mixing process in the SG inlet plenum. The mixing 

behavior in the SG inlet plenum was seen to be more complex than could be represented with a 

simple plume model. Further, even if a plume model could be adequately adjusted to represent 

the mixing behavior in the one-seventh scale facility, its extrapolation to the full-scale plant 

would be questionable due to the geometric differences in inlet plenum designs. Instead, an 

alternate approach was developed for predicting the maximum temperature of steam entering 

the SG tubes which takes advantage of the one-seventh scale test data. With this approach, 

the test data is used to characterize a normalized temperature ratio, relating the difference 

between the hottest SG tube temperature and the cold SG tube temperature to the difference 

between the HL and cold SG tube temperatures (subsequent Westinghouse four-loop plant 

modeling includes a hottest tube simulation based on this approach, which is described in 

Section 3.4). The results were extended to more prototypical inlet plenum designs using 

computational fluid dynamics simulations. 

A coordination meeting was held in Rockville, Maryland, March 19-20, 2003 among project 

participants in the areas of thermal-hydraulics, probabilistic risk assessment and stress analysis. 

The meeting resulted in a consensus regarding the event sequence and modeling assumptions 

to be used for the project. The SCDAP/RELAP5 code and Westinghouse four-loop plant model 

were revised accordingly and a SBO base case calculation was performed and documented in 

Reference 2.14 to serve as a common reference case for all involved in the project. The code 

and plant model revisions included in the revised base case calculation are summarized as 

follows: 

RCP shaft seal leakage at 1.32 L/s [21 gpm] per pump was added to the model; 

previously the base case model assumed no shaft seal leakage. 

The SG tube plugging assumption was revised from 15% to 10%. 

The axial nodalization of the SG tube region was expanded slightly, such that the 

first and last cells of the tube models represent only the fluid inside the tubesheet. 

The nodalizations for heat structures particularly important for the analysis were 

revised to increase the number of nodes employed across the thicknesses of the 

structures. 

The thermal material properties for structures in the model were revised for 

consistency with those used by the project stress analysts.(However, the hot leg 

and nozzle region continued to be modeled as stainless steel) 

RCS heat loss to containment was added to the model. A total of 4 MW heat loss 

was assumed to be uniformly distributed over the outer surfaces of the primary and 

secondary coolant system vessels and pipes. 

The SCDAP/RELAP5 code was modified to permit the modeling of steam-to-wall 

radiation heat transfer. The plant model was revised to include the effects of 
14

steam-to-wall radiation on the inside surfaces of all primary coolant system heat 

structures and the effects of wall-to-wall radiation heat transfer between the piping 

walls of the upper and lower HL sections. 

The plant model was revised to include a representation for the hottest tube in the 

pressurizer-loop SG as discussed above. 

The target SG inlet plenum mixing and flow parameters of the SCDAP/RELAP5 

plant model (as defined in Section 3.4) were revised for consistency with the 

results of initial CFD evaluations (Reference 2.15) of the Westinghouse oneseventh scale experiments and the scale-up of the experimental results to the 

Westinghouse four-loop plant configuration. Through this process the 

SCDAP/RELAP5 model is enhanced to reflect the physical behavior of the system 

observed with the CFD model. The assumed split of the SG tubes into hot and 

cold regions was revised from 53%/47% to 50%/50%. The target hot and cold 

mixing fractions were revised from 0.87 to 0.81 and the target recirculation ratio 

was revised from 1.9 to 2.75. The 30.24% target SG power fraction (the fraction of 

the total core power deposited into the SGs) was not revised. Note that, to make 

the modeling of HL circulating flow more physically-based, the target SG power 

fraction has since been replaced with a target hot leg discharge coefficient, see 

Section 3.4). The normalized temperature ratio for the hottest tube model was 

revised from 0.4737 to 0.625. 

The results of the SCDAP/RELAP5 SBO base case calculation using the revised Westinghouse 

four-loop plant model indicated a significant improvement in the SG tube failure margin. A 

stress multiplier of about 4.5 was now found to be required for the average SG tube to fail prior 

to the pressurizer surge line (in the previous base calculation that multiplier was about 2.0). The 

margin improvement was found to result primarily from the significant increase in the target 

recirculation ratio. In order to attain the higher recirculation ratio and at the same time keep the 

SG power fraction from increasing above its target value, a general slowing of the steam flows 

in the two circulating loops (i.e., the upper and lower HL sections and the hot and cold SG-tube 

sections) was required. The slowing of the transport of heat from the core to the SGs both 

delayed the heat-up of the SG tubes and (because of the increased demand for pressurizer 

relief valve operation) accelerated the heat-up of the pressurizer surge line, thereby improving 

the SG tube failure margin. For the hottest SG tube, a stress multiplier of about 1.5 was found 

to be required for it to fail prior to the pressurizer surge line. 

2.4 Sensitivity Analyses, 2004

Extensive sensitivity studies were performed to evaluate the effects of various changes in the 

SCDAP/RELAP5 Westinghouse four-loop plant modeling options, event sequence assumptions 

and plant configuration. These sensitivity studies were documented in Reference 2.16. The 

base case accident sequence and plant model used for the sensitivity analyses were the same 

as described in Section 2.3. The sensitivity evaluations performed and the analysis results are 

summarized here and are more fully described in Appendix A. See Section 3.4 for definitions of 

the hot and cold mixing fractions and the recirculation ratio. 

The target hot and cold mixing fractions were increased to from 0.81 to 0.87 and, separately, 

the target recirculation ratio was decreased to from 2.75 to 2.0. Both sensitivity runs showed 

reductions in the SG tube failure margin from the base case. 
15

A variety of assumptions regarding the RCP shaft seal leakage were investigated. The base 

case event sequence assumed a leak flow area based on an initial 1.32 L/s [21 gpm] leakage 

rate per pump. In the sensitivity cases, the leakage flow area was increased at different times 

during the event sequence to as high as 18.9 L/s [300 gpm] per pump. The results of the 

sensitivity runs indicated that the SG tube failure margins are sensitive to the assumed RCP 

shaft seal leakage, with small increases in the leakage rate leading to slightly lower the margins, 

and large increases in the leakage rate leading to significantly improved margins. 

Sensitivity evaluations were performed for 0% and 20% SG tube plugging assumptions (10% 

was assumed in the base case). The SG tube failure margin results were seen to be only 

slightly affected by the tube plugging assumption. 

The sensitivity to variations in the heat transfer processes on the outer surface of the SG tubes 

was evaluated using multipliers of 0.1, 5.0 and 10.0 on the SCDAP/RELAP5-calculated heat 

transfer coefficient. The results indicated that the SG tube failure margin is sensitive to this 

parameter. Enhanced heat transfer leads to a tighter coupling of the SG tube wall with the 

cooler steam in the SG boiler region and increased SG tube failure margins. 

The sensitivity to variations in the modeling of thermal radiation heat transfer processes was 

evaluated using SCDAP/RELAP5 runs in which multipliers of 0.5 and 2.0 were placed on the 

steam-to-wall and wall-to-wall radiation heat fluxes on the surfaces of the RCS structures. The 

results indicated that increased radiation heat flux leads to slightly-improved SG tube failure 

margins. 

Several SCDAP/RELAP5 sensitivity runs were performed to investigate the modeling of 

countercurrent flow limiting (CCFL) behavior related to pressurizer draining. None of these runs 

indicated a significant affect on SG tube failure margins. 

SCDAP/RELAP5 calculates buoyancy-driven circulations within the RV which affect the 

temperature of steam transported into the coolant loops. A SCDAP/RELAP5 sensitivity run was 

performed in which the flow losses within the vessel model were increased so as to reduce the 

flow rates of the RV internal circulations by an arbitrary 50%. The reduced RV circulation rates 

were seen to accelerate the core damage process and result in improved SG tube failure 

margins. 

The base case SCDAP/RELAP5 plant system model represents a typical 4 MW of uniformlydistributed heat loss from the outer surfaces of the primary and secondary reactor coolant 

systems to the containment. Sensitivity runs were made with this assumption changed to 2 MW 

and 8 MW and the results showed that SG tube failure margin results are moderately affected 

by the heat loss assumption, with the higher heat loss leading to reduced margins. 

A sensitivity run was also performed to evaluate the plant response to mitigative operator 

intervention. The operators were assumed to depressurize the RCS by opening the pressurizer 

PORVs following the onset of the core heat-up. The results of the sensitivity run demonstrated 

the success of this intervention strategy for mitigating containment bypass during the base case 

SBO severe accident. SG tube failures were prevented by the operator action. The core 

melted and relocated to the RV lower head; a subsequent failure of the RV lower head would 

result in a full depressurization of the RCS and a release into the containment. 

A limited investigation was performed into the effects of SG tube leakage (from 

primary-to-secondary, none is assumed in the base case calculation). The results indicated that 
16

the tube leakage assumption affects the SG tube failure margin, with higher leakage rates 

leading to reduced margins. 

A SCDAP/RELAP5 sensitivity run was performed with the assumed core bypass flow due to 

leakage around the slip fit between the core barrel and RV at the HL nozzle penetrations (1% of 

total coolant loop flow rate) arbitrarily reduced by 50%. This modeling change was seen to have 

virtually no effect on the SG tube failure margins. 

The SCDAP/RELAP5 Westinghouse four-loop base case calculation indicated that the failure of 

structural components (HL and pressurizer surge line piping and SG tubes) occurs relatively 

early during the core damage and relocation processes of the SBO severe accident sequence. 

The fuel rod cladding oxidation is seen to dramatically increase the core heat load, which in turn 

leads to a rapid heat-up of components throughout the RCS. The structural failures are 

encountered shortly after the time when the oxidation power peaks. Heating of the control rods 

leads to control rod cladding failure and relocation of molten control rod absorber material to the 

RV lower head shortly after the time of the structural failures. Melting and relocation of the core 

fuel to the RV lower head are seen to occur long after the time of the structural failures. Three 

SCDAP/RELAP5 sensitivity runs were performed to evaluate the effects of the core damage 

progression by varying the modeling of the fuel rod oxidation, control rod melting and fuel rod 

melting processes. Results from these evaluations are summarized as follows. 

At its peak, the fuel rod cladding oxidation power exceeds the fission product decay power by 

an order of magnitude. A sensitivity run was performed in which the peak oxidation power was 

limited to 43% of the peak experienced in the base case run. The results showed that limiting 

the peak oxidation power in this manner tended to slow the RCS system heat-up rate, leading to 

small reductions in the SG tube failure margins. 

A sensitivity run was performed to evaluate the effect of varying the control rod melting 

behavior. The conclusion was that the effects of uncertainties related to modeling severe 

accident control rod-related behavior (cladding failure, and melting and relocation of the 

absorber, cladding and guide tube materials) on SG tube failure margins are small. 

A sensitivity run was performed with a significant variation in a parameter that affects the 

melting and relocation of the core fuel (the fraction of the phase-change heat that must be 

absorbed by the fuel for it to be considered in the molten state). The sensitivity evaluation 

concluded that the SG tube failure margins are insensitive to variations in the fuel damage 

progression behavior (including fuel melting, flow blockage, re-freezing and relocation) primarily 

because these occur after the time when the HL surge line and SG tube structural failures are 

experienced. 

2.5 ACRS Review Meeting, 2004

A joint meeting of the ACRS Materials and Metallurgy and Thermal-Hydraulic Subcommittees 

(Reference 2.17) was held on February 3-4, 2004 to review the progress of the SGAP research. 

Presentations related to thermal-hydraulics covered both the CFD analysis and the 

SCDAP/RELAP5 systems analysis of plant response during SBO severe accident event 

sequences. The presentations on the SCDAP/RELAP5 analysis described the Westinghouse 

four-loop plant modeling and SBO base case calculation in Section 2.3 along with the results of 

the sensitivity analyses summarized in Section 2.4. 
17

One ACRS concern with the SCDAP/RELAP5 modeling regarded the “SG power fraction” 

approach for adjusting the model to the match a target value based on behavior indicated in 

Westinghouse one-seventh scale experiments (Reference 2.6) and in the CFD analyses. In the 

SCDAP/RELAP5 plant model at that time, flow loss coefficients in SG plenum regions were 

adjusted to attain a target value for the SG power fraction (in addition to target values for mixing 

fractions and the recirculation ratio, as defined in Section 3.4). The ACRS concern was that the 

SG power fraction should be an output variable produced by the systems analysis code and not 

a target parameter (experimentally derived or otherwise) that the input for the system analysis 

code is adjusted to attain. Because the heat deposited in the SG necessarily results from the 

transfer of energy from the RV to the SG through the HL, a SG power fraction modeling 

approach is similar to one in which the HL flow rate is adjusted in order to attain a specified SG 

power. In response to this ACRS comment, the SCDAP/RELAP5 plant model was 

subsequently revised such that the HL flows are determined using a target hot leg discharge 

coefficient that is based on CFD models for horizontal, countercurrent flow between the upper 

plenum and the steam generator inlet plenum. The approach using a target SG power fraction 

was therefore replaced by an approach in which the HL flow is determined using a more 

physically-based hot leg discharge coefficient. This revised modeling approach, which is 

described in Section 3.4, was employed for the analyses described in Section 2.8 and in all 

subsequent analyses described in this report. 

A second ACRS concern with the SCDAP/RELAP5 analysis regarded the calculated loop seal 

behavior. Since clearing of water from a loop seal can lead to a flow of hot steam through the 

SGs in the direction of the normal loop flow and early failure of SG tubes, assurance is needed 

that the loop seal status is well represented by the system code. This issue is addressed 

through the SCDAP/RELAP5 code assessments provided in Section 3.2.1. 

A third ACRS concern with the SCDAP/RELAP5 analysis regarded the calculation of the fluid 

circulation rates internal to the RV. This issue is addressed by sensitivity studies evaluating the 

effects of RV internal circulation rate variations as summarized in Sections 2.4 and 2.9. 

Finally, the ACRS suggested that a means be provided to enhance understanding of the flows 

of heat from the reactor core, through the RV and into the coolant loops and SGs. An analysis 

of the flow of energy within and out of primary RCS is described in Section 2.8. 

2.6 Analyses to Support PRA, 2004-2005

The SCDAP/RELAP5 Westinghouse four-loop plant model used for the analyses described in 

Sections 2.3 and 2.4 was upgraded and used to support a series of 43 SGAP PRA analyses 

that were performed in two sets of 20 and 23 runs each. The model upgrades are summarized 

as follows: 

The SCDAP/RELAP5 plant model for the first 20 analyses was revised to improve 

the representation of the flow behavior in the region of the HL-to-pressurizer surge 

line connection. This side mounted surge line had been modeled in a manner 

such that steam flow only from the upper HL section entered the surge line during 

periods when the pressurizer relief valves were closed. CFD analyses indicated 

that during those periods flow is drawn equally from the upper and lower HL 

sections into a side mounted surge line and the SCDAP/RELAP5 connection 

modeling was modified to reflect that behavior. For the final 23 analyses the 

pressurizer surge line connection additionally was moved from the top to the side 
18

of the HL (in some Westinghouse four-loop plants this connection is made on the 

top of the HL while in others it is made on the side of the HL). 

Additional considerations of entrance effects were considered for the convective 

heat transfer coefficient in the hot leg. An average enhancement of the convective 

heat transfer is applied to the hot leg pipe to account for the fact that the flow is not 

fully developed. For the final 23 analyses, the SCDAP/RELAP5 plant model was 

revised to enhance the fully developed heat transfer coefficient calculated on the 

inside surfaces of the HL piping sections by approximately 50% to account for the 

average thermal entrance effects along the pipe. A single average multiplier is 

used for the entire hot leg due to limitations in the SCDAP/RELAP5 input model. It 

is noted that the entrance effects at the anticipated hot leg failure point are higher 

and a multiplier near 2.0 on the convective heat transfer coefficient is suggested in 

this region for use in multi-dimensional analysis of the hot leg. 

For all 43 analyses the SCDAP/RELAP5 plant model was modified to 

independently represent the two pressurizer PORVs. Previously the two valves 

were lumped together in the model as there was no need to simulate independent 

operation. The change was made to support the PRA accident sequence 

simulations, some of which included the opening of only one valve. 

Based on prior PRA analyses, the SBO base case accident scenario description was revised as 

follows: 

Leakage from the SG secondary system based on a 3.2-cm2

 [0.5-in2] flow area per 

SG was added to the scenario description and the assumption that the PORV on 

the secondary system of the pressurizer-loop SG sticks open when first challenged 

was removed from the scenario description. Subsequent to this change, 

SCDAP/RELAP5 calculations show that all four SGs have completely 

depressurized by the time when the HL and pressurizer surge line structures fail. 

An assumption of a typical lower-limit four-hour station battery life was added; 

previous analyses had assumed infinite battery life. The effect of this change is to 

consider both automatic and operator control functions over the pressurizer and 

SG secondary PORVs to be inoperable after four hours. 

The 43 SCDAP/RELAP5 PRA support calculations were performed with the upgraded model to 

evaluate various combinations of assumptions regarding RCP shaft seal leakage, TDAFW 

operation, battery depletion time, SG secondary steam leakage and operator intervention. The 

PRA support analyses performed and the results are summarized in Appendix B. The key 

findings from these evaluations are summarized as follows. 

For the first set of 20 runs the base case SG tube failure margins were found to be reduced as a 

result of the HL-to-surge line connection modeling revisions. During periods when the 

pressurizer relief valves are closed, the fluid entering the surge line in the new base case 

represented a mixture of hot steam drawn from the upper HL section and cool steam drawn 

from the lower HL section. The temperature of the steam entering the surge line in the revised 

base case calculation was therefore lower than in the prior base case calculation, where the 

flow was drawn only from the upper HL section. This difference delayed the surge line failure, 

but had very little effect on the HL and SG tube failure times. With this modeling change the HL 

failure was seen for the first time to precede the surge line failure, resulting in reduced SG tube 
19

failure margins. For the second set of 23 runs, moving the pressurizer surge line connection 

from the top to the side of the HL resulted in still-lower temperatures for the steam entering the 

pressurizer surge line and even lower SG tube failure margins. 

Operator actions to mitigate the SBO accident were generally seen to be effective. Opening 

one or both pressurizer PORVs either at the time when the core exit temperature reaches 

922 K [1,200°F] or 12 minutes afterward were shown to accelerate failure of the HL, pressurizer 

surge line or RV lower head, thereby preventing containment bypass. 

Event sequence assumptions leading to significant depressurizations of the RCS were seen to 

reduce the SG tube differential pressures, thereby preventing containment bypass. These 

assumptions included stuck-open pressurizer PORVs and RCP seal leak rates which increased 

from 1.32 L/s [21 gpm] to 11.3 L/s [180 gpm] and 30.2 L/s [480 gpm] per pump at 13 minutes. 

The additional energy which is passed out of the RCS by assuming the RCP shaft seal leakage 

rate increases to 11.36 L/s·[180 gpm] per pump at 13 minutes is seen to generally improve the 

SG tube failure margins over those where the leakage rate is assumed to remain at 1.32 L/s 

[21 gpm] per pump. 

The assumption of SG secondary side steam leakage is seen to significantly reduce the SG 

tube failure margins compared with cases where no leakage is assumed. SG steam leakage 

into the turbine system leads to much lower SG secondary pressures and much less thermal 

coupling between the outside of the SG tube and the secondary-side steam. Both of these 

effects increase the potential for SG tube failure. No average or hottest SG tube failures are 

indicated (even for tube stress multipliers as high as 7.5) in the cases which assume zero SG 

steam leakage. 

2.7 NRC and Consultant PIRT Evaluation and Peer Review, 2005

A Phenomena Identification and Ranking Table (PIRT) exercise was conducted in Rockville, 

Maryland on September 28-29, 2005 to discuss the thermal-hydraulic behavior associated with 

the analysis of PWR containment bypass (Reference 2.18). Participants in the PIRT included: 

USNRC-RES – David Bessette 

USNRC-NRR – Steve Long, Len Ward and Walt Jensen 

USNRC Consultants – Marino DiMarzo and Peter Griffith 

ISL, Inc. – Don Fletcher, Bill Arcieri, Robert Beaton and Vesselin Palazov 

The PIRT exercise served to provide: (1) an independent technical review of the 

SCDAP/RELAP5 modeling and analysis approaches and (2) expert guidance regarding the 

dependent variables (figures of merit) and independent variables (important phenomena, 

processes and behavior) appropriate for an evaluation of the calculation uncertainties. The 

major technical review issues discussed at the meeting and identification of the parameters 

which the PIRT participants recommended for the uncertainty evaluation dependent and 

independent variables are summarized as follows. 

2.7.1 Independent Technical Review Issues 

The PIRT discussions uncovered modeling questions and uncertainties that were subsequently 

investigated, leading to SCDAP/RELAP5 plant model upgrades in several areas. These 

upgrades included: (1) adding a representation of the pressurizer spray system, (2) expanding 
20

the core region axial nodalization from 10 to 40 nodes, (3) employing finer axial nodalizations for 

the fluid cells and heat structures in the vicinity of the SG tubesheet and (4) replacing the target 

SG power fraction used in the SG inlet plenum flow-loss adjustment method with a target hot leg 

discharge coefficient (as described in Section 3.4). The latter of these modeling changes also 

addressed the earlier comment by the ACRS regarding the unsuitability of using a target SG 

power fraction for that purpose (see Section 2.5). 

2.7.2 Identification of Dependent Variables for the Uncertainty Evaluation 

The dependent variables for the uncertainty evaluation are those for which it is desired to 

determine the uncertainties in the SCDAP/RELAP5-calculated results. 

The PIRT participants recommended the dependent variables include the calculated output 

parameters that the project stress analysts investigating HL, pressurizer surge line and SG tube 

structural failures use as boundary conditions for their detailed analyses. These parameters 

are: (1) HL steam temperature, (2) HL piping wall inside-surface heat transfer coefficient, 

(3) pressurizer surge line steam temperature, (4) pressurizer surge line piping wall 

inside-surface heat transfer coefficient, and (5) SG tube metal temperatures. 

The PIRT participants also acknowledged the importance for the regulatory decision-making 

process of the timing difference between the HL/surge line and SG tube structural failures and 

recommended that the SG tube failure margins also be included as dependent variables. 

2.7.3 Identification of Independent Variables for the Uncertainty Evaluation 

The independent variables for the uncertainty evaluation are those judged to have the most 

influential impact on the dependent variables. 

The PIRT participants discussed a variety of issues related to the thermal-hydraulic response of 

the Westinghouse four-loop plant during SBO severe accidents and to the containment bypass 

issue. During the discussions, a list of recommended independent variables for the uncertainty 

evaluation, and their relative rankings, was developed by consensus view of the PIRT 

participants. 

Regarding the rankings, a prime consideration of the participants was that items seen to 

similarly affect structural failure times in all three locations (i.e., the HL, surge line and SG 

tubes) should be considered of lower rank than those items seen to differently affect the three 

failure times. The latter set of items can logically be seen to have a greater effect on the SG 

tube failure margin because is has the greatest potential for influencing the relative failure times 

among the structures. 

The group also decided to separate out those items that represent basic thermal-hydraulic 

processes from those items that instead represent event sequence assumptions or variations in 

the plant configuration. 

Table 2.1 summarizes consensus opinions of the PIRT participants on the thermal-hydraulic 

phenomena, behavior, event sequence assumptions and plant configuration items that are 

expected to most significantly affect the dependent variables (temperatures, heat transfer 

coefficients and SG tube failure margins) for the uncertainty evaluation. 
21

The table is separated into three sections. Section A, which includes items that differently affect 

the behavior at the three locations, represents the high-ranked items. Section B, which includes 

items that similarly affect the behavior at the three locations, represents the medium-ranked 

items. Section C includes low-ranked items that relate strictly to the event sequence 

assumptions or the plant configuration. Within each table section, the relative ranking of the 

items is indicated by the assigned number (for example, within Section A Item A1 is considered 

the highest ranked item while Item A5 is considered the lowest ranked item). 

Table 2.1 Ranking Table of Items Important for the Containment Bypass Issue 

During SBO Severe Accident Scenarios in a Westinghouse Four-Loop 

PWR 

Rank Phenomenon 

Location(s) 

Affected 

 SG 

 HL SL Tube

Reasons for Ranking, 

Other Pertinent Notes and Comments 

A1 Full loop circulation 

(loop seal clearing 

and reactor vessel 

lower plenum 

clearing) 

 X Top-level accident sequence assumption is that 

all cold leg loop seals remained water-filled. 

Cleared loop seals induce steam circulation 

throughout the loops, increasing potential for 

tube failure. Binary parameter, all loop seals are 

either water-filled or not. 

A2 Pressurizer 

Behavior (phase 

separation, PORV 

flow, CCFL & 

draining, spray 

nozzle venting) 

 X Water draining from the pressurizer preferentially 

cools the hot steam in the surge line (SL) and a 

small amount of water helps to delay the SL 

failure. Timing of pressurizer draining relative to 

core heat up affects SL failure time and core 

degradation process. Pressurizer phase 

separation and relief valve flow inherently affects 

RCS pressure and RCS energy loss. Spray 

nozzle venting may affect pressurizer draining 

process. 

A3 Mixing, SG inlet 

plenum 

 X Critical to tube failure prediction, more important 

in CE plants than Westinghouse plants. May be 

able to use scatter in the Westinghouse 

1/7-scale test data to estimate uncertainty in this 

parameter. Need to address effects on both hot 

tubes and average tubes. 

A4 SG tube outer wall 

heat transfer (SG 

secondary side 

heat transfer) 

 X Strongest potential to change timing of SG tube 

failure relative to the HL failure. Provides 

mitigating effect for SG tubes by removing the 

tube heat to the SG secondary fluid. Include 

tube sheet modeling effects in a sensitivity study. 

P. Griffith suggested + 30% as a best guess 

regarding the SG tube outer wall heat transfer 

coefficient. 
22

Table 2.1 Ranking Table of Items Important for the Containment Bypass Issue 

During SBO Severe Accident Scenarios in a Westinghouse Four-Loop 

PWR 

Rank Phenomenon 

Location(s) 

Affected 

 SG 

 HL SL Tube

Reasons for Ranking, 

Other Pertinent Notes and Comments 

A5 Buoyancy-driven 

flows in SG tubes 

(ratio of SG tube 

flow to hot leg flow) 

 X The SG tube flow directly affects the tube 

temperatures but only indirectly affects the HL 

and SL temperatures. The tube flow determines 

the energy entering the tube. The recirculation 

ratio using the three-cell inlet plenum model is 

adjusted to agree with the CFD analysis; its 

uncertainty is likely small. The hot leg flow 

model is being improved and will be more 

physically based. 

B1 Core power, 

especially fuel rod 

cladding oxidation 

power 

 X X X The hot gas generation due to oxidation drives 

the heat up process. In a sensitivity calculation, 

a large variation in the oxidation model was not 

seen to significantly affect the SG tube failure 

margin results. The hydrogen generation from 

oxidation affects vessel mixing, buoyancy, and 

feeds back into the oxidation rate. The hydrogen 

generation also affects transport of energy away 

from the core and the wall heat transfer. 

Hydrogen also affects SG inlet plenum mixing 

and CFD results may show mixing may be help 

mitigate tube heat up. P. Griffith experiments 

indicate that hydrogen rapidly mixes with steam. 

Existing SCDAP/RELAP5 assessment cases 

may provide data regarding the expected 

uncertainties in the oxidation process. 

B2 Buoyancy-driven 

flow in vessel 

(includes effects of 

vessel internal flow 

resistances) 

 X X X The vessel internal flows directly affect the 

temperatures at the core exit and at the vesselto-hot leg connections. These flows also affect 

the oxidation rate and are considered to be of 

medium importance. The prediction capability 

for the vessel internal flows was judged to 

probably be within a factor of two, suggesting 

that a range between 0.5 and 2.0 be investigated 

in the uncertainty study. 

B3 Buoyancy-driven 

flow in hot legs 

 X X X The elevation change within the hot leg provides 

a buoyancy effect. However, buoyancy in the 

SG tubes, where the elevation change is much 

larger, is judged to be the driver for the flow 

circulation processes. 

B4 RCS heat loss to 

containment 

 X X X The prior sensitivity study indicated that the SG 

tube failure margin is affected by the assumed 

heat loss. Affects the heat transfer processes for 

all three locations, but to different extents. 
23

Table 2.1 Ranking Table of Items Important for the Containment Bypass Issue 

During SBO Severe Accident Scenarios in a Westinghouse Four-Loop 

PWR 

Rank Phenomenon 

Location(s) 

Affected 

 SG 

 HL SL Tube

Reasons for Ranking, 

Other Pertinent Notes and Comments 

B5 Mixing at the 

vessel-to-hot leg 

connection 

 X X X Not much mixing occurs at this location. Test 

data (W 1/7-scale experiments) shows that hot 

leg and upper plenum temperatures are about 

the same, indicating that the hot-steam regions 

are well-mixed. The cooler steam returning 

through the lower hot leg sections falls into the 

periphery of the core as it enters the vessel, so 

there is little interaction with the hot steam exiting 

the vessel into the upper hot leg sections. 

C1 Operator 

intervention (event 

sequence definition 

item) 

 X Operator intervention includes depressurization 

of SGs and opening of the pressurizer PORVs. 

Prior sensitivity study indicated the success of 

this mitigation strategy if it is performed in a 

timely manner. Effect of the operator 

intervention on the SG tube failure margins was 

significant. 

C2 RC pump seal 

leakage (event 

sequence definition 

item) 

 X X X This phenomenon affects the primary system 

pressure and RCS energy balance. Prior 

sensitivity study indicated that the influence on 

the SG tube failure margin increases as the 

assumed leakage rate increases. 

C3 SG tube leakage 

(event sequence 

definition item) 

 X This phenomenon draws additional steam into 

the SG tubes, decreasing their failure margin. 

Prior sensitivity study indicated a moderate 

influence of the tube leakage on the tube failure 

margin. 

C4 Surge line 

orientation (plant 

configuration item) 

 X The surge line-to-hot leg connection 

configuration varies from plant to plant. In the 

current Westinghouse plant model the 

connection is made on the side of the hot leg 

pipe, but in some plants the connection is 

instead made on the top of the hot leg pipe. 

Prior sensitivity calculations indicate a 

significantly earlier surge line failure when the 

surge line is connected on the top of the hot leg 

because much hotter steam is drawn into the 

surge line. 
24

Table 2.1 Ranking Table of Items Important for the Containment Bypass Issue 

During SBO Severe Accident Scenarios in a Westinghouse Four-Loop 

PWR 

Rank Phenomenon 

Location(s) 

Affected 

 SG 

 HL SL Tube

Reasons for Ranking, 

Other Pertinent Notes and Comments 

C5 Distribution of 

metal mass in the 

plant (plant 

configuration item) 

 X X X The distribution of the metal structures (vessel 

walls, vessel internals and piping walls) within 

the plant directly affects the spread of hot steam 

from the core into the RCS. Large structures 

near the core, where the steam is the hottest, 

tend to absorb much heat, reducing the steam 

temperatures and heat deposited into heat 

structures that are more distant from the core. 

The recent energy balance analysis for the 

Westinghouse plant demonstrates this effect. 
25

2.8 Revised Base Case Calculation and Evaluation of Primary Coolant System 

Energy Flow, 2006

A revised SCDAP/RELAP5 Westinghouse four-loop plant SBO base case calculation was 

performed to take advantage of modeling improvements and revisions to the accident scenario 

description resulting from the project activities through 2005. The revised base case calculation 

is documented in Reference 2.19. The revised model included all of the modeling upgrades 

described through Section 2.7. This base case calculation served to support the following 

important project activities by providing: 

A reference case providing boundary conditions for detailed stress analyses 

related to the HL, pressurizer surge line and SG tube structures. 

A reference case for an analysis performed to enhance understanding of the 

flows of heat from the reactor core, through the RV and into the coolant loops 

and SGs as requested by the ACRS in 2004 (see Section 2.5). The energy flow 

analysis performed for that purpose is documented in Appendix C. 

A reference case for evaluating uncertainties in the SCDAP/RELAP5 

containment bypass simulations, as described in Section 2.9. 

A set of reference case results published for the purpose of a public review of the 

SCDAP/RELAP5 containment bypass analysis, in particular soliciting comments 

from the Electric Power Research Institute (EPRI). That public review is 

described in Section 2.10 

The target SG inlet plenum mixing and flow parameters for the revised base case calculation 

were a hot leg discharge coefficient of 0.12, a recirculation ratio of 2.0, an inlet plenum mixing 

fraction of 0.85, a 41%/59% split of the SG tubes into hot/cold regions and a hottest tube with an 

inlet temperature based on a conservative NTR of 0.625. 

The results of the revised SCDAP/RELAP5 Westinghouse four-loop plant SBO base case 

calculation indicated that a stress multiplier of 2.10 is required for the average SG tube to fail 

coincident with the HL failure. The calculation also indicated that the hottest SG tube fails 155 s 

prior to the HL, even when a stress multiplier of 1.0 is used, representing an undegraded tube 

strength condition. This average SG tube failure margin was smaller than seen in the prior base 

case analyses. Failure of the undegraded hottest tube prior to the HL also differed from the 

prior base case analyses which predicted it to fail after the HL. These reduced margins resulted 

from the combined effects of multiple modeling changes. In this respect the most important 

modeling changes implemented were judged to be (in decreasing order of importance): 

Expansion of axial noding in the SG regions (especially the significant shortening 

of the first active tube axial node above the top of the tubesheet), which led to 

hotter SG tube metal temperatures and an earlier SG tube failure, 

Revising from a SG power fraction target to a more physically-based hot leg 

discharge coefficient target in the model-adjustment procedure, which increased 

the HL flow rate and the SG heating rate, leading to an earlier SG tube failure, 

and 
26

Moving the pressurizer surge line connection from the top to the side of the HL 

leg pipe, which lowered the temperature of steam entering the surge line and 

delayed the surge line failure, such that the HL failed prior to the surge line. 

2.9 Evaluation of Uncertainties in SCDAP/RELAP5 Simulations, 2006

Analyses were performed to estimate the uncertainties in the SCDAP/RELAP5-calculated 

output for key parameters of importance for the containment bypass application. The key 

parameters (temperatures, heat transfer coefficients and SG tube failure margins), which 

represent the dependent variables for the uncertainty evaluation, were defined through the PIRT 

process and are listed in Section 2.7.2. The independent variables for the uncertainty study 

were also defined via the PIRT process and are discussed in Section 2.7.3 and summarized in 

Table 2.1. The SCDAP/RELAP5 Westinghouse four-loop plant SBO base case calculation 

described in Section 2.8 was used as the base case run for the uncertainty analysis. 

Experimental data pertinent for evaluating the uncertainties in the SCDAP/RELAP5 results are 

generally unavailable due to the high-temperature nature of the containment bypass application. 

Instead, standard deviations representing the estimated uncertainties in the dependent 

variables were developed using a sensitivity-study method employing 19 sensitivity runs in 

addition to the base case run. The standard deviations were calculated through four different 

approaches, using equal-weighting and biased-weighting of the independent-variable 

contributions to uncertainty, and with and without consideration of the uncertainties in the 

means. The base-case values for the dependent variables, the evaluation times from the base 

case run and the standard deviations for the dependent variables are listed in Table 2.2. 

Because many of the sensitivity studies performed for the uncertainty evaluation have additional 

uses and insights for the containment bypass project, the uncertainty evaluation is summarized 

in some detail in Appendix D. The uncertainty evaluation is fully documented in Reference 2.20. 

Table 2.2 Base Case Values and Standard Deviations for the Dependent 

Variables 

Dependent Variable 

Evaluation Time 

for Base Case 

Value(s) 

Base Case 

Value 

Standard 

Deviation 

Hottest SG Tube Failure Margin 

[1.0 Stress Multiplier Hottest Tube 

Failure Time – First Primary Piping 

Failure Time], s 

Not Applicable -155 54.89 

Average SG Tube Failure Margin 

[Stress Multiplier for Tube Failure 

Coincident with First Primary Piping 

Failure], dimensionless 

Not Applicable 2.10 0.234 

Average SG Tube Wall 

Temperature, K 13,630 1021.7 20.93 

Hottest SG Tube Wall 

Temperature, K 13,630 1239.6 34.50 

Hot Leg Steam Temperature, K 13,517 1776.0 61.48 
27

Table 2.2 Base Case Values and Standard Deviations for the Dependent 

Variables 

Dependent Variable 

Evaluation Time 

for Base Case 

Value(s) 

Base Case 

Value 

Standard 

Deviation 

Hot Leg Wall Inside-Surface Heat 

Transfer Coefficient, W/m2

·K 13,517 423.1 29.78 

Pressurizer Surge Line Steam 

Temperature, K 13,517 1373.0 59.94 

Pressurizer Surge Line Wall InsideSurface Heat Transfer Coefficient, 

W/m2

·K 

13,517 490.9 66.15 

2.10 Public Peer Review Meeting, 2007

A Category 2 NRC/EPRI public meeting (Reference 2.21) was held in Washington, DC on 

May 15, 2007 for the purpose of exchanging technical information on SG tube rupture during 

PWR severe accidents. A portion of the meeting was devoted to review of the 2006 

SCDAP/RELAP5 Westinghouse four-loop PWR base case analysis described in Section 2.8 

and the uncertainty evaluation described in Section 2.9. The discussions at the meeting related 

to the SCDAP/RELAP5 SBO analysis, subsequent evaluations and modeling considerations are 

summarized as follows. 

EPRI indicated that in their analysis using the MAAP computer code (Reference 2.22) the 

steam-to-wall radiation heat transfer rate greatly exceeds the steam-to-wall convection heat 

transfer rate to the HL wall at the time when HL failure is predicted. This view differed from the 

SCDAP/RELAP5 SBO base case analysis described in Section 2.8, which indicated that the 

heat fluxes from those two processes are roughly the same at the time of HL failure. 

Subsequent to the public meeting, the NRC and ISL evaluated the SCDAP/RELAP5 

steam-to-wall radiation heat transfer modeling. These evaluations indicated that the emissivity 

calculated with the model deviated significantly from values for water vapor total emissivity 

under similar conditions that are reported in the published literature. For example, the model 

was found to significantly underpredict the emissivity results from Ferriso, Reference 2.23, for 

the high-pressure high-temperature fluid conditions in the large-diameter HL at the time of its 

predicted failure. One source of the discrepancy was found to relate to use of a model 

appropriate at small optical depth (the product of steam partial pressure and path length) at the 

large optical depth of the SBO HL application. However, the evaluation also uncovered other 

issues regarding the SCDAP/RELAP5 steam-to-wall thermal radiation modeling which 

suggested that the code was underpredicting the steam emissivity and steam-to-HL wall heat 

transfer rate for other reasons as well. Because of these discrepancies, the SCDAP/RELAP5 

code was modified by implementing a new steam-to-wall thermal radiation heat transfer model 

as described in Section 3.1. The modified code version was used for the final SCDAP/RELAP5 

SBO simulations that are presented Sections 4 and 5. 

EPRI also questioned the validity for the target SG inlet plenum fluid mixing and flow 

parameters used in the SCDAP/RELAP5 analysis. Subsequent to the meeting, the NRC 
28

re-evaluated its recommendations for the target values made on the basis of CFD calculations. 

This re-evaluation indicated that no significant changes are needed in the target values for the 

inlet plenum mixing fraction (0.85), recirculation ratio (2.0) and hot/cold SG tube split 

(41%/59%). However, the re-evaluation indicated that a reduction in the Normalized 

Temperature Ratio (NTR) from 0.625 to 0.5 would be more appropriate for a best-estimate 

model. (Definitions for these parameters are given in Section 3.4). This target NTR revision 

was implemented in the SCDAP/RELAP5 simulations presented in Sections 4 and 5. 

EPRI indicated that the weakest point in the HL for creep rupture failure is at the safe end of the 

RV outlet nozzle, to which the stainless steel HL is welded. The nozzle safe end is constructed 

of carbon steel base metal, is clad with stainless steel, and is of approximately the same inner 

diameter and wall thickness as the HL. The SCDAP/RELAP5 Westinghouse four-loop plant 

model represents the HL piping using stainless steel structures. SCDAP/RELAP5 lacks the 

heat structure modeling capability (in particular, axial conduction) and creep rupture simulation 

capability that would be needed to fully analyze creep rupture within the complex RV nozzle 

configuration. A SCDAP/RELAP5 sensitivity calculation was performed in which the HLs are 

assumed to be fabricated entirely from carbon steel for the purpose of estimating the effect on 

the calculated SG tube failure margins resulting from considering a carbon steel RV nozzle 

material. This sensitivity evaluation, which is described in Appendix E, indicated that the 

average-tube and hottest-tube failure margins were significantly increased when a carbon steel 

HL material is used as compared to when a stainless steel HL material is used. Therefore, the 

SCDAP/RELAP5-calculated SG tube failure margins, based on solid stainless steel HLs, are 

expected to be conservative compared with the outcomes that are likely to be obtained from 

more detailed HL creep rupture failure analyses of the RV outlet nozzle configuration. 

(Unpublished preliminary detailed stress analyses of the prototype HL nozzle configuration by 

others in the project confirm the finding that the SCDAP/RELAP5-calculated failure margins 

based on the solid stainless steel HL structures are conservative.) 

At the meeting, ISL’s presentation (Reference 2.24) indicated that the expansion of axial 

nodalization for fluid regions and heat structures within, and just above, the tubesheet was a key 

factor leading to the reduced SG tube failure margins seen in the 2006 revised Westinghouse 

four-loop SBO base case calculation (see discussions in Sections 2.7.1 and 2.8). With the 

expanded axial nodalization the SG tube fluid cells and heat structures immediately above the 

top of the tubesheet have a length of 0.3048-m [1.0-ft]. Given the potential importance of axial 

modeling effects, the NRC requested that an estimate be made of the significance of heat 

conduction along the axis of the SG tube toward the tubesheet, which cannot be simulated with 

SCDAP/RELAP5. At issue is whether axial conduction might cool the tube structure for a 

considerable distance above the tubesheet and thereby provide for increased SG tube failure 

margins. The distance “x” above the tubesheet was calculated where the conduction heat 

transfer rate down the tube toward the tubesheet equals the radial conduction heat transfer rate 

through the tube over the height “x.” Large values of “x” (relative to the 0.3048-m [1.0-ft] axial 

node height) therefore indicate that tube axial conduction effects are important while small 

values of “x” indicate that tube axial conduction effects are unimportant. SG tube temperature 

and heat flux data from the SBO base case SCDAP/RELAP5 run in Section 2.8 were used to 

calculate the value of “x.” The results over the heat-up period from 9,000 s to 15,000 s indicate 

that the mean value of “x” is only 0.000823 m [0.00270 ft]. The effects of tube axial conduction 

are therefore significant over only the lower 0.27% of the first tube fluid cell and heat structure 

above the tubesheet, indicating that consideration of axial conduction would not significantly 

affect the SCDAP/RELAP5-calculated SG tube failure margins. 
29

The background of thermal-hydraulic research into the containment bypass issue described in 

Sections 2.1 through 2.10 led to a best-estimate SCDAP/RELAP5 base case calculation for an 

extended SBO event sequence using a greatly-improved computer code and greatly-improved 

model of a Westinghouse four-loop plant. This best-estimate base case calculation (which is 

described in Section 4) indicates that SG tubes with undegraded strength properties and 

carrying both average-temperature and hottest-temperature steam fail subsequent to the HL (by 

1,285 s and 360 s, respectively). The average-tube and hottest-tube failure margins (stress 

multipliers required for tube failure coincident with the HL failure) are 2.74 and 1.68, 

respectively. A final set of sensitivity evaluations was also performed using the improved code 

and model to categorize event sequence behavior relative to the occurrence of containment 

bypass. These sensitivity evaluations are described in Section 5. 

The SCDAP/RELAP5 predictions described herein provide a conservative estimate of the 

relative induced failure times between the hot leg, surge line, and steam generator tubes. 

These calculations are intended to guide and support an analysis of the risk for severe accident 

induced steam generator tube failures. In addition to indicating the potential for tube failure, the 

predictions demonstrate the effectiveness of specific operator actions or safety systems in 

preventing induced tube failures. These predictions can also be used as boundary conditions 

for more detailed analyses of induced tube failures that would provide more realistic relative 

failure times. For instance, the SCDAP/RELAP5 model only considers tube failure within the 

first 12 inches of tubing above the tube sheet where the tube temperatures are highest. A 

consideration of tube flaws above this region in the tube bundle would delay the tube failures 

due to the reduction in temperature along the tube length. In addition, a more accurate 

treatment of entrance effects on the hot leg convective heat transfer and a multi-dimensional 

structural analysis of the hot leg that includes the carbon and stainless steel sections are both 

expected to lead to an earlier prediction of hot leg failure. These issues are beyond the scope 

of the current SCDAP/RELAP5 modeling effort. The SCDAP/RELAP5 predictions provide a 

conservative estimate of induced failure times and demonstrate the effectiveness of specific 

operator actions or safety systems in preventing induced tube failures. 
30
31

3. DESCRIPTION OF ANALYSIS METHODS 

A brief description of the SCDAP/RELAP5 severe accident thermal-hydraulics system code is 

provided in Section 3.1. Assessments of SCDAP/RELAP5 capabilities pertinent for the 

containment bypass application are provided in Section 3.2 for RELAP5 standard 

thermal-hydraulic models and in Section 3.3 for SCDAP severe accident models. Section 3.4 

describes the SCDAP/RELAP5 model for the Westinghouse four-loop PWR for the containment 

bypass application, including a discussion of modeling aspects which have benefitted from 

updated CFD analyses. 

3.1 SCDAP/RELAP5 Code Description

The calculations presented in this report were performed with SCDAP/RELAP5 Version 3.3de, 

which contains the SCDAP source taken from SCDAP/RELAP5/MOD3.3, Version 3.3ld. 

The SCDAP/RELAP5 computer code (Reference 3.1) calculates the overall RCS 

thermal-hydraulic response for severe accident situations that include core damage progression 

and RV heat-up and damage. The computer code is the result of a merging of the RELAP5 and 

SCDAP computer codes. 

RELAP5 models calculate the overall RCS thermal-hydraulics, control system interactions, 

reactor kinetics and the transport of non-condensable gases. The RELAP5 code is based on a 

two-fluid (liquid water and steam/noncondensible vapor mixture) model allowing for unequal 

temperatures and velocities of the fluids and for the flow of fluid through porous debris and 

around blockages caused by reactor core damage. 

SCDAP models calculate the progression of damage in the reactor core, including the heat-up, 

oxidation and meltdown of fuel rods and control rods, ballooning and rupture of fuel rod 

cladding, release of fission products from fuel rods and the disintegration of fuel rods into 

porous debris and molten materials. A SCDAP model calculates the heat-up and structural 

damage of the RV lower head which results from the slumping of molten reactor core material 

with internal heat generation. 

SCDAP models also calculate the creep rupture failure of structural components. Specifically 

important for this project is the calculation of creep failure for stainless steel, carbon steel and 

Inconel based on the creep rupture theory of Larson and Miller (Reference 3.2 and 

Reference 3.1, Volume 2, Section 12.0). The model allows one to specify a stress multiplier, 

whereby a multiplier of 1.0 provides a creep failure prediction for a structure with no material 

strength degradation, and multipliers greater than 1.0 may be used to represent conditions of 

degraded structural strength. For example, a stress multiplier of 2.0 may be used to represent a 

structure with degraded material strength such that creep rupture failure occurs when the 

applied stress is 50% of the stress required to fail the non-degraded structure. The structures, 

locations and stress multipliers used for creep rupture failure calculations in the 

SCDAP/RELAP5 Westinghouse four-loop plant model are described in Section 3.4. 

It is noted that the SCDAP/RELAP5-calculated structural failure predictions are intended to be a 

screening tool for the occurrence of severe accident induced tube failures. Ultimately, best 

estimate failure timing predictions, especially for the RCS components, should be obtained from 

more accurate failure models that incorporate multi-dimensional effects such as multi-
32

dimensional heat conduction within structures and between connected structures, multidimensional boundary conditions, complex structural configurations (such as reactor vessel hot 

leg nozzles), and the influence of cladding on creep rupture failure of a base-metal structure. 

For this application, the SCDAP/RELAP5 code was modified to represent thermal radiation heat 

transfer between the RCS fluid and the walls of the vessels, piping and SG tubes (see 

discussion in Section 2.10). The code calculates an effective heat transfer coefficient for 

fluid-to-wall radiation heat transfer and adds it to the existing convection heat transfer coefficient 

to calculate a single heat transfer coefficient representing a combination of the steam-to-wall 

thermal radiation and convection heat transfer processes. 

The emissivity of steam is calculated using the method described in Section 6.4 of 

Reference 3.3. A table of steam emissivity at selected temperatures and optical depths is 

constructed using the following equation and the steam absorption coefficients, k(ω), given in 

Table A2-35 of Reference 3.3: 



  















 



 

0

273 ( ) 3

1

4 1

1

1 ( , ) 2









 e d

e

C

T

e T T

k

T

C , (1) 

where, 

T = temperature, K, 

C1 = 3.747  10-5 (erg-cm2

) / s, 

C2 = 1.4394 cm-K, 

 = 5.670  10-5 erg / (s-cm2

-K4), 

  p  , optical depth (steam partial pressure times beam length), atm-cm 

k(ω) = steam absorption coefficient, 

ω = wave number. 

Figure 3.1 illustrates the steam emissivity obtained using this modeling approach. 

In addition to steam-to-wall thermal radiation, the SCDAP/RELAP5 Westinghouse four-loop 

plant model described in Section 3.4 also contains wall-to-wall radiation network models 

consisting of the inner surfaces of the HL piping walls. The network models simulate radiation 

heat transfer from the hot piping walls in the upper HL sections to the cooler piping walls in the 

lower HL sections. The SCDAP/RELAP5 code was modified so that the network model 

accounts for the absorption of radiation by the intervening steam in the HL regions. 

3.2 RELAP5 Assessments Pertinent for the Containment Bypass Application

Assessments of the RELAP code pertinent for the SCDAP/RELAP5 PWR containment bypass 

modeling application are described as follows. 

3.2.1 Loop Seal Behavior 

The status of the loop seals is a key behavior for the containment bypass application because it 

affects whether hot steam from the core exit is returned to the core inlet via continuous flow 

through the SGs, RCPs, cold legs and RV downcomer or returned to the RV upper plenum via 

the SG and hot-leg recirculation paths. Loop seal status refers to whether or not the cold leg 

loop seal flow paths and the flow path at the bottom of the RV downcomer core barrel, the 

“downcomer skirt,” are predicted to remain water-plugged. 
33

A wealth of assessments for RELAP5-based codes has been performed to address clearing of 

the cold leg loop seals, especially for small break loss-of-coolant accidents (SBLOCAs). A 

sampling of those assessments is provided below in this section. The physical processes 

associated with clearing of the downcomer skirt loop seal are the same as for the cold leg loop 

seals. A preferential pressurization of the region on the upstream side of the seal depresses the 

fluid level until it reaches the bottom elevation of the seal flow path, at which time steam flow 

through the seal begins. If the steam flow is sufficiently high, water may be cleared from the 

seal, in which case unimpeded steam flow through the path is allowed. It is noted that 

prediction of loop seal clearing for SBLOCAs using thermal-hydraulic systems codes such as 

SCDAP/RELAP5 involve uncertainties, especially regarding which loop seal (in a system 

composed of identical coolant loops) first experiences clearing and the number of loop seals 

which eventually clear. 

Additional loop seal clearing uncertainties are also expected to result from the differences 

between the SBLOCA application and containment bypass application, for which pertinent loop 

seal clearing experiments suitable for code assessment are not available. For SBLOCAs, cold 

leg loop seal clearing results because the production of saturated steam in the reactor core 

preferentially pressurizes the upstream side of the loop seal until flow through the seals relieves 

the upstream overpressurization by allowing steam to reach the pipe break in the reactor 

coolant pump discharge cold leg. For the containment bypass severe accident application, the 

preferential upstream overpressurization is created not from steam production but instead by 

the extreme heating of the vapor residing in the reactor coolant system. The vapor heating 

results from the loss of the SGs as an adequate sink for the combined fission product decay and 

oxidation heats produced in the core. This heating produces dramatic reductions in the vapor 

densities and the pressurization is caused by the corresponding increases in vapor specific 

volumes. 

From its inception in the early 1980’s, the RELAP5 code was developed to represent the 

behavior of PWRs during SBLOCAs, for which loop seal clearing is also an important behavior. 

For cold leg SBLOCAs, the clearing of loop seals allows steam produced in the core to flow 

through the SGs and reach the break location. Therefore, assessments of RCS pressure and 

break flow behavior can be used to judge loop seal clearing behavior. RELAP5 loop-seal 

clearing capability was the subject of much early code assessment using experimental data 

from the Semiscale, LOFT, and other experimental facilities. Those early assessments resulted 

in improved simulation of loop seal clearing behavior through code improvements and 

development of user modeling guidelines for nodalization and code option selection. The 

RELAP5 code has been developed over the 25 years since those early assessments. In order 

to gain an updated picture of RELAP5 capabilities, the literature was searched for more recent 

assessments of its capabilities for predicting loop seal clearing. The following selected code 

assessments against experiments characterize those capabilities and indicate that 

SCDAP/RELAP5 can well simulate PWR SBLOCA loop seal clearing behavior. 

ROSA-IV Test SB-CL-18 

The ROSA-IV experimental facility (Reference 3.4) is a 1/48 volume-scaled, full-pressure, 

full-height representation of a 3423-MWt Westinghouse-type PWR. The four PWR coolant 

loops are represented with two equal-volume loops in the test facility. Components included in 

the loops of the test facility are the HL, SG, RCP, cold leg, pressurizer and emergency core 

coolant (ECC) systems. ROSA-IV Test SB-CL-18 represents a 5% 15.24-cm [6-in] equivalent 

diameter scaled break on the side of a cold leg with the reactor in full-power operation. The 
34

high pressure injection (HPI) and AFW systems are assumed to fail. A loss of off-site power, 

resulting in tripping of all RCPs, is assumed to occur at the time of reactor scram. 

A recent assessment for ROSA-IV Test SB-CL-18, performed for the NRC pressurized thermal 

shock evaluation using RELAP5/MOD3.2.2Gamma, is documented in Reference 3.5. 

Figure 3.2 compares the measured and calculated break mass flow responses from that 

assessment. When the loop seal clears, steam reaches the break location, greatly reducing the 

break mass flow rate. In the test the loop seal cleared at 140 s and this is closely matched by 

the 148-s RELAP5 calculated loop seal clearing time. The assessment indicates that the 

RELAP5 prediction of the loop seal clearing behavior in the experiment is excellent. 

PMK-2 CAMP-CLB Experiment 

The PMK-2 experimental facility (Reference 3.6) is a 1/2070 volume-scaled full-pressure 

representation of a VVER-440/213 six-loop PWR. Loop seals are employed in both the cold leg 

and HL. The six loops of the PWR are represented using a single loop in the test facility. 

PMK-2 Experiment CAMP-CLB represents a 2% cold leg SBLOCA with the reactor in full-power 

operation. The failure of the HPI system was assumed and a plant recovery operation involving 

depressurization of the SG secondary systems was simulated. A main objective of the test was 

to evaluate the effect of the HL loop seal behavior on the RCS flow, SG heat transfer and 

accumulator injection. 

A recent assessment for the PMK-2 CAMP-CLB experiment using RELAP5/MOD3.2.2Gamma, 

is documented in Reference 3.7. Figures 3.3 and 3.4 compare the measured and calculated 

levels in the RV-side and SG-side of the hot-leg and cold-leg loop seals. The assessment 

judged that the RELAP5 prediction of the initial opening of the steam path through the HL loop 

seal due to partial clearing is very good. However, this event was not seen to lead to loop flow 

stagnation in the calculation as it did in the test and, as a result, the cold leg loop seal opened 

about 120 s earlier in the calculation than in the test. The assessment judged that simulating 

the behavior in this experiment is challenging for the code because of the partial clearing 

experienced in both the HL and cold leg loop seals. It was noted that flow and pressure 

oscillations caused by partial cold leg loop seal clearing had the effect of causing repeated core 

heat-up and quenching cycles in both the test and calculation. The assessment concluded that 

code prediction of the system parameters and (with the exceptions noted above) the loop seal 

behavior was in good agreement with the test data. 

BETHSY SBLOCA Experiments 

The BETHSY experimental facility is a full-pressure, full-height, 1/100 volume-scaled model of a 

2,775 MWt Framatome PWR. The test rig includes three coolant loops, each of which contains 

a loop seal between the SG and RCP. 

As reported in the summary of RELAP5/MOD3 independent code assessments (Reference 3.8), 

INEL evaluated the capabilities of RELAP5/MOD3 Version 7 for predicting two BETHSY small 

break LOCA experiments. Test 9.1b represented a 5.08-cm [2-in] cold leg break with HPI 

unavailable and Test 6.2TC represented a 15.2-cm [6-in] cold leg break with both high and low 

pressure injection systems unavailable. INEL concluded that the RELAP5/MOD3 simulations 

for these two tests showed reasonable agreement with the loop seal clearing behavior observed 

in the experiments. 
35

Figure 3.1 Steam Emissivity as a Function of Temperature and Optical Depth 

0 100 200 300 400 500 600 700 800 900

Time (s)

−10

0

10

20

30

40

50

Flow Rate (kg/s)

mflowj−915000000 (RELAP5)

ST_TANK (Data)

Figure 3.2 Break Flow for ROSA-IV Test SB-CL-18 
36

Figure 3.3 Hot Leg Loop Seal Collapsed Levels for the PMK CAMP-CLB Experiment 

Figure 3.4 Cold Leg Loop Seal Collapsed Levels for the PMK CAMP-CLB Experiment 
37

3.2.2 Pressurizer Filling, Draining and Relief Valve Behavior 

Pressurizer behavior is key for the containment bypass application because it affects the 

distribution of water and steam within the RCS and the flow of mass and energy out of the RCS. 

Little change is seen in the pressurizer water inventory during the early portion of the SBO 

accident sequence, when heat is removed through the SGs. After the dry-out of the SGs, the 

water in the RCS is heated, increasing the RCS pressure and swelling up the water level in the 

pressurizer. The RCS pressure is relieved through the pressurizer PORVs and SRVs which are 

located on piping connected to the top of the pressurizer. The flow of energy through the relief 

valves is a major contributor to the RCS energy balance and the fluid mass exiting through the 

valves is afterward lost to the RCS. The pressurizer liquid inventory declines as a result of the 

fluid lost through the relief valves and as a result of draining of water through the surge line into 

the HL. 

From its inception in the early 1980’s, the RELAP5 code was developed to represent the 

behavior of PWRs during SBLOCAs, for which pressurizer draining, pressurizer filling and relief 

valve flow are important behavior. RELAP5 pressurizer behavior was therefore the subject of 

much early code assessment using experimental data from the Semiscale, LOFT, and other 

experimental facilities. Those early assessments resulted in improved simulation of pressurizer 

behavior through code improvements and development of user modeling guidelines for 

nodalization and code option selection. The RELAP5 code has been developed over the 

25 years since those early assessments. In order to gain an updated picture of RELAP5 

capabilities, the literature was searched for more recent assessments of its capabilities for 

predicting pressurizer behavior. The following code assessments against experiments 

characterize those capabilities and indicate that SCDAP/RELAP5 can well simulate PWR 

pressurizer behavior. 

MIT Pressurizer Test ST4 

Tests simulating a PWR pressurizer under inflow and outflow conditions were performed at the 

Massachusetts Institute of Technology (MIT), Reference 3.9. The MIT pressurizer was a 

small-scale, low-pressure representation of a PWR pressurizer. The vessel representing the 

pressurizer was 1.14-m [3.74-ft] tall with an inner diameter of 0.203 m [0.667 ft]. For Test ST4 

the tank was initialized with a low level of saturated water at 0.493 MPa [71.5 psia] under 

quiescent conditions. Subcooled water was injected into the tank, increasing the water level at 

approximately 1 cm/s [0.394 in/s]. The steam in the upper part of the vessel was compressed. 

As the saturation temperature rose, the vessel walls became subcooled and film condensation 

occurred. 

An assessment of RELAP5/MOD3.2.2Gamma against the ST4 test data, recently documented 

in Reference 3.5, concluded that the code well predicts the tank pressure, level, and vapor 

temperature seen in the experiment. Figure 3.5 shows good agreement between the measured 

and code-calculated tank pressures from that assessment, which indicates the code can well 

simulate the RCS pressurization experienced during the SBO event sequence following the loss 

of the SG heat sink. 

APEX-CE-13 

APEX-CE is a one-quarter height scale low-pressure integral systems experimental facility 

configured to model the thermal-hydraulic phenomena in PWRs of CE design. Test 
38

APEX-CE-13 (Reference 3.10) simulates a stuck-open pressurizer SRV event that occurs with 

the reactor in full power operation. The valve was opened at the start of the test and the HPI 

system was subsequently activated. The valve was kept open for an hour and was then closed. 

The test was terminated about 20 minutes later, after the RCS had refilled. 

An assessment of RELAP5/MOD3.2.2Gamma against the APEX-CE-13 test data, documented 

in Reference 3.5, indicated that the code well predicts the pressurizer pressure and level seen 

in the experiment. Figures 3.6 and 3.7, respectively, compare the measured and codecalculated RCS pressures and pressurizer levels from that assessment. The pressure 

comparison indicates that the energy flow out of the pressurizer relief valve is well simulated. 

MIST Test 360499 

MIST (Multi-loop Integral System Test) is a scaled, full-pressure experimental facility that 

represents a Babcock and Wilcox lowered-loop PWR with two HLs and four cold legs. The 

plant-to-test facility power scaling factor is 817 and the plant-to-test facility volume scaling factor 

is 620. Major components in MIST include two once-through steam generators with full-length 

tubes, two HL piping segments, four cold leg piping segments, four RCPs, a RV with an external 

downcomer, a pressurizer with spray and PORV connections and one core flood tank. 

Boundary systems provide simulation of the high and low pressure injection and emergency 

feedwater systems, and various types of failures such as SG tube ruptures and LOCAs. The 

configuration of the MIST facility is described in Reference 3.11. 

Mist Test 360499, represents a HPI/pressurizer PORV feed-and-bleed cooling operation. At the 

beginning of the test, the MIST facility was operating at 110% scaled reactor coolant flow, 10% 

scaled power and an RCS pressure of 14.82 MPa [2,150 psia]. The feed-and-bleed operation 

was initiated by interrupting all feedwater flow and isolating the steam flow paths on both steam 

generators. 
39

0 10 20 30 40 50

Time (s)

0.48

0.50

0.52

0.54

0.56

0.58

0.60

Pressure (MPa)

p−3100001 (RELAP5) 

Data 

0 10 20 30 40 50

69.6

72.5

75.4

78.3

81.2

84.1

87.0

Pressure (psia)

Figure 3.5 Pressurizer Level for MIT ST4 Pressurizer Insurge Experiment 

0 1000 2000 3000 4000 5000

Time (s)

1.00

1.50

2.00

2.50

3.00

Pressure (MPa)

p−440010000 (RELAP5) 

PT−604 (Data) 

0 1000 2000 3000 4000 5000

145

218

290

363

435

Pressure (psia)

Figure 3.6 RCS Pressure for APEX-CE-13 Stuck-Open Pressurizer SRV Experiment 
40

0 1000 2000 3000 4000 5000

Time (s)

0.00

1.00

2.00

3.00

4.00

Level (m)

cntrlvar−441 (RELAP5) 

LDP−601 (Data) 

0 1000 2000 3000 4000 5000

0.0

3.3

6.6

9.8

13.1

Level (ft)

Figure 3.7 Pressurizer Level for APEX-CE-13 Stuck-Open Pressurizer SRV Experiment 

An assessment of RELAP5/MOD3.2.2Gamma against the MIST 360499 test data, documented 

in Reference 3.5, indicated that the code well predicts the PORV flow and RCS pressure seen 

in the experiment. Figures 3.8 and 3.9, respectively, compare the measured and 

code-calculated PORV flows and RCS pressures from that assessment. The PORV flow 

comparison indicates that code simulation of the fluid drawn into the pressurizer and the phase 

separation within the tank are well simulated. The pressure comparison indicates that the 

energy flow out of the pressurizer relief valve is well simulated. 

LOBI Test BT-56 

The LOBI-MOD2 experimental facility is a high-pressure, 1/712-scale, two-loop representation 

of a 1,300-MWe, four-loop KWU PWR. Each loop in the test facility includes a HL, SG, 

crossover leg, RCP and cold leg. The pressurizer is connected to one of the loops. 

LOBI Test BT-56 (Reference 3.12) was intended to represent a loss-of-feedwater event, but 

multiple unintended and inadvertent failures during the conduct of the experiment caused the 

test to represent a more challenging accident. In addition to a loss of feedwater, the test 

simulated a loss of pumped coolant loop flow, a delay in the reactor trip function and, as a result 

of the overpressurization, a loss of primary inventory due to the rupture of a pressure safety 

disk. As performed, Test BT-56 simulates many of the processes and behaviors expected 

during a PWR SBO severe accident, including the loss of all feedwater, loss of SG inventory, 

tripping of the RCPs, RCS overpressurization and RCS inventory depletion. 
41

0 5000 10000 15000 20000 25000 30000

Time (s)

0.00

0.03

0.05

0.08

0.10

Mass Flow Rate (kg/s)

mflowj−440000000 (RELAP5) 

fporv (Data) 

0 5000 10000 15000 20000 25000 30000

0.00

0.06

0.11

0.17

0.22

Mass Flow Rate (lbm/s)

Figure 3.8 Pressurizer PORV Flow for MIST 360499 Feed-and-Bleed Cooling 

Experiment 

0 5000 10000 15000 20000 25000 30000

Time (s)

0.0

5.0

10.0

15.0

20.0

Pressure (MPa)

p−420010000 (RELAP5) 

RVGP01 (Data) 

0 5000 10000 15000 20000 25000 30000

0

725

1450

2176

2901

Pressure (psia)

Figure 3.9 RCS Pressure for MIST 360499 Feed-and-Bleed Cooling Experiment 
42

An assessment of RELAP5/MOD3.2 against the LOBI BT-56 test data, documented in 

Reference 3.13, indicated that the code well predicts the RCS pressure, pressurizer surge line 

flow and RCS inventory responses seen in the experiment. Figures 3.10, 3.11 and 3.12, 

respectively, compare the measured and code-calculated RCS pressures, pressurizer surge line 

volumetric flow rates and intact-loop cold leg fluid densities from that assessment. In these 

figures the test begins at 500 s, the pressure disk ruptures at ~518 s, the reactor trip occurs 

at ~524 s and the pressurizer empties at ~540 s. The assessment report indicated that the 

code well predicted the times for the pressure disk rupture and the emptying of the pressurizer. 

The RCS pressure comparison indicates an excellent code simulation during both the 

pressurization and depressurization portions of the test sequence. The surge line flow 

comparison indicates good simulations of the flow rates into the pressurizer during the 

pressurization period and out of the pressurizer during the depressurization period. (Note that 

the instrument upon which the measured flow is based measures the rate but not the direction 

of the flow and that the RELAP5-calculated data is presented in the figure on the same basis). 

The cold leg density comparison indicates good agreement between the measured and 

calculated RCS inventories following the opening of the rupture disk and the draining of the 

pressurizer. 

3.3 SCDAP Assessments Pertinent for the Containment Bypass Application

For the containment bypass base case event sequence application, the failure of the plant 

structures (HLs, pressurizer surge line and SG tubes) occurs relatively early in the core damage 

process. The RCS fluid temperatures rise rapidly and lead to the structural failures shortly after 

the time when the fuel rod cladding oxidation process peaks. For this reason, early-phase 

severe accident behavior (core boil-off and uncovery, fuel rod heat-up, hydrogen production due 

to fuel rod cladding oxidation and fuel rod cladding ballooning and rupture) are the most 

pertinent for the containment bypass application. Late-phase severe accident behavior (fuel rod 

melting, the formation and re-freezing of porous debris, slumping and relocation of molten fuel 

and molten fuel-coolant interaction in the lower head of the RV) occurs subsequent to the critical 

time period (i.e., when the HL and pressurizer surge line structures are predicted to fail) in the 

base case accident sequence as well as in most of the other event sequences analyzed in this 

report. 

A comprehensive assessment of SCDAP/MOD3.3 code capabilities for simulating PWR severe 

accident behavior is documented by INEL in Volume 5 of the code manual, Reference 3.1. The 

INEL SCDAP assessments related to the early-phase severe accident behavior are summarized 

as follows. 

3.3.1 Models for PWR Fuel Assembly Heat-Up Behavior 

Assessments of the SCDAP models for fuel rod heat-up were performed for situations of 

gradual core uncovery using test data from the FLHT-5, PBF SFD ST and PBF SFD 1-1 

experiments and for situations of complete core uncovery using test data from the PBF 

SFD 1-4, CORA-5, CORA-7, CORA-13, PHEBUSB-9+, and PHEBUS FPT0 experiments. 
43

Figure 3.10 RCS Pressure for LOBI BT-56 Loss-of-Feedwater Experiment 

Figure 3.11 Pressurizer Surge Line Flow for LOBI BT-56 Loss-of-Feedwater Experiment 
44

Figure 3.12 Intact Loop Cold Leg Density for LOBI BT-56 Loss-of-Feedwater 

Experiment 

The assessment performed using data from the CORA-7 experiment is described as follows; 

assessment results for this test are representative of code capabilities for predicting the fuel rod 

heat-up behavior. The CORA test facility in Karlsruhe, Germany was designed to investigate 

core damage progression under severe accident conditions. The tests used bundles of 

electrically-heated and unheated 2-m [6.56-ft] fuel rods to simulate decay heating in a reactor 

core. CORA-7 was a 56-rod experiment with 32 electrically-heated rods, 19 fresh PWR-type 

fuel rods and five typical PWR silver-indium-cadmium control rods. The test was performed by 

powering the electrically-heated rods with argon flowing through the bundle. Superheated 

steam was added to the bundle, the power to the electrically-heated rods was increased and the 

test rig temperatures, pressures, flow rates and hydrogen generation rates were measured. 

Figure 3.13 compares the CORA-7 measured and SCDAP calculated fuel rod temperatures. 

The assessment concluded that the SCDAP-calculated behavior of the test fuel assembly is in 

good agreement with the measured behavior. 

3.3.2 Models for Fuel Rod Cladding Oxidation 

SCDAP capabilities for predicting hydrogen production due to oxidation of fuel rod cladding 

during severe accidents were assessed using data from nine severe accident experiments in 

five experimental facilities. Table 3.1 compares the measured and calculated total hydrogen 

production for the nine experiments. The calculated hydrogen production was less than the 

measured production for four tests, greater than the measured production for two tests and 

within the uncertainty in the measured hydrogen production for the other tests. The calculated 

hydrogen production among the assessment cases ranged from 50% too large to 15% too 

small. The assessment concluded that the calculated hydrogen production was generally in 

good agreement with measured test behavior.
45

Figure 3.13 Fuel Rod Temperature at the 0.75-m Elevation for CORA-7 Test 

Table 3.1 Summary of Measured and SCDAP-Calculated Hydrogen Production 

During Severe Accident Experiments 

Experiment 

Measured Total 

Hydrogen 

Production 

(g) 

SCDAP/MOD3.3-

Calculated Total 

Hydrogen Production 

(g) 

FLHT-5 300 +30 231 

PBF SFD ST 150 +35 125 

PBF SFD 1-1 64 +7 105 

PBF SFD 1-4 86 +12 82 

CORA-7 114 91 

CORA-13 161 158 

PHEBUS B9+ 39 46 

PHEBUS FPT0 90 77 

ACRR DF-4 40 29 
46

3.3.3 Models for Fuel Rod Ballooning and Rupture 

SCDAP capabilities for predicting fuel rod ballooning and rupture during severe accidents were 

assessed using data from five severe accident experiments in three experimental facilities. 

Table 3.2 compares the measured and calculated fuel rod rupture temperatures and rupture 

times for the five experiments. The calculated and measured rupture temperatures and times 

were in good agreement for three of the experiments. For the other two tests, PBF SFD 1-1 and 

PBF SFD 1-4, the calculated rupture times were significantly later or earlier than observed in the 

tests. The assessment concluded that there is potential for improving the SCDAP fuel rod 

ballooning and rupture code models. 

Table 3.2 Summary of Measured and SCDAP-Calculated Fuel Rod Rupture 

Behavior During Severe Accident Experiments 

Experiment 

Measured 

Rupture 

Temperature 

(K) 

Calculated 

Rupture 

Temperature 

(K) 

Measured 

Rupture 

Time 

(s) 

Calculated 

Rupture Time

(s) 

FLHT-5 1950 1900 1010 1230 

PBF SFD ST 1150-1200 1050 5850-6260 6015-6385 

PBF SFD 1-1 1538-1632 1785-1798 1150-1280 1785-1795 

PBF SFD 1-4 1720-1900 1360-1530 1300-1600 1100-1150 

PHEBUS FPT0 973 1060-1070 N/A 7350-7410 

3.4 Description of SCDAP/RELAP5 Westinghouse Four-Loop Plant Model, 

Including Features Benefitting from Supporting CFD Analyses

The SCDAP/RELAP5 Westinghouse four-loop plant model represents the fluid volumes and 

structures in the core, RV and primary and secondary coolant system regions in the plant. The 

model also includes a simple representation of the containment. The final SCDAP/RELAP5 

model is the culmination of model development and improvement activities spanning the period 

from 1998 through 2007. Those activities, and analysis results obtained with interim models 

that remain pertinent today, are summarized in Section 2. The SCDAP/RELAP5 modeling 

benefitted from ongoing CFD analyses carried out by the NRC staff. Reference 3.14 documents 

the updated NRC CFD evaluations. The SCDAP/RELAP5 predictions did not include all of the 

final recommendations from the CFD evaluations since the predictions were completed prior to 

the conclusion of the CFD work. However, the SCDAP/RELAP5 model is consistent with the 

most significant aspects of the CFD evaluations. 

The nodalization diagrams for the final SCDAP/RELAP5 Westinghouse four-loop plant model 

are provided in Figures 3.14 through 3.17. In these diagrams, open areas typically represent 

fluid regions, arrows represent flow paths and shaded regions represent the structures of the 

model (such as fuel rods, vessel internals and piping walls). The reader is cautioned that for 

practical reasons the sub-structure of some components in the model cannot be accurately 

shown in these diagrams. 
47

SCDAP/RELAP5 SBO accident calculations are performed in four sequential steps, which are 

described as follows. 

In Step 1 (steady state) the plant model using the RV nodalization in Figure 3.14 and the 

coolant loop nodalization for normal-operation water flow in Figure 3.15 is used to establish 

full-power steady-state conditions from which the SBO transient accident sequence is 

initiated. Figure 3.15 shows the nodalization for only one of the coolant loops; identical 

models are used for all four coolant loops (with the exception of the pressurizer and surge 

line, which are connected only on Loop 1). 

In Step 2 (time reset), the same model is used to perform a brief restart calculation for the 

purpose of resetting the problem time to zero at the start of the transient SBO accident 

sequence. 

In Step 3 (event initiation), the model continues using the nodalization schemes shown in 

Figures 3.14 and 3.15, but model features and changes are implemented to initiate the SBO 

accident sequence. These include: tripping of the reactor, turbine, main feedwater and 

RCPs and opening of the SG steam leakage and RCP shaft seal leakage paths. This model 

is run from the time of the SBO event initiation until the time when the core uncovers and 

superheated steam begins to enter the coolant loops. 

In Step 4 (post core uncovery), significant modeling changes are made to permit the 

simulation of the two different coolant loop natural circulation modes shown in Figure 1.2. 

The mode shown on the right side of Figure 1.2 represents a countercurrent flow situation: 

hot steam is passed through the upper halves of the HLs to the SG inlet plenum where 

mixing occurs (resulting in a counter flow of hot and cool steam through the SG tubes) and 

cool steam is returned to the RV via counter flow through the lower halves of the HLs. The 

mode shown on the left side of Figure 1.2 represents a flow of steam from the RV upper 

plenum, through the HLs and completely around the coolant loop to the RV downcomer. 

The model selects the coolant loop circulation mode based upon whether or not the loop 

seal piping (between the SGs and the RCPs, see Component 116 in Figures 3.15 and 3.16) 

and the region at the bottom of the downcomer skirt in the RV (Cell 504-6, see Figure 3.14) 

remain filled with water, blocking the path for steam to flow from the SG outlet plenum 

through the RCPs, cold legs and the RV downcomer to the core inlet. The selection is made 

independently for each of the four coolant loops in the model. The model therefore is 

capable of representing both of the coolant loop flow behaviors shown in Figure 1.2. 
48

Figure 3.14 Reactor Vessel Nodalization 
49

Figure 3.15 Coolant Loop Nodalization Excluding Provisions for Countercurrent Natural 

Circulation 
50

Figure 3.16 Coolant Loop Nodalization With Provisions for Countercurrent Natural 

Circulation 
51

Figure 3.17 Surge Line Connections to the Split Hot Leg During Countercurrent Natural 

Circulation 
52

The major features of the SCDAP/RELAP5 Westinghouse four-loop plant model are 

summarized as follows: 

The RV is nodalized using five cross-connected, vertical flow channels as shown in Figure 3.14. 

The five reactor core region channels (511 through 515) represent a center-peaked radial power 

profile. Each channel is modeled using 40 axial cells. The RV upper plenum region is 

correspondingly modeled with five channels, four axial cells, and guide tube flow paths to the 

RV upper head region. Simpler nodalization schemes are used to model the lower plenum, 

upper head, core bypass and downcomer regions of the RV. 

For calculation Steps 1 through 3 (i.e., up to the time when the core uncovers) the HLs are 

modeled using a single flow path with five axial cells as shown in Figure 3.15. The pressurizer 

surge line connects to the middle HL cell in Coolant Loop 1. The loop seals are modeled with 

five axial cells and the pump discharge cold legs are modeled with four axial cells. Connections 

are made to the coolant loop model representing the accumulator injection lines and the RCP 

shaft seal leakage. The pressurizer is represented with six axial cells and the pressurizer surge 

line is represented with seven axial cells. The spray lines and control valves are represented in 

the model, along with the pressurizer PORV and SRV pressure relief functions. RCS coolant 

flows lost through the RCP shaft seal leaks and through the pressurizer PORVs and SRVs are 

discharged into the containment, which is represented using a single hydrodynamic cell. 

In the SGs, single cells represent the inlet plenum and outlet plenum. The active portion of the 

SG tubes is modeled using a single flow path with 22 axial cells. Each pass through the 

tubesheet is represented with two axial cells. Fine axial nodalization is used for the tube 

regions within the tubesheet and just above the upper surface of the tubesheet. The axial 

nodalization used in the SG secondary boiler region is consistent with that used for the SG tube 

primary-side flow path. Less complex nodalization is used to represent the SG separator, dryer, 

steam dome and downcomer regions. Connections to the SG secondary system are made to 

represent MFW flow, the main steam flow to the turbine, the SG PORV and SRV pressure relief 

functions, and the steam leakage. Heat losses to containment from the external walls of the 

primary and secondary reactor coolant systems are included in the model. For this purpose, the 

model uses a heat transfer coefficient on the external surfaces which provides a total heat loss 

to containment of 4 MW during normal full-power operation; this heat transfer coefficient is held 

constant throughout the steady state and transient accident calculations. 

For calculation Step 4 (i.e., after the time when the core uncovers), the coolant loop models are 

switched to the nodalization shown in Figure 3.16. In this configuration the model uses two flow 

paths to represent the upper and lower HL sections, three cells (105, 106 and 107) to represent 

hot, mixing and cold SG inlet plenum regions and two flow paths to represent forward-flowing 

and reverse-flowing groups of SG tubes. Model discretization in the axial direction is not 

changed between calculation Steps 3 and 4. The HLs are split into two equal-area flow paths 

and the lower sections of the four HLs connect to RV upper plenum Cell 581, see Figure 3.14. 

The pressurizer surge line connects on the side of the HL (in some plants, this connection is 

instead made on the top of the HL). Figure 3.17 shows the HL-to-surge line connection scheme 

employed for joining the surge line to the upper and lower HL sections. The NRC performed 

CFD evaluations (Reference 3.14) of the behavior at this connection following the time when the 

water has been drained out of the pressurizer. The evaluations indicated that the flow into a 

side mounted surge line is drawn equally from the upper and lower HL regions during periods 

when the pressurizer PORVs are closed. The valve and flow boundary conditions employed at 
53

this connection allow the SCDAP/RELAP5 model to match the behavior seen in the CFD 

calculations. 

To represent thermal radiation heat transfer from the superheated steam encountered during 

calculation Step 4, the steam-to-wall radiation heat transfer model described in Section 3.1 was 

generally activated for surfaces representing the interior boundaries of the primary and 

secondary coolant systems in the plant model. The model was activated at the interior surfaces 

of heat structures representing the RV, HLs, pressurizer, pressurizer surge line, cold legs, SG 

inlet plenum, SG outlet plenum, tubesheet and SG shell. The model was also activated on the 

inner surfaces but not on the outer surfaces of the SG tubes. For the outer SG tube surfaces, it 

was judged that thermal radiation heat transfer within the tight tube bundle configuration could 

not be well represented, given the limitations imposed by the coarse SCDAP/RELAP5 SG tube 

and secondary-side model nodalizations. 

Because the temperatures of steam carried by the upper and lower HL sections are very 

different, radiation enclosure (network) models were also included to represent wall-to-wall 

thermal radiation processes involving the HL piping walls connected to the upper and lower HL 

sections. 

The SCDAP/RELAP5 code does not have models capable of calculating from first principles the 

fluid mixing behavior in the SG inlet plenum region and the resulting circulating flows in the split 

HL and split SG tube flow paths during calculation Step 4. Instead, the SCDAP/RELAP5 

system model analyses are performed by incorporating flow resistance adjustments in the SG 

inlet plenum region for the purpose of matching target values for the HL flow and SG inlet 

plenum fluid mixing parameters. 

Reference 3.15 describes experiments conducted for the purpose of evaluating buoyancydriven flows through horizontal ducts connecting two tanks containing fluids of different 

densities. The experiments correlate the volumetric flow rate (Q) in the horizontal duct, the 

average fluid density (ρ) and the difference between the two tank fluid densities (Δρ) using a 

discharge coefficient (CD): 

Q = CD [ g (Δρ / ρ ) D5

 ] 1/2

where g is the acceleration due to gravity. 

The HL in the Westinghouse plant is analogous to the horizontal duct in the experiments, the 

RV and SG inlet plenum in the plant are analogous to the two tanks in the experiments, and the 

discharge coefficient characterizes the HL flow in the plant. CFD analyses (Reference 3.14) 

using the geometry of interest for the plant were performed to define a target CD for this specific 

SCDAP/RELAP5 plant model. 

SG inlet plenum fluid mixing parameters were defined based on the flow paths observed in a set 

of Westinghouse one-seventh scale experiments (Reference 3.16). The hot mixing fraction is 

defined as the fraction of the upper HL section flow that is directed to the mixing region of the 

SG inlet plenum (i.e., from Cell 100-5 to Cell 106 in Figure 3.16). Similarly, the cold mixing 

fraction is defined as the fraction of the cold return SG tube flow that is directed to the mixing 

region of the SG inlet plenum (i.e., from Cell 111-26 to Cell 106 in Figure 3.16). The 

recirculation ratio is defined as the ratio of the flows circulating through the hot and cold SG 

tubes to the flows circulating in the upper and lower HL sections. 
54

CFD analyses were performed to extend the experimental results to full scale conditions in the 

HL, SG inlet plenum and SG tube regions of a Westinghouse plant during a SBO event. This 

initial CFD analyses resulted in the following recommendations for the target mixing parameters 

for use in the SCDAP/RELAP5 system analyses: 

SG Tubes in Hot / Cold Regions: 41% / 59% 

Hot Leg CD = 0.12 

Hot Mixing Fraction = 0.85 

Cold Mixing Fraction = 0.85 

Recirculation Ratio = 2.0 

During calculation Step 4, the hydrodynamic cells and heat structures in the SG model are 

reconfigured to represent the desired 41%/59% split of the unplugged SG tubes into hot 

average (forward-flowing) and cold average (reverse-flowing) regions. Ten percent of the tubes 

in each SG are assumed to be plugged. The SCDAP/RELAP5 flow coefficients in the inlet 

plenum regions of the four SGs are adjusted to achieve the above target values for hot leg CD, 

hot and cold mixing fractions and recirculation ratio. Once the flow coefficients needed to attain 

the desired target mixing parameter values have been determined, they are held constant 

throughout calculation Step 4. An identical set of flow coefficients is used in each of the four 

SGs in the model. 

In addition to the hot average and cold average SG tube regions, during calculation Step 4 a 

representation for a hottest tube is added to the SG model in the pressurizer loop. (Due to the 

pressurizer relief valve flows, hot steam is drawn into the pressurizer loop HL at a higher rate 

than in the other loops and this places the most challenging tube conditions in the pressurizerloop SG). The hottest tube model uses a normalized temperature ratio (NTR) to characterize 

the temperature of the fluid entering the hottest tube. The NTR relates the difference between 

the hottest SG tube inlet fluid temperature and the cold average (reverse-flowing) SG tube outlet 

fluid temperature to the maximum expected temperature difference (between the upper HL 

section outlet and cold average SG tube outlet fluid temperatures): 

NTR = ( Thottest tube – Tcold tube ) / ( Thot leg – Tcold tube ) 

Experimental data from the Westinghouse one-seventh scale experiments (Reference 3.16) and 

CFD evaluations are used to select the NTR. The SCDAP/RELAP5 Westinghouse four-loop 

plant SBO base case calculation in Section 4 assumes a NTR of 0.5 as recommended in 

Reference 3.14. (Other values for NTR have also been investigated, see Sections 2.3 and 2.8.) 

The hottest tube model represents a single tube from the bottom of the tubesheet to the top of 

the tube U-bend and uses axial nodalization consistent with that used in the average tube 

model. The hydraulics for the primary side of the hottest tube model are based on an inlet fluid 

temperature calculated via the NTR, inlet fluid conditions and inlet velocity that are otherwise 

consistent with the hot average tube model, and an outlet pressure consistent with the pressure 

at the top of the U-bend of the hot average tube model. On the secondary side, the heat 

structure representing the hot average tube is connected to the same SG boiler-region fluid cells 

as the hot average tube model. 

In the Westinghouse four-loop plant model, creep rupture failure calculations are performed for 

the hot average SG tubes (at the inlet, just above the tubesheet), for the upper HL piping 

sections (at the RV end) in all four coolant loops, for the pressurizer surge line (at the HL end) 

and for the hottest tube in the pressurizer-loop SG (at the inlet, just above the tubesheet). A 

stress multiplier of 1.0 is used for the HL and surge line structure calculations while stress 
55

multipliers from 1.0 to 7.5 in increments of 0.5 are used for the SG tube calculations. The range 

of stress multipliers evaluated for the SG tubes allows comparison of failure times for tubes with 

varying degrees of strength degradation. See Section 3.1 for a description of the creep rupture 

model and the definition of the stress multiplier. The principal outcomes from the 

SCDAP/RELAP5 analysis are the HL, pressurizer surge line and SG tube structure failure times 

and the SG tube failure margins for the hot average tube and hottest tube. These margins are 

expressed as the tube stress multiplier (i.e., the extent of strength degradation) required for tube 

failure to occur concurrently with the earlier of HL or pressurizer surge line failure. 
56
57

4. WESTINGHOUSE FOUR-LOOP PLANT STATION BLACKOUT 

BASE CASE ANALYSIS 

The SCDAP/RELAP5 simulation for the base case extended SBO event sequence in a 

Westinghouse four-loop PWR is presented in this section. The base case SBO accident event 

sequence assumptions are described in Section 1.2 and a summary of the expected overall 

plant behavior during the event sequence is given in Section 1.3. Definitions for the SG tube 

failure margins and criteria for judging the containment bypass outcome are given in 

Section 1.4. The SCDAP/RELAP5 computer code is described in Section 3.1 and assessments 

of the code pertinent for the containment bypass application are described in Sections 3.2 

and 3.3. The SCDAP/RELAP5 Westinghouse four-loop plant model used for this base case 

calculation is described in Section 3.4. The SCDAP/RELAP5 simulation results for steady 

full-power plant operation, from which the transient SBO event sequence begins, are given in 

Section 4.1 and the SCDAP/RELAP5 simulation results for the transient base case SBO event 

sequence are given in Section 4.2.

4.1 Full-Power Steady State Calculation

The SCDAP/RELAP5 plant model was run to a steady solution. For reference, the file name of 

the input model for the steady-state run is “wnewbases1.i”. The file name of a short 

SCDAP/RELAP5 restart calculation from the end point of the steady-state run (to reset the 

problem time to zero) is “wnewbases2.i”. These are Steps 1 and 2 of the sequential four-step 

modeling process described in Section 3.4. 

Table 4.1 compares the SCDAP/RELAP5-calculated steady state conditions with target values 

for a typical Westinghouse four-loop plant in normal full-power operation. The comparisons 

show that the code-calculated parameters are in excellent agreement with the target values. 

The calculated steady state solution therefore represents an acceptable set of initial conditions 

from which to start the SCDAP/RELAP5 transient SBO base case accident simulation. 

Table 4.1 SCDAP/RELAP5 Full-Power Steady State Results 

Parameter Target Valuea SCDAP/RELAP5 

Calculated Value 

Reactor power (MWt) 3,250 3,250 

Pressurizer pressure (MPa) 15.51 15.509 

Pressurizer water/steam volume (%) 60/40 61.2/38.8 

Total RCS coolant loop flow rate (kg/s) 17,010 17,010 

Cold leg temperature (K) 549.9 549.90 

Hot leg temperature (K) 585.5 585.45 

SG secondary pressure (MPa) 4.964 4.892 

Feedwater temperature (K) 493.5 493.48 

Steam flow rate per SG (kg/s) 440.9 439.9 

Liquid volume per SG (m3) 52.05 52.66 

a. Target values are based on information for a typical Westinghouse four-loop PWR with 10% SG tube plugging. 
58

4.2 Transient Station Blackout Calculation

The SBO base case event sequence was simulated with SCDAP/RELAP5, starting from time 

zero when the loss of off-site power occurs. The transient simulation is performed as Steps 3 

and 4 of the four-step modeling process described in Section 3.4. For reference, the file name 

of the Step 3 input model, which is used up to the time of core uncovering, is “wnewbases3.i”. 

The file name of the Step 4 input model, which implements the split HL and SG tube modeling 

features used after the time of core uncovering, is “wnewbases4.i”. 

Table 4.2 shows the SCDAP/RELAP5 calculated sequence of events for the base case SBO 

simulation. The calculated time-history results for key parameters are shown in Figures 4.1 

through 4.22 and are summarized as follows. 

The RCS pressure response is shown in Figure 4.1. After a short period when the RCS 

pressure initially falls and rises slightly due to the effects of the reactor and turbine trips, the 

RCS pressure declines in response to the cooling provided by heat removed to the SGs, the 

flow of coolant out of the RCS through the RCP shaft seal leaks and the RCS heat loss to 

containment. Figure 4.2 shows the SG secondary pressure responses and Figure 4.3 shows 

the RCP shaft seal leak flow responses. The RCS depressurization continues until the SG 

secondary liquid inventories, shown in Figure 4.4, have been boiled and discharged to the 

atmosphere through the SG PORVs. After the SG heat sink is lost, the cooling afforded by 

system heat loss to containment and RCP shaft seal leak flow is insufficient to remove the RCS 

heat load, causing the RCS pressure to increase as shown in Figure 4.1 to the opening setpoint 

pressures of the pressurizer PORVs and SRVs. 

Figures 4.5 and 4.6, respectively, show the pressurizer PORV and pressurizer SRV flows. After 

SG dry-out, the RCS pressure increase is limited by multiple cycling of the PORVs and by two 

cycles of the SRVs during the period with the most-challenging RCS pressurization conditions. 

This challenge is presented when the increasing temperatures cause the RCS fluid to swell, 

completely filling the pressurizer with water. The pressurizer level response is shown in 

Figure 4.7. 

The RCS fluid mass lost through the pressurizer PORVs and SRVs and through the RCP shaft 

seal leakage paths depletes the RCS inventory, the core uncovers and superheated steam 

flows out from the RV into the coolant loops starting at 9,226 s. Water remains trapped in the 

cold leg RCP-suction loop seal piping of the RCS, thus blocking the paths for the steam to flow 

all the way around the coolant loops to the RV inlet nozzles. This blockage is a necessary 

condition for setting up of the countercurrent flows through the HLs and SG tubes. Figure 4.8 

shows the void fractions calculated in the bottom cells of the loop seal piping. The piping at the 

bottom of the loop seals in all four coolant loops remains virtually water filled, with only minor 

bubbling of steam through the loop seals seen during the period of the maximum RCS 

pressurization. 

Following core uncovery, countercurrent flow of superheated steam is calculated through two 

circulation flow paths within each of the four coolant loops. In one circulation path, hot steam 

flows upward from the SG inlet plenum through a portion (41%) of the unplugged SG tubes and 

cool steam returns from the SG outlet plenum through the remaining portion (59%) of the 

unplugged SG tubes, flowing downward as it reaches the SG inlet plenum. In the other 

circulation path, hot steam flows through the RV outlet nozzle and upper half of the HL to the 

SG inlet plenum and cooler steam is returned from the SG inlet plenum to the RV outlet nozzle 

through the lower half of the HL. Mixing between these two circulation flow paths occurs in the 
59

Table 4.2 Sequence of Events from the SCDAP/RELAP5 SBO Base Case 

Calculation 

Event Description Event Time (s) 

SBO event initiation (loss of AC power, reactor trip, turbine trip, 

MFW flow stops, RCPs trip, RCP shaft seal leaks begin, SG steam 

leaks begin). 

0 

RCP rotors coast to a stop, coolant loop natural circulation begins. 106 

SG dry-out (99% void fraction in bottom secondary cell), 

SG1 / SG2 / SG3 / SG4. 

5,905 / 6,020 / 6,020 / 6,020 

Pressurizer PORV cycling begins. 6,698 

First pressurizer SRV cycle, open/close. 8,606 / 8,714 

Loop natural circulation flow interrupted by steam collecting at the 

tops of the SG tube U-bends, SG1 /SG2 /SG3 / SG4. 

8,682 / 8,570 / 8,600 / 8,577 

Second pressurizer SRV cycle, open / close. 9,032 / 9,086 

Collapsed liquid level in the RV falls below the top of the core 

heated length (6.323 m above the bottom of RV lower head). 

9,157 

Steam at the core exit begins to superheat, HL and SG tube flow 

circulations begin, end of SCDAP/RELAP5 modeling Step 3 and 

start of modeling Step 4. 

9,226 

Collapsed liquid level in the RV falls below the bottom of the core 

heated length (2.666 m above the bottom of the RV lower head). 

10,077 

Pressurizer empties. 10,704 

Onset of fuel rod oxidation. 10,747 

First control rod cladding failure. 12,234 

First fuel rod cladding rupture. 13,002 

Peak fuel rod oxidation rate reached. 13,566 

Hot Leg 1 fails by creep rupture. 13,625 

Hot Legs 2, 3 and 4 fail by creep rupture. 13,660 

Hottest SG tube creep rupture failure 

(SG 1, non-degraded tube, 1.0 stress multiplier). 

13,985 

Pressurizer surge line fails by creep rupture. 14,140 

Molten fuel pool begins forming near center of the hottest core 

channel, partial blocking of the core flow begins. 

14,241 

Station batteries assumed to be depleted, pressurizer PORVs and 

SG PORVs fail closed and are no longer operable. 

14,400 

Average SG tube creep rupture failure 

(SG 1, non-degraded tube, 1.0 stress multiplier). 

14,910 

First relocation of control rod absorber material to RV lower head. 15,532 

End of calculation. Molten fuel pool near center of hottest core 

channel continues to grow. Partially liquefied fuel debris is found in 

the other four core channels. Molten fuel has not yet relocated to 

the RV lower head. 

18,000 
60

0 5000 10000 15000 20000

Time (s)

8.0

10.0

12.0

14.0

16.0

18.0

Pressure (MPa)

p−10001 (Hot Leg 1) 

0 5000 10000 15000 20000

1160

1450

1740

2031

2321

2611

Pressure (psia)

Figure 4.1 Reactor Coolant System Pressure 

0 5000 10000 15000 20000

Time (s)

0.00

2.00

4.00

6.00

8.00

Pressure (MPa)

p−18001 (SG 1) 

p−28001 (SG 2)

p−38001 (SG 3) 

p−48001 (SG 4)

0 5000 10000 15000 20000

0

290

580

870

1160

Pressure (psia)

Figure 4.2 Steam Generator Secondary Pressures 
61

0 5000 10000 15000 20000

Time (s)

0.0

0.2

0.4

0.6

0.8

1.0

Flow Rate (kg/s)

mflowj−12500 (Loop 1)

mflowj−22500 (Loop 2)

mflowj−32500 (Loop 3)

mflowj−42500 (Loop 4) 

0 5000 10000 15000 20000

0.00

0.44

0.88

1.32

1.76

2.20

Flow Rate (lbm/s)

Figure 4.3 Reactor Coolant Pump Shaft Seal Leakage Flows 

0 5000 10000 15000 20000

Time (s)

0

10000

20000

30000

40000

50000

Mass (kg)

cntrlvar−1015 (SG 1) 

cntrlvar−2015 (SG 2) 

cntrlvar−3015 (SG 3) 

cntrlvar−4015 (SG 4) 

0 5000 10000 15000 20000

0

22046

44092

66139

88185

110231

Mass (lbm)

Figure 4.4 Steam Generator Secondary Liquid Masses 
62

0 5000 10000 15000 20000

Time (s)

0

40

80

120

160

200

Flow Rate (kg/s)

mflowj−15700 + mflowj−15900 (Pressurizer PORV) 

0 5000 10000 15000 20000

0

88

176

265

353

441

Flow Rate (lbm/s)

Figure 4.5 Total Pressurizer PORV Flow 

0 5000 10000 15000 20000

Time (s)

0

100

200

300

400

Flow Rate (kg/s)

mflowj−15800 (Pressurizer SRV) 

0 5000 10000 15000 20000

0

220

441

661

882

Flow Rate (lbm/s)

Figure 4.6 Pressurizer SRV Flow 
63

0 5000 10000 15000 20000

Time (s)

0.0

3.0

6.0

9.0

12.0

15.0

Water Level (m)

cntrlvar−1150

0 5000 10000 15000 20000

0.0

9.8

19.7

29.5

39.4

49.2

Water Level (ft)

Figure 4.7 Pressurizer Level 

0 5000 10000 15000 20000

Time (s)

0.00

0.01

0.02

0.03

0.04

0.05

Void Fraction

voidg−11604 (Loop 1) 

voidg−21604 (Loop 2) 

voidg−31604 (Loop 3) 

voidg−41604 (Loop 4) 

Figure 4.8 Reactor Coolant Pump Loop Seal Void Fractions 
64

SG inlet plenum. In Coolant Loop 1, which contains the pressurizer, steam may be diverted 

from the HL into the pressurizer surge line. The time-history behavior of the plant parameters is 

generally affected by the cyclic opening and closing of the pressurizer PORVs and pressurizer 

SRVs. 

The flow rates in the SG 1 hot (forward-flowing) and cold (reverse-flowing) average tube 

sections are shown in Figure 4.9. The flow around this circulation path is driven by the net 

positive buoyancy driving head created by the differences in steam densities (resulting from 

temperature differences) in the hot and cold tube sections. Referring to Figure 3.16, the hot 

tube section is represented by Component 110 and the cold tube section is represented by 

Component 111. The declining trend in the SG tube circulation rate in Figure 4.9 results from 

two effects. First, because the initial rise in the temperature of the steam entering the SG is 

rapid and the SGs initially are cold, the initial steam temperature difference is large. However 

over the course of the event sequence, the steam temperature difference declines as a result of 

transfer of heat into to the SG. Second, because the entire RCS is experiencing a transient 

heat-up, steam densities are generally declining and this results in correspondingly declining 

steam mass flow rates. To place the SG tube mass flow rates shown in Figure 4.9 into 

perspective, the 8.0-kg/s [17.6-lbm/s] mass flow rate seen at 13,000 s corresponds to an 

average SG tube steam flow velocity of 0.52 m/s [1.72 ft/s] 

The flow rates in the Loop 1 upper and lower HL sections are shown in Figure 4.10. Unlike the 

SG tube circulation path where the flow rates in the hot and cold sections are the same, in the 

Loop 1 HL circulation path the flow through the upper HL section is greater than that in the lower 

HL section during periods when the pressurizer PORVs are open (the PORV flow response is 

shown in Figure 4.5). The flow around the HL circulation path is driven by the buoyancy head 

created by the steam temperature and density differences between the two sections over the 

vertical portion of the HL and within the SG inlet plenum. The HL bends upward from its 

horizontal run to the SG inlet plenum, with an elevation rise of 0.924 m [3.03 ft] and the 

elevation rise within the SG inlet plenum adds another 1.206 m [3.958 ft]. The declining trend in 

the HL circulation rate results for the same reasons described above for the SG tube circulation 

path. To place the HL mass flow rates shown in Figure 4.10 into perspective, the 4.76-kg/s 

[10.5-lbm/s] upper HL section mass flow rate seen at 13,000 s corresponds to a steam flow 

velocity of 0.700 m/s [2.30 ft/s]. 

In addition to the SG tube and HL flow circulations, there are also flow circulations within the 

RV. Referring to Figures 3.14 and 3.16, flow of hot steam into the upper HL sections leaves the 

RV from Component 582 and the cooler steam flowing through the lower HL sections returns to 

the RV at Component 581. The difference in densities between the hot and cool steam sets up 

circulation paths within the RV. The cooler steam returning from the lower HL sections tends to 

flow downward through the peripheral core regions and then upward through the central core 

regions. Another circulation path also sets up in the RV upper plenum region, with hotter steam 

flowing from the core channel exits across the upper region (through Components 542, 552, 

562, 572 and 582) to reach the entrances to the upper HL sections and with cooler steam 

flowing from the exits of the lower HL sections across the lower region (through Components 

581, 571, 561, 551 and 541) toward the RV centerline. The RV circulation is characterized in 

Figure 4.11, which shows the mass flow rates near the tops of one of the upward-flowing central 

core regions and one of the downward-flowing peripheral core regions (Core Channels 512 and 

514, as shown in Figure 3.14). To place the core mass flow rates shown in Figure 4.11 into 

perspective, the 13.0-kg/s [28.7-lbm/s] central core channel flow seen at 13,000 s corresponds 

to a steam velocity of 0.49 m/s [1.6 ft/s]. 
65

0 5000 10000 15000 20000

Time (s)

0.0

4.0

8.0

12.0

16.0

20.0

Flow Rate (kg/s)

mflowj−11001 (Hot Tube) 

mflowj−11101 (Cold Tube) 

0 5000 10000 15000 20000

0.0

8.8

17.6

26.5

35.3

44.1

Flow Rate (lbm/s)

Figure 4.9 SG 1 Hot and Cold Average Tube Flows 

0 5000 10000 15000 20000

Time (s)

0.0

5.0

10.0

15.0

20.0

Flow Rate (kg/s)

mflowj−10001 (Upper) 

mflowj−10101 (Lower) 

0 5000 10000 15000 20000

0.0

11.0

22.0

33.1

44.1

Flow Rate (lbm/s)

Figure 4.10 Hot Leg 1 Upper and Lower Section Flows 
66

The flow resistances of the SCDAP/RELAP5 plant model in the regions of the SG inlet plenum 

are preset so as to match the behavior of the hot leg discharge coefficient, recirculation ratio, 

hot mixing fraction and cold mixing fraction observed during Westinghouse 1/7th-scale 

experiments and CFD analyses simulating plant behavior during SBOs. (See discussions in 

Section 3.4). Figures 4.12 through 4.15 show the SCDAP/RELAP5-calculated responses for 

these inlet plenum fluid mixing and flow parameters. Table 4.3 compares the smoothed 

SCDAP/RELAP5-calculated values for these parameters (averaged over the four coolant loops) 

with their nominal target values at 13,000 s. Smoothing is necessary because the parameter 

values vary significantly with the cyclic opening and closing of the pressurizer PORVs and the 

rate of PORV cycling increases as the system heat-up rate becomes larger. 13,000 s was 

chosen for the comparison time because parameter values at that time remain relatively stable 

and yet are close to the values experienced at the time when the critical structural failures are 

predicted to occur. Table 4.3 shows excellent agreement of the smoothed SCDAP/ 

RELAP5-calculated and target values for hot leg discharge coefficient, hot and cold mixing 

fractions and recirculation ratio. 

The responses of the hot leg discharge coefficients for the four coolant loops are shown in 

Figure 4.12. This parameter characterizes the countercurrent flow in a horizontal pipe between 

two tanks containing fluids of different densities (see Section 3.4). The average 

SCDAP/RELAP5 calculated value for the hot leg discharge coefficient in the four coolant loops 

is within 0.6% of the 0.12 target value. 

The recirculation ratio, hot mixing fraction and cold mixing fraction responses are shown in 

Figures 4.13, 4.14 and 4.15, respectively. The recirculation ratio is defined as the ratio of the 

SG tube mass flow rate to the HL mass flow rate. The mixing fractions are defined as the 

portions of the flow entering the SG inlet plenum which are directed to the “mixing” plenum 

(Cell 106, see Figure 3.16). The hot mixing fraction is thus the portion of the upper HL flow 

which is directed to the mixing plenum while the cold mixing fraction is the portion of the “cold” 

tube return flow which is directed to the mixing plenum (see Section 3.4). As listed in Table 4.3, 

the target value for the recirculation ratio is 2.0 and the target value for the hot and cold mixing 

fractions is 0.85. The average SCDAP/RELAP5 calculated values for the hot and cold mixing 

fractions are within 0.5% of the target value. The average SCDAP/RELAP5 calculated value for 

the recirculation ratio is within 1.5% of the target value. 

The responses of the SG power fractions are shown in Figure 4.16. This parameter is defined 

as the ratio of the heat removed to each SG (to the tubes, tubesheet, inlet plenum wall and 

outlet plenum wall) to the total core heat (fission product decay and fuel rod oxidation heat). 

The SG power fractions are calculated on an integrated basis, starting at the time of core 

uncovering. The power fractions increase after the core uncovers as the hot steam flows 

outward through the HLs and into the SGs. A first peak in the SG power fractions occurs during 

the period when the fuel rod oxidation process is peaking. The oxidation heat is immediately 

absorbed by the fuel rods, thereby reducing for a time the fraction of the core heat that is 

absorbed by the SGs. After the oxidation process subsides, the excess heat that was absorbed 

in the fuel rods is dissipated into the steam and transported outward into the coolant loops and 

SGs, causing the SG power fractions to again rise. Note that no target value for SG power 

fraction is listed in Table 4.3 (target values for SG power fraction were used in some of the 

earlier analyses, see Sections 2.1 through 2.6). For this final analysis, the previously-used 

target SG power fraction for the modeling process has been replaced with the target hot leg 

discharge coefficient described above. The calculated SG power fraction responses described 

here are provided only for purposes of comparison with the prior analyses. 
67

0 5000 10000 15000 20000

Time (s)

−40.0

−20.0

0.0

20.0

40.0

60.0

Flow Rate (kg/s)

mflowj−51239 (Upward, Central Region) 

mflowj−51439 (Downward, Peripheral Region) 

0 5000 10000 15000 20000

−88

−44

0

44

88

132

Flow Rate (lbm/s)

Figure 4.11 Vessel Circulation Flows 

0 5000 10000 15000 20000

Time (s)

0.10

0.11

0.12

0.13

Hot Leg CD

cntrlvar−9619 (Loop 1) 

cntrlvar−9639 (Loop 2) 

cntrlvar−9659 (Loop 3) 

cntrlvar−9679 (Loop 4) 

Figure 4.12 Hot Leg Discharge Coefficients 
68

0 5000 10000 15000 20000

Time (s)

1.8

1.9

2.0

2.1

2.2

Recirculation Ratio

cntrlvar−5144 (Loop 1) 

cntrlvar−5244 (Loop 2) 

cntrlvar−5344 (Loop 3) 

cntrlvar−5444 (Loop 4) 

Figure 4.13 Recirculation Ratios 

0 5000 10000 15000 20000

Time (s)

0.75

0.80

0.85

0.90

Mixing Fraction

cntrlvar−5135 (Loop 1) 

cntrlvar−5235 (Loop 2) 

cntrlvar−5335 (Loop 3) 

cntrlvar−5435 (Loop 4) 

Figure 4.14 Hot Mixing Fractions 
69

0 5000 10000 15000 20000

Time (s)

0.75

0.80

0.85

0.90

Mixing Fraction

cntrlvar−5138 (Loop 1) 

cntrlvar−5238 (Loop 2) 

cntrlvar−5338 (Loop 3) 

cntrlvar−5438 (Loop 4) 

Figure 4.15 Cold Mixing Fractions 

0 5000 10000 15000 20000

Time (s)

0.00

0.02

0.04

0.06

0.08

0.10

Power Fraction

cntrlvar−5121 (SG 1) 

cntrlvar−5221 (SG 2) 

cntrlvar−5321 (SG 3) 

cntrlvar−5421 (SG 4) 

Figure 4.16 SG Power Fractions 
70

Table 4.3 Comparison of Target and SCDAP/RELAP5-Calculated SG Inlet Plenum 

Fluid Mixing and Flow Parameters 

Parameter Target Value 

SCDAP/RELAP5 

Calculated 

Value 

Assumed Split of SG Tubes into Hot/Cold Regions 41%/59% 41%/59% 

Hottest Tube Normalized Temperature Ratio 0.5 0.5 

Average Hot Leg Discharge Coefficient 0.12 0.1207 

Average Hot Mixing Fraction 0.85 0.854 

Average Cold Mixing Fraction 0.85 0.847 

Average Recirculation Ratio 2.0 1.971 

Portion of the Integrated Total Core Heat Addition 

which is Absorbed in the Four SGs Not Applicable 28.4% 

The rate of hydrogen generation resulting from fuel rod cladding oxidation is shown in 

Figure 4.17. The oxidation process resulting from metal-water reaction on the exterior surfaces 

of the fuel rod cladding begins gradually, starting in the high-power core regions. The oxidation 

rate increases rapidly as fuel temperatures climb, with the process spreading into lower-power 

regions of the core. Fuel rod oxidation begins at 10,747 s and the peak oxidation rate is 

reached at 13,566 s. The major peak in the oxidation rate seen in Figure 4.17 occurs because 

the process accelerates as a result of fuel rod cladding rupture and the involvement of the inner 

cladding surfaces in addition to the outer surfaces. The peak core oxidation power is 300.2 MW 

and during the period of its peak the oxidation power is the dominant contributor to the system 

heat-up. To place the significance of the oxidation power into perspective, at the time of its 

peak the oxidation power is 10.1 times the fission product decay power and 9.2% of the plant 

normal-operation full rated thermal power. 

Figure 4.18 compares the thermal responses for the key structures in Coolant Loop 1. The data 

shown represent the average temperatures across the structure thickness at the hottest axial 

locations. The pressurizer surge line temperature presented is at the end of the line adjacent to 

the HL. The HL temperature presented is for the upper half of the HL adjacent to the RV. The 

average and hottest SG tube temperatures presented are for the upward-flowing tube sections 

just above the top of the tubesheet. 

As the HL steam temperatures rise, the rates at which the structure temperatures increase vary, 

depending on the local steam temperature, the fluid-to-wall heat transfer, and on the material 

and thickness of the structure. Generally, the temperatures of the thin-wall SG tubes respond 

quickly to an increasing steam temperature, while the temperature of the thicker pressurizer 

surge line responds more slowly and the still-thicker HL structure temperature responds even 

more slowly. Because the hottest steam is modeled at its inlet, the temperature of the hottest 

SG tube structure increases more rapidly than the temperature of the average SG tube 

structure. The start of the pressurizer surge line heat-up is delayed until the pressurizer empties 

at 10,704 s. Before that time, liquid intermittently drains out of the pressurizer into the surge line 

during periods when the pressurizer PORVs are closed. The draining cools both the steam 
71

0 5000 10000 15000 20000

Time (s)

0.0

1.0

2.0

3.0

Total H2 Generation Rate (kg/s)

bgth−0

0 5000 10000 15000 20000

0.00

2.20

4.41

6.61

Total H2 Generation Rate (lbm/s)

Figure 4.17 Hydrogen Generation Rate 

0 5000 10000 15000 20000

Time (s)

400

600

800

1000

1200

1400

1600

1800

Heat Structure Temperature (K)

htvat−1531007 (Surge Line) 

htvat−1001001 (Hot Leg) 

htvat−1101001 (Average SG Tube) 

htvat−1121001 (Hottest SG Tube) 

0 5000 10000 15000 20000

260

620

980

1340

1700

2060

2420

2780

Heat Structure Temperature (F)

Figure 4.18 Loop 1 Structure Temperatures 
72

inside the surge line and the surge line wall. This behavior directly affects the response of the 

surge line heat structure but not the HL or SG tube heat structures. After the pressurizer 

empties, the pressurizer PORVs continue to cycle and hot steam is drawn upward through the 

surge line without the cooling benefit afforded by liquid draining downward, causing the surge 

line temperatures to rapidly rise. 

Pressurizer PORV cycling ceases at 14,400 s (four hours after event initiation) when the station 

batteries are assumed to be depleted. Afterward, the RCS pressure increases, but not 

sufficiently to open the pressurizer SRVs, see Figures 4.1 and 4.6. The turnover in the surge 

line structure temperature in Figure 4.18 reflects the cessation of surge line steam flow at that 

time. With neither the pressurizer PORVs nor SRVs opening, the flow of increasingly-hotter 

steam through the surge line stops and the heat loss from the outside of the surge line to the 

containment cools the surge line wall. Figure 4.19 shows a detailed view of the structure 

temperature responses from Figure 4.18 overlaid with the SCDAP/RELAP5-calculated failure 

times for the structures. 

Figures 4.20 through 4.22 compare the Larson-Miller creep rupture damage indexes for the 

surge line, HL and SG tube structures. The damage index indicates the accumulation of creep 

damage as a fraction of the creep damage needed to cause failure; the structural failure is 

predicted to occur at the time when the index value reaches 1.0. The creep rupture model 

allows use of a stress multiplier that represents the effect on the creep calculation 

corresponding to a specific degree of degradation in the strength of a structure due to other 

factors, such as cracks that were present before the accident event sequence started. For the 

pressurizer surge line and HL structures only a stress multiplier of 1.0 is used. A set of stress 

multipliers from 1.0 to 7.5, in increments of 0.5, is used for the SG tube structures as a means to 

introduce tube material strength degradation as an analysis variable. 

Figure 4.20 compares the damage indexes for the pressurizer surge line and the four HLs. The 

failure of Hot Leg 1 occurs first, followed by failures of Hot Legs 2, 3 and 4 and then by the 

failure of the surge line (the calculated creep rupture failure times for all structures in the model 

are listed in Table 4.4). The failure of Hot Leg 1 precedes the failures of the other HLs (by 35 s) 

because of effects related to the connection of the pressurizer to Hot Leg 1. The opening of the 

pressurizer PORVs and SRVs causes steam flow to be drawn through Hot Leg 1 at a higher 

rate than for Hot Legs 2, 3 and 4, resulting in slightly greater heating and the earlier creep 

rupture failure prediction. The prediction of the surge line failure is delayed, relative to the HLs, 

because flow into the surge line is drawn equally from the hot steam in the upper section and 

cool steam in the lower section of Hot Leg 1. 

Figure 4.21 compares the damage indexes for Hot Leg 1 and the average tubes in SG 1. The 

figure and table show that an average tube with a stress multiplier of 2.74 is predicted to fail at 

the same time that Hot Leg 1 fails. In other words, tubes that are subjected to the average 

steam conditions on the inside are not expected to fail before the HL fails as long as 

degradation of the tube strength has not progressed past the point where a tube will fail when 

subjected to a stress of only (1.0 / 2.74 =) 36.5% of the stress that would fail a non-degraded 

SG tube. 

Figure 4.22 compares the damage indexes for Hot Leg 1 and the hottest tube in SG 1 (see 

Section 3.4 for a description of hottest tube modeling). This figure and the event times in 

Table 4.4 indicate that the hottest tube with a stress multiplier of 1.68 is predicted to fail at the 

same time that Hot Leg 1 fails. In other words, tubes that are subjected to the hottest steam on 

the inside are not expected to fail before the HL as long as degradation of the tube strength has 
73

12000 12500 13000 13500 14000 14500 15000

Time (s)

800

1000

1200

1400

1600

Heat Structure Temperature (K)

htvat−1531007 (Surge Line) 

htvat−1001001 (Hot Leg) 

htvat−1101001 (Average SG Tube) 

htvat−1121001 (Hottest SG Tube) 

trip−431 (Surge Line Failure Time) 

trip−432 (Hot Leg 1 Failure Time) 

trip−441 (Average Tube x 1.0 Failure Time) 

trip−572 (Hottest Tube x 1.0 Failure Time) 

12000 12500 13000 13500 14000 14500 15000

980

1340

1700

2060

2420

Heat Structure Temperature (F)

Figure 4.19 Correspondence Between Loop 1 Structure Temperatures and Failure 

Times 

12000 12500 13000 13500 14000 14500 15000

Time (s)

0.00

0.25

0.50

0.75

1.00

Damage Index (Failure = 1)

dcreph−2 (Hot Leg 1) 

dcreph−3 (Hot Leg 2) 

dcreph−4 (Hot Leg 3) 

dcreph−5 (Hot Leg 4) 

dcreph−1 (Surge Line) 

Figure 4.20 Hot Leg and Pressurizer Surge Line Creep Rupture Damage Indexes 
74

12000 12500 13000 13500 14000 14500 15000

Time (s)

0.00

0.25

0.50

0.75

1.00

Damage Index (Failure = 1)

dcreph−2 (Hot Leg 1) 

dcreph−6 (Avg Tube x 1.0) 

dcreph−7 (Avg Tube x 1.5) 

dcreph−8 (Avg Tube x 2.0) 

dcreph−9 (Avg Tube x 2.5) 

dcreph−10 (Avg Tube x 3.0) 

Figure 4.21 SG 1 Average Tube and Hot Leg 1 Creep Rupture Damage Indexes 

12000 12500 13000 13500 14000 14500 15000

Time (s)

0.00

0.25

0.50

0.75

1.00

Damage Index (Failure = 1)

dcreph−2 (Hot Leg 1) 

dcreph−62 (Hottest Tube x 1.0) 

dcreph−63 (Hottest Tube x 1.5) 

dcreph−64 (Hottest Tube x 2.0) 

Figure 4.22 SG 1 Hottest Tube and Hot Leg 1 Creep Rupture Damage Indexes 
75

Table 4.4 Summary of Calculated Creep Rupture Failure Times from the Base Case 

Calculation 

Structure Calculated Failure Time 

(s) 

Pressurizer surge line 14,140 

Hot Leg 1 / Hot Leg 2 / Hot Leg 3 / Hot Leg 4 13,625 / 13,660 / 13,660 / 13,660 

SG 1 / SG 2/ SG 3 / SG 4 

Average SG Tube, Stress Multiplier: 1.0 14,910 / 14,975 / 14,975 / 14,975 

 1.5 14,180 / 14,220 / 14,220 / 14,220 

 2.0 13,850 / 13,880 / 13,880 / 13,880 

 2.5 13,680 / 13,700 / 13,700 / 13,700 

 3.0 13,565 / 13,575 / 13,575 / 13,575 

 3.5 13,460 / 13,475 / 13,475 / 13,475 

 4.0 13,315 / 13,330 / 13,330 / 13,330 

 4.5 13,240 / 13,255 / 13,255 / 13,255 

 5.0 13,205 / 13,220 / 13,220 / 13,220 

 5.5 13,185 / 13,200 / 13,200 / 13,200 

 6.0 13,175 / 13,190 / 13,190 / 13,190 

 6.5 13,170 / 13,185 / 13,185 / 13,185 

 7.0 13,165 / 13,180 / 13,180 / 13,180 

 7.5 13,165 / 13,180 / 13,180 / 13,180 

SG 1 

Hottest SG Tube, Stress Multiplier: 1.0 13,985 

 1.5 13,660 

 2.0 13,560 

 2.5 13,440 

 3.0 13,140 

 3.5 12,880 

 4.0 12,715 

 4.5 12,620 

 5.0 12,570 

 5.5 12,550 

 6.0 12,540 

 6.5 12,535 

 7.0 12,530 

 7.5 12,530 
76

not progressed past the point where a tube will fail when subjected to a stress of only 

( 1.0 / 1.68 = ) 59.5% of the stress that would fail a non-degraded SG tube. 

The formation of a molten fuel pool is predicted near the center of the hottest core channel 

(Component 511 in Figure 3.14) starting at 14,241 s, blocking the flow in that channel. Partially 

liquefied fuel debris is also predicted to form, but not to block flow, at various locations in the 

other four core channels later during the simulation. Relocation of molten control rod absorber 

to the RV lower head is predicted, starting at 15,532 s. 

The SCDAP/RELAP5 calculation was continued beyond the predicted times of the HL, 

pressurizer surge line and SG tube structural failures until 18,000 s. Note that the calculation 

does not simulate the actual thermal-hydraulic behavior associated with opening of breaks from 

the RCS into the containment and SG secondary systems. Structural failures are predicted but 

the effects of the failures are not implemented into the thermal-hydraulic model. So the 

calculated thermal-hydraulic behavior subsequent to the time of the first structural failure does 

not reflect the impacts of that failure. Those impacts are addressed in Section 5.5. 

In summary, the final SCDAP/RELAP5 simulation of the base case SBO accident sequence in a 

Westinghouse four-loop PWR indicates positive failure margins for SG tubes carrying 

average-temperature steam and for SG tubes carrying the hottest-temperature steam. The tube 

failure margins are expressed as the stress multiplier (representing degraded structural 

strength) required for SG tube failure to occur coincident with the earliest other RCS pressure 

boundary structural failure (predicted to be Hot Leg 1, at 13,625 s). The average-tube predicted 

failure margin is 2.74 and the hottest-tube predicted failure margin is 1.68. From the 

perspective of structural failure timing, a non-degraded SG tube carrying average-temperature 

steam is predicted to fail 1,285 s after the HL fails and a non-degraded SG tube carrying the 

hottest-temperature steam is predicted to fail 360 s after the HL fails. 
77

5. KEY SENSITIVITIES 

As discussed in Section 1, the objective of this report is to coalesce the findings from current 

and prior containment bypass thermal-hydraulic evaluations into a view of the SBO severe 

accident event sequences that (1) result in containment bypass, (2) provide a potential for 

containment bypass, and (3) do not result in containment bypass. As discussed in Section 1.4, 

the criteria for judging into which category an event sequence falls are based on the 

SCDAP/RELAP5-predicted hottest SG tube failure margin. Sequences for which the hottest SG 

tube with no degradation in structural strength is predicted to fail coincident with or prior to 

another RCS component (a HL, the pressurizer surge line or the RV) are considered to fall into 

Category (1). Sequences for which the hottest SG tube has a predicted failure margin (i.e., 

stress multiplier) of between 1.0 and 3.0 are considered to fall into Category (2). Sequences for 

which the hottest SG tube has a failure margin of 3.0 or greater are considered to fall into 

Category (3). 

Prior containment bypass thermal-hydraulic analyses were reviewed and a final set of 

SCDAP/RELAP5 sensitivity analyses was developed in order to provide a comprehensive 

database permitting the categorization of all extended SBO severe accident event sequences. 

These reviews covered PRA evaluations (as documented in Reference 5.1), updated CFD 

evaluations regarding fluid mixing behavior, event-sequence definition evaluations regarding 

consistency with another ongoing containment bypass research project, and SCDAP/RELAP5 

modeling related evaluations regarding confirmation of important prior findings using the latest 

computer code and plant model. The final set of sensitivity analyses are documented in this 

section. 

Sensitivity analyses related to the expected RCP shaft seal leakage behavior are described in 

Section 5.1. Sensitivity analyses related to variations in TDAFW operation and steam leakage 

from the SG secondary systems are described in Section 5.2. Sensitivity analyses of 

opportunities for mitigative operator intervention are described in Section 5.3. An analysis of the 

sensitivity of results to variations in the subdivision of SG tubes into hot and cold tube sections 

is described in Section 5.4. Sensitivity analyses related to directly modeling the opening of 

SG tube and HL piping rupture flow paths are described in Section 5.5. 

5.1 RCP Shaft Seal Leakage Behavior

During normal plant operation, the charging system injects a cooling flow into the RCS through 

the RCP shaft seals. During SBO events, the seal injection flow is lost and the RCP shaft seals 

become a path for leakage flow from the RCS into the containment. The postulated minimum 

shaft seal leakage rate is 1.325 L/s [21 gpm] in each RCP. Additionally, failures of various shaft 

seal components may lead to larger leakage rates. Certain seal failures are expected to occur 

at about 13 minutes following the initiation of the SBO and certain other seal failures are 

expected to occur when, due to heating, the fluid in the RCP changes from liquid to steam. In 

the SBO base case accident sequence this transition from liquid to steam occurs at about 

2 hours into the event sequence, when the fluid in the RCPs reaches the saturation 

temperature. The maximum expected shaft seal leakage rate in each RCP is 30.2 L/s 

[480 gpm], assuming a worst-case combination of shaft seal failures. 

RCP shaft seal leakage behavior is important for the containment bypass issue from many 

perspectives. Larger leakage rates lead to lower RCS pressures, thereby reducing stresses on 
78

the SG tubes. Larger leak rates accelerate the loss of RCS fluid, thereby affecting event 

sequence timing, core inventory and core damage behavior. The lower RCS pressures 

associated with larger leak rates also increase the potential for the water in loop seals to clear, 

which is of key importance for containment bypass. The analyses presented here address the 

sensitivity of results to RCP shaft seal leakage. Section 5.1.1 discusses increases in the 

leakage rate at 13 minutes. Section 5.1.2 discusses increases in the leakage rate at the time 

when saturated fluid conditions are reached in the RCPs. 

5.1.1 Leakage Rate Increases Due to Seal Failures at 13 Minutes 

A series of SCDAP/RELAP5 sensitivity calculations were performed to evaluate the effects of 

the RCP shaft seal leak rate increasing above 1.325 L/s [21 gpm] per pump after 13 minutes. 

The sensitivity calculation assumptions are the same as for the base case calculation presented 

in Section 4, except for the increased shaft seal leak rates. The results from the base case and 

sensitivity calculations are listed in Table 5.1 and are summarized as follows. 

Increased leak rates result in additional cooling of the RCS, leading to less demand for SG heat 

removal, cooler SG tubes and higher SG tube failure margins. The additional RCS cooling also 

keeps the water in the loop seals cooler, which inhibits flashing and prevents the loop seals 

from clearing, even during rapid RCS depressurizations which are experienced at large 

assumed leak rates. 

The cases with leak rates of 9.464 L/s [150 gpm] and lower indicate minimum SG tube failure 

margins of less than 3.0. For these cases, whether or not containment bypass occurs depends 

upon the SG tube strength degradations and on the distribution of the inlets to the 

lowest-strength tubes relative to the location of the hot plume on the bottom surface of the 

tubesheet. 

The cases with leak rates of 11.36 L/s/pump [180 gpm] through 27.76 L/s [440 gpm] indicate 

minimum tube failure margins of greater than 3.0. These cases do not result in containment 

bypass. 

For the case with a leak rate of 30.2 L/s [480 gpm], the core is predicted to be significantly 

damaged prior to the failure of the HL or any SG tubes. This case therefore also does not result 

in containment bypass. 

A sensitivity evaluation into SCDAP/RELAP5 modeling of the RCP leaks was also performed. 

Relocating the RCP seal leak location in the model from the cold leg centerline to 

0.9906 m [39”] below the cold leg centerline (the elevation span over which RCP seal leaks may 

effectively be located) was not seen to significantly affect the overall outcome or the SG tube 

failure margins. 
79

Table 5.1 Sensitivity of Results to Increased RCP Shaft Seal Leakage After 13 Minutes 

Assumed 

Per-RCP Shaft 

Seal Leak Rate 

After 13 Minutes 

Average 

Tube 

Failure 

Margin 

Hottest 

Tube 

Failure 

Margin 

Loop 

Seals 

Cleared? 

Early 

Core 

Failure? 

Containment Bypass 

Condition Indicated? 

21 gpm 

(Base Case) No 

Leak Rate 

Increase 

2.7 1.7 No No Depends on Tube Strength 

Degradations and 

Locations 

(Minimum Margin < 3.0) 

60 gpm 

Case A-60 

2.8 1.8 No No Depends on Tube Strength 

Degradations and 

Locations 

(Minimum Margin < 3.0) 

100 gpm 

Case A-100 

3.2 2.0 No No Depends on Tube Strength 

Degradations and 

Locations 

(Minimum Margin < 3.0) 

150 gpm 

Case A-150 

4.1 3.5 No No Depends on Tube Strength 

Degradations and 

Locations 

(Minimum Margin < 3.0, 

Judgment Includes Effects of 

a Hottest Tube Modeling 

Uncertainty Specific to this 

Case) 

180 gpm 

Case A-180 

4.7 4.4 No No No 

(Minimum Margin >3.0) 

200 gpm 

Case A-200 

5.0 4.6 No No No 

(Minimum Margin >3.0) 

250 gpm 

Case A-250 

>7.5 6.9 No No No 

(Minimum Margin >3.0) 

300 gpm 

Case A-300 

>7.5 >7.5 No No No 

(Minimum Margin >3.0) 

350 gpm 

Case A-350 

>7.5 >7.5 No No No 

(Minimum Margin >3.0) 

400 gpm 

Case A-400 

>7.5 >7.5 No No No 

(Minimum Margin >3.0) 

440 gpm 

Case A-440 

>7.5 >7.5 No No No 

(Minimum Margin >3.0) 

480 gpm 

Case A-480 

(Maximum Leak 

Rate) 

>7.5 >7.5 No Yes No 

(Core Fails Prior to HL and 

Tubes) 
80

5.1.2 Leakage Rate Increases Due to Seal Failures When RCPs Experience Saturated 

Fluid Conditions 

A series of SCDAP/RELAP5 sensitivity calculations were performed to evaluate the effects of 

the RCP shaft seal leak rate increasing above 1,325 L/s [21 gpm] per pump for a first time at 

13 minutes and then for a second time when the fluid conditions in the RCPs transition from 

liquid to steam at about 2 hours into the event sequence. The sensitivity calculation 

assumptions are the same as for the base case calculation presented in Section 4, except for 

the increased shaft seal leak rates. The results from the base case and sensitivity calculations 

are listed in Table 5.2 and are summarized as follows. 

The relatively minor RCS cooling resulting from a 3.786-L/s [60-gpm] leak rate after 13 minutes 

leads to a warming of the water in the loop seals (as compared with the sensitivity cases 

described in Section 5.1.1, for which much-higher RCP leak rates are assumed to start at 

13 minutes). When the fluid conditions in the RCPs reach saturation, the shaft seal leak rate 

increases for the second time and the warm loop seal water tends to flash and clear the loop 

seals. 

The results of the sensitivity calculations show that for leak rates after the time of RCP 

saturation from 11.36 L/s [180 gpm] to 25.23 L/s [400 gpm] fluid flashing in the loop seals is not 

sufficient to clear them and a containment bypass condition does not result. For leak rates after 

the time of RCP saturation of greater than 25.23 L/s [400 gpm], however, the loop seals clear 

leading to a containment bypass condition. The judgments shown in Table 5.2 for the leakage 

range between 22.08 L/s [350 gpm] and 28.39 L/s [450 gpm] are based on the core damage 

and loop seal clearing trends seen at the lower and higher leak rates. 

The results for a case where the leak rate between 13 minutes and the time of RCP fluid 

saturation is 11.48 L/s [182 gpm] are similar to those for the case where the leak rate during that 

period is 3.786 L/s [60 gpm]. 

5.2 Effect of Variations in Turbine-Driven Auxiliary Feedwater Operation and 

SG Steam Leakage

The results from six SCDAP/RELAP5 sensitivity calculations for more-realistic event sequence 

assumptions than used in the SBO base case accident sequence are discussed here. These 

“Group E” runs were performed for three purposes: 

Evaluate the effects of TDAFW system operation on the results for key SBO 

accident event sequences. 

Reconfirm the sensitivity of SG tube failure margin results to the assumed SG 

steam leakage flow area using the final upgraded code and plant models. 

(Earlier analyses found that smaller assumed SG steam leakage flow areas 

resulted in significantly improved SG tube failure margins.) 

Evaluate the possibilities for interactions between the TDAFW operation and SG 

steam leakage flow area assumptions. 
81

Table 5.2 Sensitivity of Results to Increased Shaft Seal Leakage After Transition of RCP 

Fluid from Liquid to Steam 

Assumed Per-RCP 

Shaft Seal Leak 

Rate (gpm) 

(0 – 13 min) 

– 

(13 min – RCP Sat) 

– 

 (After RCP Sat) 

Average 

Tube 

Failure 

Margin 

Hottest 

Tube 

Failure 

Margin 

Loop 

Seals 

Cleared? 

Early 

Core 

Failure? 

Containment Bypass 

Condition Indicated? 

21 – 21 – 21, (Base 

Case, No Increases) 

2.7 1.7 No No Depends on Tube 

Strength Degradations 

and Locations 

(Minimum Margin < 3.0) 

Case C-21-60-180 >7.0 >5.0 No No No 

(Minimum Margin >3.0) 

Case C-21-60-300 >6.5 >5.0 No No No 

(Minimum Margin >3.0) 

Case C-21-60-350 >7.0 >7.0 No No No 

(Minimum Margin >3.0) 

From 21 – 60 – 350 

to 21 – 60 - 400 

>7.0 >7.0 No Yes No 

(Core Fails Prior to HL and 

Tubes) 

From 21 – 60 – 400 

to 21 - 60 - 450 

N/A N/A Yes No Yes 

Loop Seal Clears Prior to 

HL Failure or Core Damage 

Case 21-60-450 N/A N/A Yes No Yes 

Loop Seal Clears Prior to 

HL Failure or Core Damage 

Case 21-60-480 N/A N/A Yes No Yes 

Loop Seal Clears Prior to 

HL Failure or Core Damage 

Case 21–182-300 >7.5 >5.5 No No No 

(Minimum Margin >3.0) 

Results for 21-182-300 are 

similar to those for 

21-60-300 
82

The assumptions used for the Group E calculations, as well as other calculations against which 

they are compared, and the key results are listed in Table 5.3. The results from the individual 

sensitivity evaluations are summarized below. For the cases involving TDAFW system 

operation, note is made of the delay in the time of HL failure relative to the corresponding 

comparative cases where the TDAFW system was assumed not to operate. From the 

perspective of containment bypass risk, the additional time delays represent a period when 

opportunities for restoration of AC power may prove successful. 

Case E1-A (RCP Shaft Seal Leak Rate Increases to 480 gpm at 13 Minutes and TDAFW 

Operates Until Battery Depletion at 4 Hours) 

The Case E1-A assumptions are the same as for the base case except that the RCP shaft seal 

leak rate increases to 30.2 L/s [480 gpm] per pump at 13 minutes and TDAFW operates for the 

first four hours of the event sequence. The shaft seal leak rate assumptions for Case E1-A are 

the same as for Case A-480, which is described in Section 5.1.1. TDAFW is assumed to 

operate for four hours in Case E1-A whereas Case A-480 assumes no TDAFW operation. 

The key findings from Case A-480 are that: (1) the loop seals do not clear even when the 

maximum 30.2-L/s [480-gpm] leak rate starts at 13 minutes and (2) the very high leak rate 

results in early core damage and a relocation of the core to the RV lower head prior to the time 

when the HL fails. Loop seal clearing is avoided for this case because the RCS 

depressurization occurs before the water in the loop seals can be significantly warmed by the 

steam in the RCS. Early core damage and relocation occurs for this case because the core is 

quickly voided of liquid as a result of the RCS mass lost through the large RCP shaft seal leaks. 

Case E1-A was run to confirm that the key findings from Case A-480 remain valid even when 

TDAFW operation is considered. The Case E1-A results confirm those findings. Since a 

complete failure of the TDAFW system is unlikely, Case E1-A perhaps represents a 

more-realistic accident scenario than does Case A-480. 

Case E2-A (RCP Shaft Seal Leak Rate Increases to 60 gpm at 13 Minutes and Again to 

350 gpm When the RCP Fluid Temperature Reaches Saturation, TDAFW 

Operates Until Battery Depletion at 4 Hours) 

The Case E2-A assumptions are the same as for Case C-21-60-350 (which is described in 

Section 5.1.2) except that TDAFW is assumed to operate until battery depletion at 4 hours. The 

HL failure time in Case E2-A is 33,020 s whereas in Case C-21-60-350 without TDAFW 

operation the HL failure time is 13,445 s. 

The findings from Case C-21-60-350 are: (1) increasing the RCP shaft seal leak rate to 

22.08 L/s [350 gpm] when the RCP fluid saturates does not result in loop seal clearing and (2) 

the SG tube failure margins are very large. 

Case E2-A was run to confirm that the key findings from Case C-21-60-350 remain valid even 

when TDAFW operation is considered. The Case E2-A results confirm those findings. Since a 

complete failure of the TDAFW system is unlikely, Case E2-A perhaps represents a 

more-realistic accident scenario than does Case C-21-60-350. 
83

Case E2-B (RCP Shaft Seal Leak Rate Increases to 60 gpm at 13 Minutes and again to 

450 gpm When the RCP Fluid Temperature Reaches Saturation, TDAFW 

Operates Until Battery Depletion at 4 Hours) 

The Case E2-B assumptions are the same as for Case C-21-60-450 (which is described in 

Section 5.1.2) except that TDAFW is assumed to operate until battery depletion at 4 hours. The 

HL failure time in Case E2-B is 28,265 s whereas in Case C-21-60-340 without TDAFW 

operation the HL failure time is 12,995 s. 

The key finding from Case C-21-60-450 is that increasing the RCP shaft seal leak rate to 

28.39 L/s [450 gpm] when the RCP fluid saturates results in clearing of one of the loop seals 

Table 5.3 Results of Sensitivity Calculations Evaluating Variations in TDAFW System 

Operation and SG Secondary System Steam Leakage 

Case 

Number 

RCP Shaft 

Seal 

Leakage 

(gpm) 

Assumed 

per Pump 

Steam 

Leak 

Flow 

Area per 

SG (in2

) 

TDAFW 

Operation 

SG Tube 

Failure 

Margins, 

Average/ 

Hot Tubes 

Notes and Comments 

Case E1-A 480 after 13 

min 

0.5 4 hours N/A No loop seal clearing. Core 

relocates to lower head prior 

to failure of HL, SL and SG 

tubes. Compare to Case 

A-480. 

Case E2-A 21, 60 after 

13 min and 

350 after 

time of cold 

leg saturation 

0.5 4 hours N/A No loop seal clearing. HL 

fails at 33,020 s. No failures 

of average or hottest SG 

tubes predicted. Core 

relocates to lower head at 

34,889 s. Compare to Case 

C-21-60-350. 

Case E2-B 21, 60 after 

13 min and 

450 after 

time of cold 

leg saturation 

0.5 4 hours N/A No loop seal clearing. HL 

fails at 28,265 s. No failures 

of average or hottest SG 

tubes predicted. Core 

relocates to lower head at 

28,692 s. Compare to Case 

C-21-60-450. 

Case E3-A 21 0.2 None 3.41/2.09 Compare to Base Case. 

Case E3-B 21 0.5 8 hours 2.04/1.52 Compare to Base Case. 

Case E3-C 21 0.2 8 hours 2.08/1.53 Compare to Case E3-B and 

to Case E3-A. 

 

Base Case 21 0.5 None 2.74/1.68 HL fails at 13,625 s. 
84

Table 5.3 Results of Sensitivity Calculations Evaluating Variations in TDAFW System 

Operation and SG Secondary System Steam Leakage 

Case 

Number 

RCP Shaft 

Seal 

Leakage 

(gpm) 

Assumed 

per Pump 

Steam 

Leak 

Flow 

Area per 

SG (in2

) 

TDAFW 

Operation 

SG Tube 

Failure 

Margins, 

Average/ 

Hot Tubes 

Notes and Comments 

Case A-480 480 after 13 

min 

0.5 None N/A No loop seal clearing. Core 

relocates to lower head prior 

to failure of HL, SL and SG 

tubes. 

Case 

C-21-60-350 

21, 60 after 

13 min and 

350 after 

time of cold 

leg saturation 

0.5 None N/A No loop seal clearing. HL 

fails at 13,445 s. No failures 

of average SG tubes 

predicted. Core relocates to 

lower head at 14,991 s. 

Case 

C-21-60-450 

21, 60 after 

13 min and 

450 after 

time of cold 

leg saturation 

0.5 None Loop Seal 

Clearing 

Results in 

Tube 

Failure 

Prior to 

HL Failure 

or Core 

Relocation

One loop seal clears at 

12,251 s. HL fails at 

12,995 s. Core relocates to 

lower head at 14,187 s. 

prior to HL failure or core relocation. Therefore SG tube failure resulting in containment bypass 

is indicated under those event sequence assumptions. The heating of water in the loop seals 

occurring prior to the time when the RCP fluid saturates promotes fluid flashing and clearing of 

water from the loop seals when the leak rate increases to 28.39 L/s [450 gpm]. 

Case E2-B was run to evaluate the effect that TDAFW operation would have on the key finding 

from Case C-21-60-450. The Case E2-B results indicate that if TDAFW operates the loop seal 

clearing does not occur, the SG tube failure margins are very large and the containment bypass 

condition is avoided. TDAFW operation in Case E2-B is found to keep the water in the loop 

seals cooler (relative to Case C-21-60-450) such that flashing of the loop seal water is inhibited 

and the loop seals do not clear when the RCP shaft seal leak rate increases to 28.39 L/s 

[450 gpm] per pump. Additionally, operation of the TDAFW system is seen to move forward the 

time when core damage and relocation occur, although HL failure still precedes the core 

relocation. Since a complete failure of the TDAFW system is unlikely, Case E2-B perhaps 

represents a more-realistic accident scenario than does Case C-21-60-450. 

Case E3-A (0.2 in2

 per SG Steam Leakage Flow Area) 

The Case E3-A assumptions are the same as the base case except that the assumed flow area 

for steam leakage from the SGs is reduced. The purpose of the Case E3-A calculation is to 

reconfirm the findings from an evaluation described in Section 2.6 that SG tube failure margins 

are significantly improved if reduced SG steam leakage flow areas are assumed. A comparison 

of the results for the base case calculation from Section 4 and the Case E3-A calculation using 
85

the upgraded SCDAP/RELAP5 code and plant model confirm the previous finding. The 

comparison shows that reducing the steam leakage path flow area from 3.23 cm2

 [0.5 in2] to 

1.29 cm2 [0.2 in2] greatly increases the SG tube failure margins. 

Case E3-B (TDAFW Operates Until Battery Depletion at 8 Hours) 

The purpose of the Case E3-B calculation is to evaluate the effects of the TDAFW system 

operating temporarily for 8 hours on the SG tube failure margins under event-sequence 

assumptions that are otherwise the same as for the base case. The HL failure time in 

Case E3-B is 33,020 s whereas in the base case calculation without TDAFW operation the HL 

failure time is 13,625 s. 

The results from the base case and Case E3-B calculations indicate that temporary TDAFW 

operation reduces the SG tube failure margins. 

The heat-up of the RCS system occurs much later in the event sequence when TDAFW 

operates for eight hours than when it does not. The core decay power during the heat-up period 

is therefore much lower and the RCS heat-up rate is correspondingly slower. A slower heat-up 

rate reduces SG tube failure margins because the time constants involved with transporting 

heat from the RV into the SGs are less effective at delaying the SG tube heat-up (relative to the 

HL heat-up) than is the case at a faster heat-up rate. In other words, at a slow heat-up rate the 

inherent delays in transporting the heat into the SGs do not buffer the SG tubes from the effects 

of the increasing temperatures as well as they do when the heat-up rate is fast. 

Case E3-C (0.2 in2

 per SG Steam Leakage Flow Area, TDAFW Operates Until Battery 

Depletion at 8 Hours) 

The Case E3-C assumptions are the same as for the base case except that the flow area for SG 

steam leakage is reduced and TDAFW is assumed to operate until the time of battery depletion 

at 8 hours. The purpose of Case E3-C is to evaluate together the effects of reduced SG steam 

leakage and temporary TDAFW operation. 

Comparing the failure margin results in Table 5.3 for Cases E3-C and E3-B, it is observed that 

when TDAFW operates only a small benefit results from the reduced SG steam leakage flow 

area. This result contrasts with the much-larger tube failure margin benefit seen for the same 

reduction in SG steam leakage flow when the TDAFW system does not operate (see margins 

for the base case and Case E3-A). 

Comparing the results in Table 5.3 for Case E3-C and Case E3-A (1.29 cm2

 [0.2 in2] SG steam 

leakage in both cases) it is seen that the margin reduction resulting from temporary TDAFW 

operation is similar to that seen between the base case and Case E3-B (1.29 cm2 [0.5 in2] SG 

steam leakage in both cases). The HL failure time in Case E2-C is 54,540 s whereas in 

Case E3-A without TDAFW operation the HL failure time is 13,950 s. 

Comparisons among the results for the base case, Case E3-A, Case E3-B and Case E3-C in 

Table 5.3 indicate that the SG steam leakage assumption has considerable influence on the SG 

tube failure margins for sequences with no TDAFW operation and very little influence on the SG 

tube failure margins for sequences with temporary TDAFW operation. The conclusion is 

therefore that event-sequence assumptions related to temporary TDAFW operation (which 

directly affect the differential heat-up behavior between the SG and HL) have more influence on 

the analysis outcome than do the assumptions related to SG steam leakage. 
86

5.3 Mitigative Operator Intervention

The effectiveness of two operator intervention strategies for mitigating the consequences of 

extended SBO accident events effects were evaluated. 

In the first strategy, the operators implement SG feed-and-bleed cooling by using the 

turbine-driven auxiliary feedwater (TDAFW) system and opening the SG PORVs to 

depressurize the SGs at 30 minutes into the event sequence. An evaluation of this pre-core 

damage strategy is presented in Section 5.3.1. 

In the second strategy, the operators depressurize the RCS by opening the pressurizer PORVs 

after plant instrumentation has indicated that the core damage process is underway. An 

evaluation of this post-core damage strategy is presented in Section 5.3.2. 

Both operator intervention strategies require that action be taken prior to the time when the 

station batteries have been depleted. Afterward, operator control over PORVs on the 

secondary and primary coolant systems is lost and ability to deliver or control TDAFW may also 

be lost. 

5.3.1 Pre-Core Damage Operator Action 

Five SCDAP/RELAP5 sensitivity calculations were performed to evaluate the effectiveness of 

pre-core damage mitigative operator intervention. This intervention strategy assumes that the 

TDAFW system is operable. (This assumption is not included in the base case event sequence, 

but consideration that the TDAFW system operates, at least initially, may represent a 

more-realistic assumption.) The pre-core damage intervention strategy is based on SG 

secondary feed-and-bleed cooling in which cold TDAFW enters the SGs and the operators open 

the SG PORVs to depressurize and bleed steam from the SG secondary system at 30 minutes 

into the SBO event sequence. Issues affecting the timing of the operator intervention include 

the life of the station batteries and the available water inventory in the condensate storage tank 

(CST). Operator control over the SG PORVs and pressurizer PORVs is lost when the battery 

power is depleted, and the ability to deliver or control TDAFW may also be affected. The initial 

CST inventory is immediately available as a water source for TDAFW system, but after it is 

depleted another source of water would need to be available for the TDAFW system to continue 

operating. 

The five calculations performed and the results obtained are listed in Table 5.4 along with the 

corresponding information for the base case calculation from Section 4, which assumes neither 

TDAFW operation nor operator intervention. Of particular note in the table is that TDAFW 

operation results in slight reductions in the SG tube failure margins but also significant delays in 

the time of HL failure relative to the base case event sequence. From the perspective of 

containment bypass risk, the additional time delays represent a period when opportunities for 

restoration of AC power may prove successful. Results for the individual sensitivity cases are 

summarized here, followed by conclusions regarding the effectiveness of pre-core damage 

operator intervention. 
87

Case 153 (SG Depressurization at 30 Minutes, 4-Hour Battery Life, and TDAFW Stops 

When Batteries are Depleted) 

Case 153 investigates the effects of the operators: (1) depressurizing the SGs at 30 minutes 

into the SBO event sequence and (2) controlling the delivery of TDAFW to the SGs until four 

hours, when the station batteries are assumed to be depleted. The Case 153 event sequence 

assumptions related to the SG depressurization and TDAFW operation are based on the Zion 

plant procedures, which are described as follows: 

The operators are assumed to open the SG PORVs on all four SGs at 30 

minutes (with additional requirements that in order to do so the SGs must have 

narrow range levels above 5% and the RCS average temperature must be above 

138°C [280°F]). The operators are assumed to close the SG PORVs when the 

SG pressures have fallen to 1.86 MPa [270 psia], and afterward are assumed to 

control the SG PORVs to maintain the SG pressures between 1.93 and 2.0 MPa 

[280 and 290 psia]. The SG PORVs are assumed to become inoperative and fail 

closed at four hours, when the batteries are depleted. 

A single TDAFW pump, with a total capacity of 56.8 L/s [900 gpm], is assumed to 

be operating and the flow available for delivery to each of the four SGs is 

14.2 L/s [225 gpm]. It is assumed that the operators throttle the TDAFW flows to 

maintain normal SG levels. The TDAFW is assumed to be drawn from a 

567,812 L [150,000 gallon] CST. The TDAFW system is assumed to fail when 

the entire CST inventory has been injected into the SGs or when the batteries 

are assumed to fail at four hours, whichever occurs first. 

The results of the SCDAP/RELAP5 simulation for Case 153 are described as follows. The SG 

pressure responses are shown in Figure 5.1. The operators open the SG PORVs at 

30 minutes. The SG pressures quickly fall to 1.86 MPa [270 psia] and the throttling of the SG 

PORVs to control the SG pressures between 1.93 and 2.0 MPa [280 and 290 psia] begins. 

With the SG PORVs fully open, it takes only ~1,000 s for the SG pressures to reach 1.86 MPa 

[270 psia]; the effective RCS cooldown rate associated with this process is ~265°C/hr 

[~477°F/hr]. 

Figure 5.2 shows that the SG depressurization causes a significant loss of secondary-side mass 

inventory and that the delivery of TDAFW replenishes the lost inventory. When the TDAFW flow 

stops, a boil-off of the SG inventory begins and by ~35,000 s the SGs have boiled dry. In 

Case 153 a total of 281,468 L [74,356 gal] of AFW, less than 50% of the CST inventory, is 

delivered to the SGs before the TDAFW system stops operating at four hours. 

Figure 5.3 shows the RCS pressure response; the RCS depressurization is deeper than seen 

for the base case in Figure 4.1 because of the additional RCS cooling caused by the SG 

depressurization. The RCS pressure falls below the initial accumulator pressure (4.24 MPa 

[615 psia]) at 7,550 s and the accumulators inject water into the RCS until 14,688 s. About 17% 

of the initial accumulator water inventory is expelled into the RCS over this period. No 

accumulator injection is indicated in the base case run. 

When the TDAFW flow stops the fluids in the SGs and RCS begin heating up and this causes 

the SG and RCS pressures to start rising. After the SGs have boiled dry, there is no longer 

liquid in the SGs to convert to steam and the flows through the steam valve leakage paths 

cause the SG pressures to decline. On the primary side however, the continuing heat-up 
88

Table 5.4 Results of Sensitivity Calculations Evaluating Pre-Core Damage Mitigative 

Operator Intervention 

Case 

No. Case Description 

HL Failure 

Time 

(s) 

Stress Multiplier for 

Average SG Tube 

Failure Coincident 

with HL Failure 

Stress Multiplier for 

Hottest SG Tube 

Failure Coincident 

with HL Failure 

69 Base case 13,625 2.74 1.68 

153 

SGs depressurized at 30 min 

using Zion procedures, TDAFW 

runs to 4 hr 

47,565 2.05 1.47 

153A 

SGs depressurized at 30 min 

using Surry procedures, 

TDAFW runs to 4 hr 

53,645 2.00 1.44 

161 

SGs depressurized at 30 min 

using Zion procedures, TDAFW 

runs to 8 hr 

67,120 1.89 1.31 

161m 

SGs depressurized at 30 min 

using Zion procedures, station 

batteries depleted at 8 hr, 

TDAFW runs until condensate 

storage tank depletion 

93,085 1.96 1.53 

165m 

RCP leakage increases to 

3.79 L/s·[60 gpm] per pump at 

13 min, SGs depressurized at 

30 min using Zion procedures, 

station batteries depleted at 

8 hr, TDAFW runs until 

condensate storage tank 

depletion 

93,180 2.56 2.23 

causes the RCS pressure to increase to the pressurizer SRV opening setpoint pressure. 

Afterward, the cycling of the pressurizer SRVs prevents further increases in the RCS pressure. 

The pressurizer PORVs (which have a lower opening setpoint pressure than the pressurizer 

SRVs) are assumed to not be operable after battery depletion at four hours. 

The RCS and SG behavior seen for Case 153 are very similar to that seen for the base case 

event sequence, except that the event timing has been significantly extended as a result of the 

SG depressurization and TDAFW system operation. For Case 153, the first predicted creep 

rupture failure is Hot Leg 1 at 47,565 s, which is 33,940 s [9.4 hr] later than seen for the base 

case. 

For Case 153 the tube failure margins are 2.05 for the average tube (compared with 2.74 in the 

base case) and 1.47 for the hottest tube (compared with 1.68 in the base case). It is therefore 

concluded that SG depressurization at 30 minutes and TDAFW operation for the first four hours 

(followed by TDAFW failure) results in lower SG tube failure margins than if the SGs are not 

depressurized and TDAFW never operates. The primary cause for the reduced SG tube failure 

margins is related to the core decay power at the time when the RCS experiences the heat-up. 

In Case 153, the heat-up is encountered 9.4 hours later than in the base case and as a result 
89

the core decay power is much lower and the RCS heat-up is much slower than in the base 

case. As the heat-up rate declines the tube failure margins also decline because the time lag 

for heat to be passed from the reactor vessel into the SGs becomes less effective at slowing the 

rate of tube temperature increase relative to the rate of HL temperature increase. This time lag 

is related to the HL and SG tube circulation rates, which are determined by the target hot leg 

discharge coefficient and target SG recirculation ratio and which are the same, regardless of the 

RCS heat-up rate. 

0 10000 20000 30000 40000 50000 60000

Time (s)

0.0

2.0

4.0

6.0

8.0

Pressure (MPa)

p−18001 (SG 1) 

p−28001 (SG 2)

0 10000 20000 30000 40000 50000 60000

0

290

580

870

1160

Pressure (psia)

Figure 5.1 Case 153 SG Secondary Pressures 
90

0 10000 20000 30000 40000 50000 60000

Time (s)

0

10000

20000

30000

40000

50000

Mass (kg)

cntrlvar−1015 (SG 1) 

cntrlvar−2015 (SG 2) 

0 10000 20000 30000 40000 50000 60000

0

22046

44092

66139

88185

110231

Mass (lbm)

Figure 5.2 Case 153 SG Water Masses 

0 10000 20000 30000 40000 50000 60000

Time (s)

0.0

5.0

10.0

15.0

20.0

Pressure (MPa)

p−15006 (Pressurizer) 

0 10000 20000 30000 40000 50000 60000

0

725

1450

2176

2901

Pressure (psia)

Figure 5.3 Case 153 RCS Pressure 
91

Case 153A (Evaluation of Plant-Specific Assumptions for the SG Depressurization)

Case 153, described above, assumes that the operators depressurize the SGs by opening the 

SG PORVs at 30 minutes, leave them open until the SG pressures decline to 1.86 MPa 

[270 psia], and afterward control the SG PORVs to maintain the SG pressures between 1.93 

and 2.0 MPa [280 and 290 psia]. These Zion plant procedures result in an effective RCS 

cooldown rate of ~265°C/hr [~477°F/hr]. 

Case 153A evaluates the effects of changing the operator action procedure for the SG 

depressurization to those for the Surry plant as provided in Reference 5.2. For Surry, the 

operators are assumed to manually control the SG PORVs to maintain a 55.6°C/hr [100°F/hr] 

cooldown rate and to stop the depressurization when the SG pressures reach 0.827 MPa 

[120 psia]. The Case 153A event sequence is therefore the same as Case 153, except that the 

SG depressurization implemented by the operators is much slower. 

Figures 5.4, 5.5 and 5.6 show the Case 153A SG pressures, SG masses and RCS pressure 

responses. The responses for Case 153A are seen to be very similar to those for Case 153, 

except because of the slower depressurization the event sequence timing for Case 153A is 

extended by ~5,000 s [~1.4 hr]. This much additional time is needed in Case 153A to deplete 

the SG secondary inventory, fully depressurize the SGs and heat up the RCS. The HL failure is 

experienced at 53,645 s in Case 153A, compared with 47,565 s in Case 153. Even though the 

SG and RCS cooldown rates are lower, the depressurization of the SGs to the lower pressure in 

Case 153A results in a greater depressurization of the RCS and more accumulator injection. 

For Case 153A the tube failure margins are 2.00 for the average tube (compared with 2.05 for 

Case 153) and 1.44 for the hottest tube (compared with 1.47 for Case 153). The small margin 

reductions seen from Case 153 to Case 153A, in which the sequence timing is delayed by 

~5,000 s [~1.4 hr], are consistent with the finding that extending the event sequence timing 

reduces the margins. However no significant differences are noted between the results from the 

two cases and therefore it is concluded that the impact of using the Surry procedures rather 

than the Zion procedures for the SG depressurization is small. On that basis, the remaining 

analyses in this section are completed using only the Zion SG depressurization procedures. 

Case 161 (SG Depressurization at 30 Minutes, 8-Hour Battery Life and TDAFW Stops 

When Batteries are Depleted)

Case 161 evaluates the effects of operator actions: (1) depressurizing the SGs 30 minutes into 

the SBO event sequence and (2) controlling the delivery of TDAFW to the SGs until eight hours, 

when the station batteries are assumed to be depleted. This case is identical to Case 153 

except that the battery life is increased from four hours to eight hours. 

When the TDAFW flow stops, a boil-off of the SG inventory begins and by ~51,500 s the SGs 

have boiled dry. In Case 161 a total of 408,052 L [107,796 gal] of AFW, about 72% of the CST 

inventory, is delivered to the SGs before the TDAFW system stopped operating. 
92

0 10000 20000 30000 40000 50000 60000

Time (s)

0.0

2.0

4.0

6.0

8.0

Pressure (MPa)

p−18001 (SG 1) 

p−28001 (SG 2)

0 10000 20000 30000 40000 50000 60000

0

290

580

870

1160

Pressure (psia)

Figure 5.4 Case 153A SG Pressures 

0 10000 20000 30000 40000 50000 60000

Time (s)

0

10000

20000

30000

40000

50000

Mass (kg)

cntrlvar−1015 (SG 1) 

cntrlvar−2015 (SG 2) 

0 10000 20000 30000 40000 50000 60000

0

22046

44092

66139

88185

110231

Mass (lbm)

Figure 5.5 Case 153A SG Water Masses 
93

0 10000 20000 30000 40000 50000 60000

Time (s)

0.0

5.0

10.0

15.0

20.0

Pressure (MPa)

p−15006 (Pressurizer) 

0 10000 20000 30000 40000 50000 60000

0

725

1450

2176

2901

Pressure (psia)

Figure 5.6 Case 153A RCS Pressure 

Figure 5.7 shows the RCS pressure response for Case 161. The minimum RCS pressure is 

somewhat lower for Case 161 than for Case 153 because of the additional RCS cooling 

resulting from the longer TDAFW system operation and the longer period over which the SGs 

are maintained at low pressure. In Case 161, the RCS pressure falls below the initial 

accumulator pressure (4.24 MPa [615 psia]) at 7,555 s and the accumulators inject water into 

the RCS until 28,560 s. About 59% of the initial accumulator water inventory is expelled into the 

RCS over this period. 

When the TDAFW flow stops the fluids in the SGs and RCS begin heating up, and this causes 

the SG and RCS pressures to begin rising. After the SGs boil dry, there is no longer liquid in 

the SGs to convert to steam and the flows through the steam valve leakage paths cause the SG 

pressures to decline, as shown in Figure 5.8. On the primary side however, the continuing 

heat-up causes the RCS pressure to increase to the pressurizer SRV opening setpoint 

pressure. Afterward, the cycling of the pressurizer SRVs prevents further increases in the RCS 

pressure. The pressurizer PORVs (which have a lower opening setpoint pressure than the 

pressurizer SRVs) are assumed to not be operable after battery depletion at eight hours. 

For Case 161, the first predicted creep rupture failure is Hot Leg 1 at 67,120 s, which is 

19,555 s [5.4 hours] later than seen for Case 153. The Case 161 SG tube failure margins are 

1.89 for the average tube (compared with 2.05 in Case 153) and 1.31 for the hottest tube 

(compared with 1.47 in Case 153). 

The primary cause for the lower SG tube failure margins in Case 161 is related to the lower core 

decay power at the time when the RCS encounters the heat-up. In Case 161, the heat-up is 

experienced 5.4 hours later than in Case 153 and as a result the core decay power is lower and 

the RCS heat-up is slower than in Case 153. 
94

It is concluded that SG depressurization at 30 minutes and TDAFW operation for the first eight 

hours (followed by TDAFW failure) results in lower SG tube failure margins than if the TDAFW 

had instead operated only for four hours. 

Case 161m (SG Depressurization at 30 Minutes, 8-Hour Battery Life and TDAFW 

Continues Running Until Condensate Storage Tank Depletion)

Case 161m is used to evaluate the effects of operator actions: (1) depressurizing the SGs 

30 minutes following the start of the SBO event sequence and (2) controlling the delivery of 

TDAFW to the SGs until the CST has been depleted of water. The sequence assumes an 

eight-hour battery life; afterward the pressurizer PORVs and SG PORVs are inoperable. This 

case is identical to Case 161 except that TDAFW runs past the time when the station batteries 

are depleted until the CST empties, which occurs at 54,890 s [15.3 hours]. After the TDAFW 

flow stops the SG inventories are boiled off, followed by heat-up and pressurization of the RCS 

and SG systems. The continuation of the TDAFW operation from eight hours to 15.3 hours in 

Case 161m retards the SG pressurization and delays the heat-up relative to Case 161. The 

Case 161m HL failure occurs at 93,085 s [25.9 hours]; for Case 161 the HL failed 25,965 s 

[7.21-hours] earlier than that. 

For Case 161m the tube failure margins are 1.96 for the average tube (compared with 1.89 in 

Case 161) and 1.53 for the hottest tube (compared with 1.31 in Case 161). The tube failure 

margin comparisons between the two cases are the opposite of what was expected given the 

trends seen in the other comparisons among the other cases. Those trends suggest that 

continuing the TDAFW system operation longer prior to its failure results in reduced failure 

margins. Yet, the margins calculated for Case 161m (for which the TDAFW system runs 

7.3 hours longer than in Case 161) are increased, not reduced, relative to Case 161. 

The cause for this difference was found to be related to the operation of SG PORVs, which are 

assumed to fail closed at eight hours in both cases. A separate run, Case 161mA, was made in 

which Case 161m was repeated except that the SG PORVs were allowed to continue operating 

along with the TDAFW system after eight hours and up to the time of CST depletion. The 

Case 161mA run indicated that the HL failure occurs 460 s later than in Case 161m and also 

showed the expected tube failure margin reduction (in comparison with the Case 161). 

Figure 5.9 compares the HL temperatures between Case 161m and Case 161mA. After eight 

hours, the HL temperatures are lower for Case 161mA where the SG PORVs continue 

operating, than for Case 161m where they do not. This result is expected because of the better 

cooling of the RCS provided by continued operation of the SG PORVs in Case 161mA. 

However, the lower HL temperatures in Case 161mA should result in an increased, not reduced 

SG, tube failure margin. 
95

0 20000 40000 60000 80000

Time (s)

0.0

5.0

10.0

15.0

20.0

Pressure (MPa)

p−15006 (Pressurizer) 

0 20000 40000 60000 80000

0

725

1450

2176

2901

Pressure (psia)

Figure 5.7 Case 161 RCS Pressure 

0 20000 40000 60000 80000

Time (s)

0.0

2.0

4.0

6.0

8.0

Pressure (MPa)

p−18001 (SG 1) 

p−28001 (SG 2)

0 20000 40000 60000 80000

0

290

580

870

1160

Pressure (psia)

Figure 5.8 Case 161 SG Secondary Pressures 
96

Figure 5.10 compares the RCS pressures between Case 161m and Case 161mA. This figure 

shows that at eight hours the RCS pressure in Case 161m immediately begins increasing but in 

Case 161mA the RCS pressure continues declining until the SG PORV operation is finally 

stopped when the CST empties at 54,890 s [15.3 hours]. The continuation of the RCS 

depressurization in Case 161mA is caused by heat removal to the SGs resulting from operation 

of the SG PORVs. Since at eight hours the RCS pressure is below the accumulator pressure, 

the continuing RCS pressure decline in Case 161mA results in additional accumulator injection 

into the RCS in comparison to Case 161m. When the RCS heat-up is eventually encountered, 

the additional RCS inventory in Case 161mA leads to higher RCS pressures, which persist into 

the period, at ~93,300 s [~25.9 hours], when the HL failures are encountered in both cases. 

The reduced failure margin seen in Case 161mA (in comparison with Case 161m) is therefore 

caused by the higher RCS pressures that result from continuing the operation of the SG PORVs 

past the time of station battery depletion. 

The conclusion drawn from the analysis of Case 161m is that continuing the TDAFW system 

operation past the time of battery depletion (when the pressurizer PORVs and SG PORVs 

cease operating) improves the SG tube failure margins. 

Case 165m (RCP Shaft Seal Leakage Increased to 60 gpm/pump at 13 Minutes, SG 

Depressurization at 30 Minutes, 8-Hour Battery Life and TDAFW Continues 

Running Until Condensate Storage Tank Depletion)

Case 165m assumes that the RCP shaft seal leakage rate increases from 1.32 L/s [21 gpm] to 

3.77 L/s·[60 gpm] per pump at 13 minutes and is used to evaluate the effects of operator 

actions: (1) depressurizing the SGs 30 minutes into the SBO event sequence and (2) controlling 

the delivery of TDAFW to the SGs until the CST has been depleted of water. The sequence 

assumes an eight-hour battery life; afterward the pressurizer PORVs and SG PORVs are 

inoperable. This case is identical to Case 161m except for the increased RCP shaft seal 

leakage rate. 

The results of the SCDAP/RELAP5 run for Case 165m are described as follows. Figure 5.11 

compares the RCS pressure responses for Cases 165m and 161m. The RCS depressurization 

seen during the SG depressurization period is deeper for Case 165m because of the additional 

RCS cooling afforded the RCS by the higher RCP shaft seal leakage rate. The RCS pressure 

falls below the initial accumulator pressure (4.24 MPa [615 psia]) at 3,161 s [0.88 hr] in 

Case 165m and the accumulators inject water into the RCS until 28,659 s [7.96 hr]. About 60% 

of the initial accumulator water inventory is expelled into the RCS over this period (this value 

compares with about 41% for Case 161m). 

The TDAFW system continues to operate until the CST empties, which occurs at 55,550 s 

[15.4 hours]. This time is 660 s later for Case 165m than for Case 161m. The additional RCS 

cooling afforded by the greater RCP shaft seal leakage in Case 165m reduces the demand for 

AFW, moderately extending the CST depletion time. 

The Case 165m HL failure occurs at 93,180 s [25.88 hours]. This is only 95 s different from the 

time when the HL fails in Case 161m. For Case 165m the tube failure margins are 2.56 for the 

average tube (compared with 1.96 for Case 161m) and 2.23 for the hottest tube (compared with 

1.53 for Case 161m). As the RCS and SG systems heat up and the conditions leading to HL 

failure are approached, the lower RCS pressure resulting from the higher RCP shaft seal 

leakage rate in Case 165m reduces the stresses on the SG tubes compared with Case 161m, 

where the RCS remains at a high pressure. At the times of the respective HL failures, the RCS 
97

pressure is 3.88 MPa [563 psi] lower in Case 165m than in Case 161m. However by the times 

of the HL failures the SGs in both cases have been completely depressurized, as shown in 

Figure 5.12, and the SG pressures for the two cases differ by only 68 Pa [0.01 psi]. As a result 

of the lower RCS pressure, the SG tube failure margins for Case 165m are higher than for 

Case 161m. 

The conclusion drawn from the comparative analysis of Case 165m and Case 161m is that the 

modest 2.46 L/s [39 gpm] per pump increase in the RCP seal leakage rate significantly 

improves the SG tube failure margins. The margin gained from the higher RCP seal leakage 

rate is seen to be much larger than the margin lost as a result of continuing TDAFW system 

operation past the time of the station battery depletion. 
98

0 20000 40000 60000 80000 1e+05

Time (s)

0

500

1000

1500

2000

Temperature (K)

tempg−10001 (Case 161m) 

tempg−10001 (Case 161mA)

0 20000 40000 60000 80000 1e+05

−460

440

1340

2240

3140

Temperature (F)

Figure 5.9 Case 161m and Case 161mA HL Vapor Temperatures 

0 20000 40000 60000 80000 1e+05

Time (s)

0.0

5.0

10.0

15.0

20.0

Pressure (MPa)

p−15006 (Case 161m) 

p−15006 (Case 161)

0 20000 40000 60000 80000 1e+05

0

725

1450

2176

2901

Pressure (psia)

Figure 5.10 Case 161m and Case 161mA RCS Pressures 
99

0 20000 40000 60000 80000 1e+05

Time (s)

0.0

5.0

10.0

15.0

20.0

Pressure (MPa)

p−15006 (Case 165m) 

p−15006 (Case 161m)

0 20000 40000 60000 80000 1e+05

0

725

1450

2176

2901

Pressure (psia)

Figure 5.11 Case 165m and Case 161m RCS Pressures 

0 20000 40000 60000 80000 1e+05

Time (s)

0.0

2.0

4.0

6.0

8.0

Pressure (MPa)

p−28001 (Case 165m) 

p−28001 (Case 161m)

0 20000 40000 60000 80000 1e+05

0

290

580

870

1160

Pressure (psia)

Figure 5.12 Case 165m and Case 161m SG 2 Pressures 
100

Summary of the Effectiveness of Pre-Core Damage Mitigative Operator Intervention

The pre-core damage operator intervention strategy (feeding the SGs with TDAFW and 

bleeding steam from the SGs through the SG PORVs at 30 minutes into the SBO event 

sequence) is seen to be effective in the short term for removing core decay heat and preventing 

an RCS heat-up that could lead to containment bypass. At a minimum, this strategy 

significantly delays the onset of an RCS heat-up, thereby providing time for other plant recovery 

opportunities to be considered and implemented. 

In the long term, the SG PORVs fail closed and the ability to deliver or control TDAFW may be 

lost after the station battery power has been depleted. Additionally, a means of replenishing the 

CST water inventory or aligning a separate water source for the TDAFW system is needed. To 

be successful in the long term, the pre-core damage operator intervention strategy requires that 

a TDAFW water source remain available and that some capability to deliver the water into the 

SGs continues. 

For the event sequences analyzed with assumptions that lead to an RCS heat-up in the long 

term, no large changes in SG tube failure margins (relative to the corresponding no-operator 

intervention cases) were seen to result from implementing the pre-core damage operator 

intervention strategies. Depending upon the operator intervention procedure, the assumed life 

of the station batteries and assumptions regarding operation of the TDAFW system, both minor 

increases and minor decreases in SG tube failure margins may be experienced relative to the 

no-operator intervention cases. For the purpose aiding future evaluations of pre-core damage 

operator intervention, the following minor parametric sensitivities are identified: 

The combination of the operators depressurizing the SGs at 30 minutes and 

TDAFW system operation until the time of battery depletion at four hours is seen 

to result in reductions in the SG tube failure margins compared with the base 

case (which assumed neither SG depressurization nor TDAFW operation). The 

primary cause for the margin reduction is related to the time when the RCS 

heat-up is experienced. A later heat-up is slower as a result of reduced core 

decay power. As the heat-up rate declines the SG tube failure margins also 

decline because the time lag for heat to be passed from the RV into the SGs 

becomes less effective at slowing the rate of tube temperature increase relative 

to the rate of HL temperature increase. 

For the same reason, SG tube failure margin reductions are seen for cases 

where the heat-up is experienced later because the TDAFW system is assumed 

to operate longer. 

An evaluation of the effect of varying the SG depressurization rate allowed during 

the operator intervention indicated no significant sensitivity of results to that 

parameter. 

Continuing the TDAFW system operation past the time of battery depletion (when 

the pressurizer PORVs and SG PORVs cease operating) and until the time when 

the CST water inventory is depleted moderately improves the SG tube failure 

margins. 
101

A modest 2.46 L/s·[39 gpm] per pump increase in the RCP seal leakage rate 

improves the SG tube failure margins. The improvement so gained is seen to be 

larger than the SG tube failure margin lost as a result of continuing the TDAFW 

system operation past the time of the station battery depletion. 

5.3.2 Post-Core Damage Operator Action 

Four SCDAP/RELAP5 sensitivity calculations were performed to evaluate the effectiveness of 

mitigative operator intervention to depressurize the RCS by opening pressurizer PORVs once 

the plant instrumentation has provided an indication that core damage is in progress. The 

calculations performed and the results obtained are listed in Table 5.5 along with the 

corresponding information for the base case calculation from Section 4, which assumed no 

operator intervention. 

The sensitivity-case assumptions are the same as for the base case except that the operators 

take action by opening one or two pressurizer PORVs. In the model, two PORVs are 

represented, each with a saturated steam flow capacity of 26.5 kg/s [210,000 lbm/hr] at 

16.2 MPa [2,350 psia]. (A survey of Westinghouse plants indicates that this valve flow capacity 

is typical, with some plants employing two PORVs and others employing three PORVs. Another 

potential plant-to-plant variation regards the period that PORVs remain operable, depending on 

whether they are air-operated or electric-operated.) The operators are assumed to take action 

either at the time when the core exit temperature reaches 922 K [1,200°F], or 12 minutes after 

that time. A high core-exit temperature is an indicator that the core has been uncovered, 

causing superheated steam to flow from the top of the core, and that core damage is in process. 

The 12-minute delay reflects an estimate of the additional time required for the Technical 

Support Center to analyze the plant data and to agree that PORVs should be opened. The 

base case and all four of the sensitivity case event sequences assume a four-hour station 

battery depletion time. After that time the pressurizer PORVs and SG PORVs are assumed to 

fail closed, their automatic functions are assumed to be inoperative and operator control over 

the valves is assumed to be lost. The results of the post-core damage operator intervention 

calculations are summarized as follows. 

For the one-PORV cases the HL fails before battery depletion. The RCS cooling afforded by 

opening only one pressurizer PORV is limited. The core fails early, with damaged fuel starting 

to block the core flow at about the time that the HL is predicted to fail. The core heat therefore 

goes into melting the core and not into the SGs, resulting in very large SG tube failure margins. 

No containment bypass is indicated for the one-PORV cases. 

For the two-PORV cases the HL fails after battery depletion. The greater RCS cooling afforded 

by opening two pressurizer PORVs rapidly depressurizes the RCS and also prevents early core 

damage. The low RCS pressure reduces the stresses on the HL and SG tube structures, 

significantly delaying their failures. When the pressurizer PORVs fail closed after battery 

depletion, the RCS begins re-pressurizing and re-heating and this subsequently leads to HL and 

SG tube failures. The SG tube failure margins are seen to improve relative to the base case as 

a result of the pressurizer PORVs having been open. During the period when PORVs are open, 

the primary flow of hot steam from the core and out of the RCS through the pressurizer PORVs 

passes through the pressurizer-loop HL, keeping its structure temperature elevated. However, 

during this period, flows through the SGs stagnate, allowing the SG tubes to significantly cool
102

Table 5.5 Results of Sensitivity Calculations Evaluating Post-Core Damage Mitigative 

Operator Intervention 

Assumed 

Operator Actions 

Average 

Tube 

Failure 

Margin 

Hottest 

Tube 

Failure 

Margin 

Loop 

Seals 

Cleared? 

Early 

Core 

Failure? 

Containment Bypass 

Condition Indicated? 

None (Base Case) 2.7 1.7 No No Depends on Tube Strength 

Degradations and Locations 

(Minimum Margin < 3.0) 

1 Pressurizer 

PORV Opened 

When Core Exit 

Temperature 

Reaches 1,200°F 

>7.5 >7.5 No Yes No 

(Core Fails at About Same 

Time as the Hot Leg) 

1 Pressurizer 

PORV Opened 

12 Minutes After 

Core Exit 

Temperature 

Reaches 1,200°F 

>7.5 >7.5 No Yes No 

(Core Fails at About Same 

Time as the Hot Leg) 

2 Pressurizer 

PORVs Opened 

When Core Exit 

Temperature 

Reaches 1,200°F 

4.6 4.1 No No No 

(Minimum Margin >3.0) 

2 Pressurizer 

PORVs Opened 

12 Minutes After 

Core Exit 

Temperature 

Reaches 1,200°F 

3.2 2.9 No No Marginally No 

(Minimum Margin ~3.0) 

down. After the PORVs fail close and the RCS begins to heat-up again, the difference in the HL 

and tube temperatures at the start of the re-heat process causes the HL failure conditions to be 

reached earlier (with respect to the SG tube failure conditions) than is seen in the base case 

run, which assumed no operator intervention. Because the minimum SG tube failure margins 

are ~3 or higher, no containment bypass is indicated for the two-PORV cases. As shown 

Table 5.5, this judgment is marginal for the two-PORV case with the 12-minute delay. 

The finding that opening only one pressurizer PORV looks to be more effective at preventing 

containment bypass than opening two pressurizer PORVs is counter-intuitive. Opening only 

one PORV is not sufficient to prevent the rapid progression of core damage, fuel melting and 

core flow blockage. Containment bypass is therefore avoided when opening one PORV 

because of early core damage and core flow blockage. Opening two PORVs prevents the rapid 

core-damage progression, but as a result the challenges to the integrity of the HL and SG tube 

structures persist. Compared with opening only one PORV, opening two PORVs provides an 

advantage in that additional time becomes available during which recovery of plant systems (for 
103

example, restoration of AC power or arrangement of some source of auxiliary feedwater) could 

prove effective in preventing failure of the core, the HLs and the SG tubes. 

In summary, all four of the post-core damage operator interventions evaluated are shown to be 

effective at preventing containment bypass. 

5.4 Sensitivity of Results to Assumed Split of SG Tubes into Hot and Cold 

Sections

The SBO base case calculation in Section 4 assumes that 10% of the tubes in each SG are 

blocked and that the SG tubes are split into hot and cold tube sections representing 41% and 

59%, respectively, of the remaining unblocked SG tubes. 

The most recent CFD evaluations (Reference 3.14) indicate that a 30%/70% tube split is within 

the range of possibilities for some periods of the transient. Employing fewer tubes in the hot 

tube section results in the same mass flow of hot steam passing through a smaller number of 

tubes, thereby increasing the SG tube heating rate and reducing tube failure margins. 

To evaluate the effects of this worst-case tube split assumption, a SCDAP/RELAP5 sensitivity 

calculation using the 30%/70% assumption was performed. Results for the sensitivity case are 

very similar to those for the base case. The first primary system failure in the sensitivity case is 

Hot Leg 1 at 13,565 s (it occurred at 13,625 s in the base case). The average tube multiplier for 

failure coincident with the HL is 2.57 (in the base case it was 2.74). The hottest tube multiplier 

for failure coincident with the hot leg is 1.48 (in the base case it was 1.67). The SG tube failure 

margin reductions resulting from changing the tube split from 41%/59% to 30%/70% are judged 

to be moderate. Therefore, uncertainties related to this issue for the findings in this report 

regarding containment bypass in general are also judged to be moderate. 

5.5 Effects Related to Opening SG Tube and HL Rupture Flow Paths

Independent thermal-hydraulic analyses related to the containment bypass issue are underway 

as a part of a separate project, the State-of-the-Art Reactor Consequences Analyses 

(SOARCA) Project. Unlike, the SCDAP/RELAP5 analyses presented in this report, in the 

SOARCA analyses, the opening of rupture flow paths (from the primary to secondary coolant 

system through ruptured SG tubes and from the primary coolant system into the containment 

through ruptured HLs) are directly modeled. The SOARCA analysis results therefore include 

system pressure responses and tube and pipe rupture flows not seen in the SCDAP/RELAP5 

analyses. The tube and piping rupture flow responses are primarily of interest for considering 

the radiological release aspects of containment bypass. 

To provide a basis for comparing results between the SCDAP/RELAP5 and SOARCA analysis 

methods, four SCDAP/RELAP5 sensitivity calculations were performed in which SG tube 

rupture and HL rupture flow paths were directly modeled. The SCDAP/RELAP5 sensitivity 

calculations performed are listed in Table 5.6 and are summarized as follows. 
104

Table 5.6 Results of Sensitivity Calculations Evaluating the Effects of Opening SG 

Tube Rupture and HL Rupture Flow Paths 

Case 

Number 

Size of SG Tube Rupture 

Modeled Time of SG Tube Rupture Hot Leg Break Modeled 

F1 Equivalent to the doubleended rupture of one tubeTime in the base case run 

when the hottest tube with a 

stress multiplier of 2.0 is 

predicted to fail (13,560 s) 

No 

F2 Equivalent to the doubleended rupture of one tubeTime in the base case run 

when the hottest tube with a 

stress multiplier of 2.0 is 

predicted to fail (13,560 s) 

Yes. The HL is 

predicted to fail at 

13,630 s and the 

break is opened at 

that time. 

F3 Equivalent to the doubleended rupture of one tubeTime in the base case run 

when the hottest tube with a 

stress multiplier of 3.0 is 

predicted to fail (13,140 s) 

No 

F4 Equivalent to the doubleended rupture of four tubesTime in the base case run 

when the hottest tube with a 

stress multiplier of 2.0 is 

predicted to fail (13,560 s) 

No 
105

Cases F1 through F4 use the same set of assumptions as in the base calculation in Section 4 

except that simulation of SG tube ruptures in the pressurizer-loop steam generator are directly 

modeled. The SG tube inner diameter is 1.97 cm [0.775 in]. The size of the assumed tube 

break between the SG primary and secondary systems varies from case to case, along with the 

time when the tube break is assumed to open. The tube breaks are assumed to be 

double-ended, with a total flow area per ruptured tube of twice the tube flow area: 6.08 cm2

[0.943 in2

]. The SG tube ruptures are modeled in the first active tube cell above the top of the 

tubesheet in the hot tube section (Component 110, Cell 3, see Figure 3.16). Additionally, 

rupture of the HL in Loop 1 with a break size equivalent to the flow area of the pressurizer surge 

line is modeled in one of the cases. 

For reference, pertinent data from the base case calculation in Section 4 are as follows: 

HL failure time: 13,625 s 

SG-1 average tube multiplier for failure coincident with HL: 2.74 

SG-1 hottest tube multiplier for failure coincident with HL: 1.68 

At end of calculation (18,000 s) the core is partially molten but not yet relocated 

Case F1 (Rupture of a Single Tube at Time When the 2.0 Stress Multiplier Hottest 

Tube Fails) 

The SG tube rupture is modeled to occur at 13,560 s, which is 65 s prior to the time of HL failure 

in the base case. The SG tube ruptures when the 2.0 stress multiplier SG-1 hottest tube is 

predicted to fail in the base case. In Case F1 the HL fails 5 s later than in the base case (at 

13,630 s) and the SG-1 average tube multiplier for failure coincident with the HL declines to 

2.49. For this case the HL is predicted to fail 70 s after the time the SG tube rupture opens. 

The flow through the SG tube break peaks (at ~13 kg/s) at the time of the rupture and continues 

at a reduced rate throughout the remainder of the run (averaging ~3 kg/s). The pressurization 

of SG 1 by the tube break causes the SG-1 PORV to cycle open and closed several times 

between 13,884 s and the time of battery depletion at 4 hours. The SG PORVs fail closed and 

are inoperative after the batteries are depleted. The SG-1 SRVs did not open. The total 

integrated mass lost to the environment through the SG-1 PORV is 600 kg. Note that in this run 

an actual rupture of the HL is not modeled and that the first time the SG-1 PORV opens is 254 s 

after the time when the HL is predicted to fail. Had the RCS depressurization effects of opening 

the HL break been modeled, none of the 600 kg release to the environment would have been 

predicted to occur. The effects of opening the HL break, including the prevention of the 

environmental release are included in the modeling for Case F2. In Case F1, a significant 

portion of the core relocates to the RV lower head at 16,304 s. 

Case F2 (Rupture of a Single Tube at Time When the 2.0 Stress Multiplier Hottest 

Tube Fails and Subsequent Rupture of the Hot Leg) 

The SG tube rupture is modeled to occur at 13,560 s, which is 65 s prior to the time of HL failure 

in the base case. In Case F2 the HL failure is predicted to occur at 13,630 s (which is 5 s later 

than in the base case) and the HL break path is opened at that time. The HL break is simulated 

as a flow path from HL 1 to the containment with a flow area equivalent to that of the 0.284-m 

[11.2-in] I.D. pressurizer surge line. For this case the HL is predicted to fail 70 s after the time 

the SG tube rupture opens. The flow through the SG tube break peaks (at ~13 kg/s) at the time 

of the tube rupture, but quickly turns negative as a result of the rapid RCS depressurization 

caused by opening the HL break. The pressurization of SG 1 by the tube break is not sufficient 

to open the SG-1 PORV prior to the time when the HL break opens. Therefore, in Case F2 no 
106

SG-1 PORV or SG-1 SRV flow to the environment is experienced. The Case F2 run failed at 

13,723 s, which is 93 s after the HL break opens. We attempted to advance the run further but 

were unsuccessful in doing so. At the end of the Case F2 calculation the core has been 

significantly damaged but has not yet relocated to the RV lower head. Melted and refrozen fuel 

blocks the two hottest fuel channels and molten porous debris resides in major portions of other 

three core channels. It is concluded that opening the HL break rapidly blows down the RCS into 

containment, thus removing further challenges to the integrity of the SG tubes, accelerating the 

core damage process and preventing a release to the environment. 

Case F3 (Rupture of a Single Tube at Time When the 3.0 Stress Multiplier Hottest 

Tube Fails) 

The SG tube rupture is modeled to occur at 13,140 s, which is 485 s prior to the time of HL 

failure in the base case. The SG tube ruptures when the 3.0 stress multiplier SG-1 hottest tube 

failed in the base case. In case F3 the HL fails 45 s later than in the base case (at 13,670 s) 

and the SG-1 average tube multiplier for failure coincident with the HL increases to 4.39. For 

this case the HL is predicted to fail 530 s after the time the SG tube rupture opens. The flow 

through the SG tube break peaks (at ~16 kg/s) at the time of the rupture and continues at a 

reduced rate throughout the remainder of the run (averaging ~4 kg/s). The pressurization of 

SG 1 by the tube break causes the SG-1 PORV to cycle open and closed many times between 

13,516 s and the time of battery depletion at 4 hours. The SG PORVs fail closed and are 

inoperative after the batteries are depleted. The total integrated mass lost to the environment 

through the SG-1 PORV is 2,068 kg. Following battery depletion, the SG-1 SRVs open for the 

first time at 15,666 s and cycle open and closed many times between then and the end of the 

calculation at 18,000 s. During that period, the total integrated mass lost to the environment 

through the SG-1 SRVs is 2,438 kg. Note that in this run an actual rupture of the HL is not 

modeled and that only a portion of the time period when the SG-1 PORV opens and none of the 

time period when the SG-1 SRVs open is prior to the time when the HL is predicted to fail. Had 

the RCS depressurization effects of opening the HL break been modeled, only 864 kg of the 

release through the SG-1 PORV and none of the release through the SG-1 SRVs would have 

been predicted to occur. In Case F3, a significant portion of the core relocates to the RV lower 

head at 15,064 s, which is shortly before the SG-1 SRVs open for the first time. 

Case F4 (Rupture of Four Tubes at Time When the 2.0 Stress Multiplier Hottest Tube 

Fails) 

The SG tube rupture is modeled to occur at 13,560 s, which is 65 s prior to the time of HL failure 

in the base case. The SG tube ruptures when the 2.0 stress multiplier SG-1 hottest tube failed 

in the base case. In case F4 the HL fails 15 s later than in the base case (at 13,640 s) and the 

SG-1 average tube multiplier for failure coincident with the HL declines to less than 1.5. For this 

case the HL is predicted to fail 80 s after the time the SG tube rupture opens. The flow through 

the SG tube break peaks (at ~45 kg/s) at the time of the rupture and continues at a reduced rate 

throughout the remainder of the run (averaging ~3 kg/s). The pressurization of SG 1 by the 

tube break causes the SG-1 PORV to continuously cycle open and closed between 13,615 s 

and the time of battery depletion at 4 hours. The SG PORVs fail closed and are inoperative 

after the batteries are depleted. The total integrated mass lost to the environment through the 

SG-1 PORV is 5,241 kg. Following battery depletion, the SG-1 SRVs open for the first time at 

17,436 s and cycle open and closed continuously between then and the end of the calculation at 

18,000 s. During that period, the total integrated mass lost to the environment through the SG-1 

SRVs is 8,014 kg. Note that in this run an actual rupture of the HL is not modeled and that only 

a portion of the time period when the SG-1 PORV opens and none of the time period when the 
107

SG-1 SRVs open is prior to the time when the HL is predicted to fail. Had the RCS 

depressurization effects of opening the HL break been modeled, only 344 kg of the release 

through the SG-1 PORV and none of the release through the SG-1 SRVs would have been 

predicted to occur. In Case F4, a significant portion of the core relocates to the RV lower head 

at 17,237 s. 

Conclusions from the SOARCA-Counterpart SCDAP/RELAP5 Calculations

Ruptures of the equivalent of one and four SG tubes were modeled at the times when the 2.0 

and 3.0 stress multiplier hottest tubes were predicted to fail in the base case run. These 

assumed SG rupture times are 65 s and 485 s, respectively, prior to the time when the HL fails 

in the base case calculation in Section 4. These predictions indicate that opening the SG tube 

break flow paths does not significantly affect the timing of the subsequent HL failure. Modeling 

the tube break does delay the HL failure and this is as expected since the tube breaks begin to 

depressurize the RCS. However, the predicted HL failure time delays are very small: only 5 s 

(one tube) and 15 s (four tube) for breaks that open 65 s prior to the base case HL failure and 

45 s for a one-tube break that opens 485 s prior to the base case HL failure. 

The peak flows through the tube breaks are found to be ~15 kg/s per double-ended tube 

rupture. A single ruptured tube removes fluid from the RCS at a rate which is on the same order 

as the circulating flows in the HLs (~5 kg/s) and in the SG tubes (~10 kg/s) near the time when 

the HL is predicted to fail. CFD predictions (NUREG-1922) indicate that leakage rates of this 

magnitude completely break down the overall natural circulation flow patterns and tubes near 

the leaking tube are subjected to temperatures approaching the hot leg flow temperatures. 

These results suggest that a potential exists for propagation of tube failures, with the first tube to 

fail drawing additional hot steam into that SG potentially leading to additional tube failures. 

As expected, the fluid released to the environment through the PORV and SRVs of the SG 

containing ruptured tubes is seen to be proportional to the number of tubes assumed to rupture 

and to the time period during which flow from the RCS passes into the SG. 

Directly modeling the tube ruptures is seen to result in an acceleration of the core degradation 

process. In comparison with the base case run, which did not model tube breaks, the effects of 

modeling tube ruptures are seen to result in earlier melting of fuel, blockage of core flow 

channels and relocation of molten core materials to the RV lower head. 

Finally, it is concluded that opening a HL break rapidly blows down the RCS into containment, 

thus removing further challenges to the integrity of the SG tubes, additionally accelerating the 

core damage process and significantly reducing or eliminating the environmental release. 
108
109

6. GROUPING OF EXTENDED SBO EVENT SEQUENCES INTO 

CONTAINMENT BYPASS, POTENTIAL FOR CONTAINMENT 

BYPASS, AND NO CONTAINMENT BYPASS CATEGORIES 

The Westinghouse four-loop plant thermodynamic conditions experienced during a typical nonLOCA accident event sequence with normal operation of the safety systems are characterized 

in Table 6.1. With the safety systems available, both the primary and secondary cooling 

systems remain pressurized and water-filled. The core heat passes from the fuel rods into the 

RCS cooling water, and from there through the SG tubes into the SG water inventory. Steam 

produced in the SGs is released to the environment through the SG PORVs and the SG 

inventory lost is replenished by the AFW system. The plant conditions with safety systems 

available reflect a continuation of these safe and stable fluid conditions. 

The plant thermodynamic conditions experienced during the hypothetical extended SBO severe 

accident event sequences evaluated in this report are characterized in Table 6.2. The loss of 

AC-powered plant safety systems is assumed to prevent replenishment of the water inventories, 

resulting in dry conditions in both the primary and SG secondary systems. Because of the dry 

SGs, the heat sink available for the core fission product decay power is insufficient and as a 

result the RCS remains pressurized and experiences a transient heat-up. The assumed dry 

conditions in the secondary system make it susceptible to depressurization due to leakage 

through valves in the main steam system and as a result the secondary system pressure falls. 

The high differential pressure across the SG tubes and the weakened structural strength caused 

by the increasing temperatures significantly increase the likelihood of SG tube failures. The 

containment bypass risk is therefore created during for extended SBO events because of the 

increased potential for SG tube failure during the system heat-up. Of note is that the SGs 

remain a heat sink for the RCS (albeit a poor one), and this induces hot steam to be drawn from 

the reactor core into the SGs. Also of note is that, because the total heat sink for the reactor 

core heat is insufficient, both the RCS and SG systems experience transient heat-ups and it is 

the differences between the heat-up behaviors (especially the heat-up timing and rates) 

experienced in various portions of the plant, in particular between the HLs and the SG tubes, 

which are of most importance for the containment bypass issue. 

The objective of this report is to coalesce the findings from prior and current evaluations (using 

the failure margin definitions and selection criteria described in Section 1.4) into a view of the 

extended SBO severe accident event sequences that fall into the following three categories: 

 Sequences resulting in containment bypass (undegraded, 1.0-stress 

multiplier, hottest SG tube is predicted to fail prior to the HL) 

 Sequences with a potential for resulting in containment bypass (hottest SG 

tube failure margin is between 1.0 and 3.0) 

 Sequences not resulting in containment bypass (hottest SG tube failure 

margin is 3.0 or higher). 

This categorization of event sequences provides information that (when combined with results 

from pertinent SG tube structural analyses, probabilistic risk assessments and environmental 

release evaluations) permits an evaluation of risks due to containment bypass. 
110

Table 6.1 Characterization of Plant Fluid Conditions During Typical Non-LOCA 

Accident Sequences with Normal Operation of Safety Systems 

RCS Pressure RCS Water 

Inventory SG Water Inventory SG Pressure 

High Wet Wet High 

~15.5 MPa [~2,250 

psia] 

RCS water-filled, with a 

liquid/steam interface 

within the pressurizer 

SG downcomer and 

boiler regions 

water-filled, with a 

liquid/steam interface in 

the separator region 

~6.9 MPa [~1,000 psia] 

RCS pressure 

maintained by 

operation of pressurizer 

heater and spray 

systems, pressurizer 

PORVs and SRVs 

prevent overpressure 

condition 

Water inventory 

replenished by HPI and 

charging systems, 

pressurizer level 

controlled within normal 

range by operation of 

charging system 

SG water level 

controlled within normal 

range by operation of 

AFW system 

Heat transfer from RCS 

to SGs pressurizes the 

secondary coolant 

system, SG PORVs 

and SRVs prevent 

overpressure condition 

Table 6.2 Characterization of Plant Fluid Conditions During an Extended Station 

Blackout Accident Sequence 

RCS Pressure RCS Water 

Inventory SG Water Inventory SG Pressure 

High Dry Dry Low 

~16 MPa [~2,320 psia] RCS becomes mostly 

steam-filled 

SG secondary system 

becomes steam-filled 

~0.1 MPa [~15 psia] 

Insufficient heat sink for 

the reactor core causes 

the RCS fluid to heat 

up 

Heat-up causes RCS 

water inventory to be 

expelled through the 

pressurizer PORVs and 

SRVs 

Core heat is first 

removed to the SG 

water inventory, which 

is boiled to steam 

The boiling process 

causes SG pressure to 

remain elevated until 

the water inventory has 

been lost 

Fluid expansion effects 

increase and maintain 

RCS pressure near the 

pressurizer PORV/SRV 

opening setpoint 

pressures 

Water remains in the 

cold leg loop seal 

regions and in the 

region below the core 

in the RV, core heat 

causes RCS 

temperatures to 

significantly increase 

Steam is expelled from 

the secondary system 

through the SG PORVs 

and SRVs 

After SG dry-out the 

steam-filled secondary 

system is susceptible to 

depressurization due to 

leakage through main 

steam outlet valves 

High RCS pressure 

maintains stress on the 

SG tubes 

High RCS 

temperatures weaken 

the SG tube material 

strength 

Steam in the SGs is 

cooler than the steam 

in the RCS, causing the 

SGs to remain an 

inefficient heat sink for 

the reactor core heat 

Low SG pressure 

greatly increases stress 

on SG tubes 
111

The categorization of event sequences is performed by using the evaluations and 

considerations described in this report to select the parameters which have been found to have 

major influences on the four fluid conditions required for occurrence of containment bypass 

(high-pressure RCS, dry RCS, dry SG and low-pressure SG as listed in the columns of 

Table 6.2). From among this set of parameters, those which are identified as being the most 

influential are selected as the key event-sequence parameters regarding the containment 

bypass outcome. The quantitative results from the evaluations summarized in this report are 

then used to map the containment bypass outcome as a function of the key event sequence 

parameters. 

It is cautioned that the event sequence categorizations presented here are estimates which may 

be affected by many factors, some of which are summarized as follows. The 3.0 hottest-tube 

failure margin criterion is arbitrary. Prototype SGs may or may not contain SG tubes with 

material-strength properties that have been degraded to that extent. The criterion assumes that 

the hottest steam entering any of the SG tubes enters a tube with that reduced material 

strength. The event sequence categorization is made based on limited number of 

SCDAP/RELAP5 simulations; the borders between the regions for the three categories are 

necessarily assigned using judgments about the behavior to be expected between data points 

directly supported by the simulations. The total uncertainty in the SCDAP/RELAP5-predicted 

hottest-tube failure margin is judged to be about 0.4. The methodical PIRT-based uncertainty 

evaluation summarized in Section 2.9 found that the standard deviation in the hottest tube 

failure time was 54.89 s which, when used with the base-case hottest-tube failure time data 

from Table 4.4, gives a two-sigma uncertainty around the 3.0 hottest tube failure margin of 

about 0.20. However, additional uncertainties affecting the hottest-tube failure margin prediction 

likely also apply (such as the +0.58 attributed to the assumed HL nozzle material, see 

Section 2.10, and the -0.19 attributed to modeling a worst-case split of the SG tubes into hot 

and cold sections, see Section 5.4). 

Despite the limitations of the event sequence categorization process described in the preceding 

paragraph, the results are useful for defining the set of event sequences which clearly pose a 

risk for containment bypass and the set of event sequences which clearly do not. For those 

event sequences providing only a potential for containment bypass, the results are also useful 

for focusing upon the parameters for which additional analyses may be productively employed 

to further clarify event-sequence outcomes. 

Event sequences which do not involve operator intervention are categorized in Section 6.1 and 

event sequences involving operator intervention are categorized in Section 6.2. 

6.1 Categorization of Event Sequences Without Operator Intervention

At the highest level, the containment bypass outcomes for certain event sequences are seen to 

be determined by loop seal clearing behavior or by the timing of core damage and relocation 

behavior: 

The analyses in this report demonstrate that event sequences resulting in the 

clearing of one or more loop seals lead to containment bypass. With a loop seal 

cleared of water, hot steam flows around the coolant loop (from the RV outlet 

nozzle, through the HL, SG, RCP and CL to the RV inlet nozzle) in direction of 

normal flow during powered operation. In this situation the SG tubes rapidly fail 

because they are continually exposed to the hottest steam given off by the core; 

see the discussion in Section 1.3. 
112

The analyses in this report also demonstrate that certain event sequence 

assumptions promote acceleration of the core damage process such that 

containment bypass is avoided. If core damage progresses rapidly enough, then 

the core geometry may be significantly altered and the core may be relocated to 

the lower head of the RV prior to the time when coolant loop piping or SG tube 

structural failures occur. In this situation the core decay heat primarily goes into 

altering the structure of the core, which generally results in blockage of the flow 

paths through the core, reduction of the effective area for transfer of heat from 

the core material to the core fluid, and relocation of significant portions of the 

core to the lower head of the RV. With the core reconfigured in such a manner 

and the flow of heat to the SGs correspondingly reduced, the challenge to the 

structural integrity of the SG tubes is removed and containment bypass does not 

occur. 

Beyond these top level considerations, the evaluations presented in this report were reviewed 

for the purpose of identifying other considerations related to event sequence assumptions, plant 

configuration, and SCDAP/RELAP5 modeling important for determining the containment bypass 

outcome. The results of this review (and references to pertinent evaluations in this report) for 

event sequences without operator intervention are listed in Table 6.3. 

The items listed in the “Modeling Considerations” table column reflect SCDAP/RELAP5 

modeling uncertainties affecting the calculated SG tube failure margins but which were 

generally not found to be sufficiently influential to alter the containment bypass outcome. 

The items listed in the “Plant Configuration Considerations” table column reflect plant-specific 

assumptions related to piping configuration, component materials and plant operating condition. 

These items also were found to affect the calculated SG tube failure margins but generally not 

sufficiently to alter the containment bypass outcome. 

The items listed in the “Event Sequence Consideration” table column reflect assumptions 

defining the event sequences themselves and evaluations related to these items were found to 

most-directly affect the containment bypass outcomes. Of the seven items listed in this column, 

the top four items, shown in bold, were judged to be the most significant regarding containment 

bypass outcome. The assumptions related to the size and timing of RCP shaft seal leakage 

affect the depressurization of the RCS, which reduces the stresses on SG tubes. However, if 

the RCS depressurization is sufficiently rapid, loop seal clearing or early core damage and 

relocation may result. The assumption as to the operability of the TDAFW system directly 

affects removal of core heat from the RCS and prevents heat-up of the SG tubes. While most of 

the analyses presented in this report assumed the TDAFW system inoperable, an assumption 

that TDAFW operates, at least initially, likely represents a more-realistic condition. Leakage of 

steam from the SGs through closed main steam line valves results in depressurization of the SG 

secondary systems, which increases the stresses on the SG tubes. The analyses demonstrate 

that after SG dry-out relatively small steam leakage paths are sufficient to fully depressurize the 

SGs by the time when piping and SG tube structures are predicted to fail. 

These four items (RCP shaft seal leakage rate, RCP shaft seal leakage timing, TDAFW system 

operation and leakage of steam from the SG secondary system) are judged to be the key 

parameters affecting the containment bypass outcome for event-sequences without operator 

intervention. The quantified evaluations for these key parameters in this report are used to 
113

Table 6.3 Major Considerations and Influences on the Containment Bypass Outcome 

for Event Sequences Without Operator Intervention 

Event Sequence 

Considerations 

Plant Configuration 

Considerations 

Modeling 

Considerations 

RCP shaft seal leakage rate 

(See Sections 2.3, 2.4, 5.1, 5.2 

and Appendices A and D) 

SG tube plugging 

(See Sections 2.3, 2.4 and 

Appendix A) 

Heat loss from RCS and SGs to 

containment 

(See Sections 2.3, 2.4 and 

Appendixes A and D) 

RCP shaft seal leakage timing 

(See Sections 2.3, 2.4, 5.1, 5.2 

and Appendix D) 

Configuration of the connection 

of the surge line to the HL 

(See Appendix D) 

Prediction of the transient fuel 

rod cladding oxidation rate 

(See Sections 2.4, 3.3.2 and 

Appendix D) 

TDAFW system operation 

(See Sections 2.6, 5.2 and 

Appendix B) 

RV outlet nozzle materials 

(See Section 2.10 and 

Appendix E) 

HL discharge coefficient 

(See Sections 2.5, 2.8, 3.4 and 

Appendix D) 

Leakage of steam from SG 

secondary system 

(See Sections 2.6, 5.2 and 

Appendices B and D) 

 Hot and cold mixing fractions 

(See Sections 2.3, 2.4, 2.8, 

2.10, 3.5 and Appendices A 

and D) 

Stuck-open SG secondary 

system relief valves 

(See Section 2.3 and 

Appendix D) 

 Recirculation ratio 

(See Sections 2.3, 2.8, 2.10, 3.5 

and Appendices A and D) 

Station battery life 

(See Sections 2.6, 5.2 and 

Appendix B) 

 Split of SG tubes into hot and 

cold sections 

(See Sections 2.3, 2.8, 2.10, 3.5 

and Appendix D) 

Pre-existing SG tube leakage 

(See Section 2.4 and 

Appendix D) 

 Tube-to-tube inlet steam 

temperature variations, NTR 

(See Sections 2.3, 2.8, 2.10 

and 3.5) 

 Heat transfer coefficient on 

outside of SG tubes 

(See Section 2.4 and 

Appendices A and D) 

 Circulating flows internal to the 

RV 

(See Sections 2.4, 2.5 and 

Appendices A and D) 

 Core damage and relocation 

modeling 

(See Sections 2.4, 3.3 and 

Appendix A) 
114

construct the maps of containment bypass outcome shown in Figures 6.1 through 6.5. The 

findings shown in these maps are discussed as follows. 

Variations in SG Steam Leakage and RCP Shaft Seal Leakage Which Increases After 

13 Minutes

Figure 6.1 illustrates the estimated containment bypass outcome as a function of the assumed 

SG steam leakage flow area and the assumed RCP shaft seal leakage rate after 13 minutes. 

Very small assumed SG steam leakage flow areas (up to 0.64 cm2

/SG [0.1 in2/SG]) were found 

to keep the SG secondary pressures elevated and sufficiently reduce the stresses on the SG 

tubes to prevent their failure. For larger assumed SG steam leakage flow areas the SGs are 

significantly depressurized prior to the time of the RCS heat-up, providing a potential for 

containment bypass. 

Following the loss of RCP seal injection at the beginning of the event sequence, a shaft seal 

leakage rate of 1.325 L/s [21 gpm] per pump represents postulated minimum leakage from the 

RCS into the containment through the shaft seals. In addition, certain seal failures may occur at 

around 13 minutes into the SBO event, possibly resulting in shaft seal leakage rates as high as 

30.2 L/s [480 gpm] per pump. The evaluations show that potential for containment bypass 

exists for increased RCP shaft seal leakage rates below 11.36 L/s [180 gpm] per pump. At that 

rate and higher, the shaft seal leakage flow depressurizes the RCS sufficiently to reduce the 

stresses on the SG tubes and prevent their failure. The evaluations show that the RCS 

depressurizations experienced from increases in RCP shaft seal leakage up to the maximum 

30.2 L/s [480 gpm] per pump at 13 minutes do not result in loop seal clearing. An important 

factor influencing this finding is that at 13 minutes the SGs have not yet dried out and the 

temperature of the water in the loop seals is far below the RCS saturation temperature. The 

flashing of the cool water in the loop seals caused by the increased RCP shaft seal leak rates 

after 13 minutes is not sufficient to clear the water from the loop seals. 

Variations in SG Steam Leakage and RCP Shaft Seal Leakage Which Increases When the RCP 

Fluid Reaches the Saturation Temperature

Figure 6.2 illustrates the estimated containment bypass outcome as a function of the assumed 

SG steam leakage flow area and the assumed RCP shaft seal leakage rate after the time when 

the fluid in the RCPs reaches the saturation temperature. 

As in the discussion in the preceding section, very small assumed SG steam leakage flow areas 

(up to 0.64 cm2

/SG [0.1 in2/SG]) were found to keep the SG secondary pressures elevated and 

sufficiently reduce the stresses on the SG tubes to prevent their failure. For larger assumed SG 

steam leakage flow areas the SGs are significantly depressurized prior to the time of the RCS 

heat-up, providing a potential for containment bypass. 

Following the loss of RCP seal injection at the beginning of the event sequence, a SG shaft seal 

leakage of 1.325 L/s [21 gpm] per pump represents the postulated minimum leakage flow from 

the RCS into the containment through the shaft seals. In addition, certain seal failures may 

occur at around 13 minutes into the SBO event and certain other seal failures may occur when 

the fluid in the RCPs changes from liquid to steam. The presence of steam in the RCPs is 

indicated by the liquid temperature reaching the saturation temperature, which occurs at about 2 

hours into the base case event sequence. 
115

0 180 480 21

0.1

0

0.2

0.3

0.4

0.5

RCP Shaft Seal Leak Rate After 13 minutes (gpm/pump) 

SG Steam 

Leakage 

Flow Area 

(in2/SG) 

No Containment Bypass

Potential for 

Containment 

Bypass

Figure 6.1 Map of Containment Bypass Outcome for No Operator Intervention and 

Variations in SG Steam Leakage and RCP Shaft Seal Leakage Which 

Increases at 13 Minutes 

Figure 6.2 Map of Containment Bypass Outcome for No Operator Intervention and 

Variations in SG Steam Leakage and RCP Shaft Seal Leakage Which 

Increases When the RCP Fluid Reaches the Saturation Temperature 
116

The investigations in this report evaluated the effects of a shaft seal leakage increase to 

3.786 L/s [60 gpm] per pump at 13 minutes followed by a second increase to a higher rate when 

the RCP fluid temperature reaches saturation. The evaluations show a potential for 

containment bypass for increased RCP shaft seal leakage rates of less than 11.36 L/s 

[180 gpm] per pump. At that rate and up to 25.23 L/s [400 gpm] per pump, the shaft seal 

leakage depressurizes the RCS sufficiently to reduce the stresses on the SG tubes, preventing 

their failure and avoiding containment bypass. However, (unlike the sequences for which the 

increase to a high leakage rate occurs at 13 minutes) above a 25.23 L/s [400 gpm] per pump 

leak rate the RCS depressurization is sufficient to clear the loop seals, resulting in containment 

bypass. The heating of the water in the loop seals that occurs between 13 minutes and 2 hours 

(which is after SG dry-out and during the RCS heat-up period) results in increased flashing of 

the loop seal water and the clearing of the loop seals when the leakage rate increases for the 

second time. 

Variations in Temporary TDAFW System Operation and RCP Shaft Seal Leakage Which 

Increases After 13 Minutes

Figure 6.3 illustrates the estimated containment bypass outcome as a function of temporary 

TDAFW system operation and RCP shaft seal leakage which increases at 13 minutes. 

Event sequences in which the TDAFW system operates and continues operating do not lead to 

containment bypass. In this situation, heat passes from the RCS into the water-filled SGs. The 

outer surfaces of the SG tubes remain cool and the low tube temperatures prevent their rupture, 

regardless of the pressure stresses caused by high RCS pressure and low SG pressure. RCP 

shaft seal leakage does result in a loss of the RCS inventory, however heat removal to the SGs 

continues even after the upper regions of the RCS become steam filled. The continued loss of 

the RCS inventory may eventually lead to a condition where the core is uncovered or otherwise 

not adequately cooled. In this event core failure may occur but, because TDAFW operation 

would continue cooling the SG tubes, containment bypass would not occur. 

Challenges to continued TDAFW operation result from: (1) depletion of the station batteries, 

which may result in valve failures preventing delivery or control of the TDAFW flow, (2) the need 

to arrange for an alternate source of water for the TDAFW system following depletion of the 

CST inventory and (3) a loss of SG pressure sufficient to affect operation of the TDAFW turbine, 

which powers the pump. Station battery depletion is estimated to occur between 4 and 8 hours 

and CST water inventory depletion is estimated to occur at about 15 hours. Extrapolations of 

the behavior seen in SCDAP/RELAP5 simulations in which TDAFW operates and maintains SG 

levels until 8 hours suggest that sufficient SG pressure will remain available for driving the 

TDAFW turbine until 15 hours, and perhaps beyond that. 

For event sequences in which the TDAFW system is assumed to initially operate and then later 

fail, results are similar to those seen when the TDAFW does not operate at all. For RCP shaft 

seal leak rates after 13 minutes from 11.36 L/s [180 gpm] per pump up to the maximum 30.2 L/s 

[480 gpm] per pump, loop seal clearing does not occur and the tube stresses are sufficiently 

reduced by the RCS depressurization to prevent SG tube failure and containment bypass. A 

potential for containment bypass is seen for RCP shaft seal leak rates below 11.36 L/s 

[180 gpm] per pump. 
117

Variations in Temporary TDAFW System Operation and RCP Shaft Seal Leakage Which 

Increases When the RCP Fluid Reaches the Saturation Temperature

Figure 6.4 illustrates the estimated containment bypass outcome as a function of temporary 

TDAFW system operation and the assumed RCP shaft seal leakage rate after the time when 

the fluid in the RCPs reaches the saturation temperature. 

For event sequences in which the TDAFW system is assumed to initially operate and later fail, 

results are similar to those seen when the TDAFW does not operate at all. A potential for 

containment bypass is seen for sequences in which the RCP shaft seal leak rate after the time 

when the RCP fluid saturates is less than 11.36 L/s [180 gpm] per /pump. Above a 11.36 L/s 

[180 gpm] per pump leak rate and up to a 25.3 L/s [400 gpm] per pump leak rate, no loop seal 

clearing is seen and the RCS depressurization is sufficient to either reduce SG tube stresses 

and prevent their failure or to result in early core failure. In either case containment bypass is 

avoided. 

Note that the results for TDAFW operation and leak rates above 25.23 L/s [400 gpm] per pump 

are different than seen for when the TDAFW does not operate at all (compare Figures 6.4 

and 6.2). With no TDAFW operation, leak rates above 25.23 L/s [400 gpm] per pump are seen 

to result in loop seal clearing and containment bypass. The analyses indicate that a 4-hour 

period of TDAFW operation sufficiently cools the water in the loop seals such that when the leak 

rate increases to the maximum 30.2 L/s [480 gpm] per pump, loop seal clearing and 

containment bypass do not occur. Figure 6.4 portrays this effect as persisting down to a 

TDAFW operation period of 3 hours, however the actual minimum TDAFW operation period 

which produces this beneficial effect is not known. 

Variations in Temporary TDAFW System Operation and SG Steam Leakage

Figure 6.5 illustrates the estimated containment bypass outcome as a function the temporary 

TDAFW system operation and the assumed SG steam leakage flow area. 

The data shown in the figure are based on a limited number of SCDAP/RELAP5 cases. 

Evaluations were made using an RCP shaft seal leakage rate of 1.325 L/s [21 gpm] per pump, 

TDAFW operation times of 0 hours and 8 hours and SG steam leakage flow areas of 

1.29 cm2

/SG [0.2 in2/SG] and 3.23 cm2/SG [0.5 in2/SG]. 

The results of these evaluations show that for event sequences with no TDAFW operation and 

very small SG steam leakage flow areas (less than 0.64 cm2

/SG [0.1 in2/SG]) the SG pressures 

remain elevated sufficiently to reduce SG tube stresses, prevent tube failure and avoid 

containment bypass. 

The evaluations also show that for sequences in which the TDAFW system initially operates and 

later fails the SG tube failure margins are reduced, in comparison with sequences in which the 

TDAFW system never operates. A temporary period of TDAFW operation causes the system 

heat-up to occur later, and the system heat-up rates are slower due to reduced core decay 

power. A slower system heat-up reduces SG tube failure margins because the time constants 

associated with transporting heat from the RV to the SG become less effective at delaying the 

SG tube heat-up relative to the HL piping heat-up. 
118

Figure 6.3 Map of Containment Bypass Outcome for No Operator Intervention and 

Variations in Temporary TDAFW System Operation and RCP Shaft Seal 

Leakage Which Increases at 13 Minutes 

Figure 6.4 Map of Containment Bypass Outcome for No Operator Intervention and 

Variations in Temporary TDAFW System Operation and RCP Shaft Seal 

Leakage Which Increases When the RCP Fluid Reaches the Saturation 

Temperature 
119

0 0.1 0.3

2

0

4

6

8

10

SG Steam Leakage Flow Area (in2/SG)

Period of 

TDAFW 

Operation 

(hours) Potential for Containment Bypass

No Containment Bypass

0.2 0.4 0.5 0.6 0.7

Figure 6.5 Map of Containment Bypass Outcome for No Operator Intervention and 

Variations in Temporary TDAFW System Operation and SG Steam Leakage 

The margin lost from temporary TDAFW operation is seen to exceed the margin gained from 

assuming a very small SG steam leak flow area. As a result, sequences that include a period 

temporary TDAFW operation generally provide a potential for containment bypass, even when 

very low SG steam leakage flow areas are assumed. 

On the other hand, the margin reductions caused by eight hours of TDAFW operation were not 

seen to be large, regardless of the assumed SG steam leakage flow area. It is therefore 

concluded that event sequences in which the TDAFW system operates for a very long period 

before failing continue to provide only a potential for containment bypass and not a certainty of 

containment bypass. 

6.2 Categorization of Event Sequences with Operator Intervention

The effectiveness of two operator intervention strategies (pre-core damage and post-core 

damage) were evaluated. Both operator intervention strategies require that action be taken 

prior to the time when the station batteries have been depleted. Afterward, operator control 

over PORVs on the secondary and primary coolant systems is lost and ability to deliver or 

control TDAFW may also be lost. The core damage outcomes for the two strategies are 

summarized separately below. 

Pre-Core Damage Operator Intervention

In the pre-core damage intervention strategy (which is evaluated in Section 5.3.1) the operators 

implement SG feed-and-bleed cooling at 30 minutes into the event sequence, using the TDAFW 

system and opening the SG PORVs to depressurize the SGs. Table 6.4 characterizes the four 

fluid conditions required for occurrence of containment bypass (high-pressure RCS, dry RCS, 
120

dry SG and low-pressure SG) for event sequences without intervention (from Table 6.2) and for 

event sequences with pre-core damage intervention. Figure 6.6 illustrates the estimated 

containment bypass outcomes as a function the TDAFW system operation and the assumed 

RCP shaft seal leakage flow area. 

The evaluation indicates that the intervention strategy is effective in the short term for removing 

core decay heat and preventing an RCS heat-up that could lead to containment bypass. At a 

minimum, this strategy significantly delays the onset of an RCS heat-up, thereby providing time 

for other plant recovery opportunities to be considered and implemented. In the long term, the 

SG PORVs fail closed when the batteries are depleted and continued success of the 

intervention strategy requires that a TDAFW water source remain available and that some 

capability to deliver the water into the SGs continues. 

For sequences in which the TDAFW system initially operates but later fails, no large changes in 

SG tube failure margins (relative to the no-operator intervention base case event sequence) 

were seen to result from implementing the pre-core damage operator intervention strategy. The 

evaluation also showed that increasing the assumed RCP shaft seal leak rate from 1.325 L/s 

[21 gpm] per pump to 3.786 L/s [60 gpm] per pump at 13 minutes significantly improved the SG 

tube failure margin, although not sufficiently to indicate that containment bypass cannot occur. 

Based on an extrapolation of this margin improvement, Figure 6.6 reflects that containment 

bypass is avoided at RCP shaft seal leak rates of 7.572 L/s [120 gpm] per pump and higher. 

Post-Core Damage Operator Intervention

In the post-core damage strategy (which is evaluated in Section 5.3.2) the operators 

depressurize the RCS by opening the pressurizer PORVs after plant instrumentation has 

indicated that the core damage process is underway. Table 6.5 characterizes the four fluid 

conditions required for occurrence of containment bypass (high-pressure RCS, dry RCS, dry SG 

and low-pressure SG) for event sequences without intervention (from Table 6.2) and for event 

sequences with post-core damage intervention. Figure 6.7 illustrates the estimated containment 

bypass outcomes as a function the number of pressurizer PORVs the operators open and the 

time in the event sequence when the operator action is assumed to begin. 

The evaluations show that opening only one PORV limits the cooling afforded to the RCS, the 

core fails early (prior to battery depletion) and containment bypass is avoided for both of the 

operator intervention times evaluated. 

The evaluations show that the RCS cooling afforded by opening two PORVs prevents early core 

damage and also prevents early failure of the HL and SG tube structures. When the PORVs fail 

closed after battery depletion, the RCS begins re-pressurizing and re-heating and this 

subsequently leads to HL and SG tube failures. The SG tube failure margins seen for the 

operator intervention cases are significantly improved (compared to the no-intervention case) 

and containment bypass is seen to be avoided for both of the operator intervention times 

evaluated. 

The evaluations indicate that the post-core damage mitigative operator intervention strategy is 

effective for preventing containment bypass, regardless of whether the intervention begins at 

the time when the core exit temperature reaches 922 K [1,200°F] or 12 minutes later, and 

regardless of whether one or two pressurizer PORVs are opened. 
121

Table 6.4 Pre-Core Damage Mitigative Operator Intervention Strategy 

RCS Pressure RCS Water 

Inventory SG Water Inventory SG Pressure 

Without Intervention: 

High 

Without Intervention: 

Dry 

Without Intervention: 

Dry 

Without Intervention: 

Low 

Following Intervention: 

Low 

Following Intervention: 

Wet 

Following Intervention: 

Wet 

Following Intervention: 

Medium 

The heat removal to 

depressurized SGs 

greatly reduces RCS 

pressure 

The RCS 

depressurization is 

sufficient to produce a 

period of accumulator 

injection (accumulators 

do not completely 

empty) 

TDAFW operation 

keeps the SG water 

inventory up as long as 

it operates 

Open PORVs 

depressurize SGs 

If TDAFW later stops 

operating, a long period 

is required to heat up 

and repressurize the 

RCS due to reduced 

core decay power 

If TDAFW later stops 

operating, a long period 

is required to expel the 

RCS water due to 

reduced core decay 

power 

If TDAFW later stops 

operating, a long 

inventory boil-off period 

results from reduced 

core decay power 

The SGs repressurize 

after the PORVs fail 

closed following battery 

depletion 

Table 6.5 Post-Core Damage Mitigative Operator Intervention Strategy 

RCS Pressure RCS Water 

Inventory SG Water Inventory SG Pressure 

Without Intervention: 

High 

Without Intervention: 

Dry 

Without Intervention: 

Dry 

Without Intervention: 

Low 

With Intervention: 

Low 

With Intervention: 

Mostly Dry 

With Intervention: 

Dry 

With Intervention: 

Low 

Opening only one 

PORV limits RCS 

cooling and core fails 

early, prior to the 

battery depletion 

The RCS 

depressurization is 

sufficient to produce a 

period of accumulator 

injection (accumulators 

do not completely 

empty) 

 

Opening two PORVs 

affords sufficient RCS 

cooling to avoid early 

core failure. PORVs 

fail closed after battery 

depletion and RCS 

heat-up and 

pressurization lead to 

HL and SG tube 

failures. 

Boiling of the injected 

accumulator water and 

release of steam 

through the PORVs 

enhances RCS cooling, 

but the upper half of the 

core remains dry. 

 
122

Figure 6.6 Map of Containment Bypass Outcome for Pre-Core Damage Operator 

Intervention 

0

Number of 

Pressurizer 

PORVs 

Opened

1

2

Time 

Zero

1200°F

Core Exit 

Temperature

12 Minutes after Core 

Exit Temperature 

Reaches 1200°F

No Containment Bypass

Potential for 

Containment Bypass

Operator Action Begins

Figure 6.7 Map of Containment Bypass Outcome for Post-Core Damage Operator 

Intervention 
123

7. CONCLUSIONS 

Over the past 12 years, the NRC has sponsored extensive evaluations into the containment 

bypass issue for extended SBO accident events in Westinghouse four-loop plants. This report 

coalesces the findings from those former evaluations, along with selected additional 

evaluations, into a view of the extended SBO event sequences that fall into each of the following 

three categories: 

 Sequences resulting in containment bypass. 

 Sequences with a potential to result in containment bypass, for which an 

outcome may be determined by comparing the degradation of tube strengths in a 

prototype SG against the SCDAP/RELAP5-predicted tube failure margins. 

 Sequences not resulting in containment bypass. 

This categorization of event sequences provides information that (when combined with results 

from pertinent SG tube structural analyses, probabilistic risk assessments and environmental 

release evaluations) permits an evaluation of risks due to containment bypass for Westinghouse 

four-loop plants. 

The event sequence categorization is described in Section 6 for situations where no operator 

actions are assumed and for situations where the operators are assumed to implement 

mitigative actions. Cautions related to uncertainties in the criteria used to categorize the event 

sequences and related to limitations of the supporting analyses are discussed there. The maps 

of containment bypass outcomes provided in Section 6 are considered to be the main product of 

the detailed research summarized in this report. The major findings are summarized below: 

For situations where the operators are assumed to take no action the key results are 

summarized as follows. 

Event sequences which assume very small leakage paths for steam to escape 

the SG secondary system (0.64 cm2

/SG [0.1 in2/SG] and smaller) generally do 

not result in containment bypass. The reduced SG tube stresses resulting from 

the SG secondary pressures remaining elevated prevent SG tubes from failing 

prior to the reactor core or a HL piping structure. 

Event sequences which assume RCP shaft seal leakage rates lower than 

11.36 L/s [180 gpm] per pump generally provide a potential for containment 

bypass. Event sequences which assume RCP shaft seal leakage rates of 

11.36 L/s [180 gpm] per pump and higher generally do not result in containment 

bypass. A high leak rate leads to lower RCS pressures, and the reduced SG 

tube stresses prevent SG tubes from failing prior to the reactor core or a HL 

piping structure. However, there are exceptions related to the time when RCP 

shaft seal failures are assumed to occur. For RCP shaft seal failures that occur 

late in the event sequences, loop seal clearing and therefore containment bypass 

occur for leakage rates above 25.23 L/s [400 gpm] per pump. 

Event sequences in which the TDAFW system operates and continues operating 

generally do not result in containment bypass. The outer surfaces of the SG 
124

tubes remain wet and cool and the RCS heat removal provided prevents system 

heat-up. 

For event sequences in which the TDAFW system is assumed to initially operate 

and later fail, results are very similar to those seen when the TDAFW does not 

operate at all. Challenges to continued TDAFW operation result from depletion 

of the station batteries, the need to arrange for an alternate source of water for 

the TDAFW system following depletion of the CST inventory and a loss of SG 

pressure sufficient to affect operation of the TDAFW turbine. 

For situations where the operators take mitigative action the key results are summarized as 

follows. 

An evaluation was performed for a pre-core damage mitigative strategy in which 

operators implement SG feed-and-bleed cooling at 30 minutes into the event 

sequence, using the TDAFW system and opening the SG PORVs. The 

evaluation shows that this strategy is effective in the short term for preventing 

containment bypass. At a minimum, this strategy significantly delays the onset of 

an RCS heat-up, thereby providing time for other plant recovery opportunities to 

be considered and implemented. In the long term, the SG PORVs fail closed 

when the batteries are depleted and continued success of this intervention 

strategy requires that a TDAFW water source remain available and that some 

capability for delivering the water into the SGs continues. For sequences in 

which the TDAFW system initially operates but later fails, no large changes in SG 

tube failure margins (relative to the no-operator intervention base case event 

sequence) were seen to result from implementing the pre-core damage operator 

intervention strategy. Event sequences in which the TDAFW system operates 

and continues operating generally do not result in containment bypass. The 

outer surfaces of the SG tubes remain wet and cool and the RCS heat removal 

provided prevents system heat-up. 

An evaluation was also performed for a post-core damage mitigative strategy in 

which the operators depressurize the RCS by opening one or two pressurizer 

PORVs after plant instrumentation indicates that core damage is in progress. 

PORVs are opened at the time when the core exit temperature reaches 922 K 

[1,200°F] or 12 minutes later. The evaluation shows that opening only one 

PORV limits the cooling afforded to the RCS, the core fails early (prior to battery 

depletion) and containment bypass is avoided for both operator action times. 

The evaluations also show that the greater RCS cooling afforded by opening two 

PORVs prevents early core damage and also prevents early failure of the HL and 

SG tube structures. When the PORVs fail closed after battery depletion, the 

RCS begins re-pressurizing and re-heating and this subsequently leads to HL 

and SG tube failures. The SG tube failure margins seen for the operator 

intervention cases are significantly improved (compared to the no-intervention 

case) and containment bypass is seen to be avoided for both post-core damage 

operator action times. 

In addition to the analyses that led to the above event sequence categorization, limited 

SCDAP/RELAP5 analyses were performed to evaluate the effects of opening SG tube rupture 

and HL rupture flow paths. The findings of these analyses, which were performed to provide a 

basis for comparison with SOARCA Project calculation results, are summarized as follows. 
125

Opening SG tube break flow paths into the SG secondary system does not significantly affect 

the timing of the subsequent HL failure but does significantly reduce the RCS pressure, which 

has a generally beneficial effect on the subsequent stresses in all of the RCS pressure 

boundary components (including the other HLs and the SG tubes which remain intact). 

However, for the remaining tube structures in the SG containing ruptured tubes the beneficial 

effect of the RCS depressurization is exceeded by the detrimental effect of drawing additional 

steam into that SG. This suggests that a potential exists for a propagation of tube failures, with 

the first tube to fail drawing additional hot steam into that SG, leading to additional tube failures. 

The fluid released to the environment through the PORV and SRVs of the SG containing 

ruptured tubes is proportional to the number of tubes assumed to rupture and to the time period 

during which flow passes through the ruptured tubes. Opening a HL break rapidly blows down 

the RCS into containment, thus removing further challenges to the integrity of the SG tubes. 

This detailed thermal-hydraulic evaluation of station blackout event sequences provides 

information that (when combined with results from pertinent SG tube structural analyses, 

probabilistic risk assessments and environmental release evaluations) permits an evaluation of 

risks due to containment bypass for Westinghouse four-loop plants. The integration of this work 

is currently underway within the Office of Nuclear Regulatory Research, Division of Risk 

Analysis and this work supports the closure of the agency’s Steam Generator Action Plan. 
126
127

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Generator tubes During Severe Accident Conditions, U. S. Nuclear Regulatory 

Commission, September 7, 2000. 

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Steam Generator Tube Integrity (WITS Item 200100026), U. S. Nuclear Regulatory 

Commission, May 11, 2001. 

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Environmental Laboratory, November 20, 2000. 

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Variations, Information Systems Laboratories, Inc., ISL-NSAD-NRC-01-004, 

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Information Systems Laboratories, Inc., ISL-NSAD-NRC-01-004 (Draft), March 2002. 
128

2.13 L. W. Ward, Tube-to-Tube Temperature Variations During the Station Blackout Event, 

Task 3.5: Tube-to-Tube Temperature Variations, Information Systems Laboratories, Inc., 

ISL-NSAD-TR-02-03, (Draft), August 2002. 

2.14 C. D. Fletcher, R. W. Shumway and D. A. Barber, Revised SCDAP/RELAP5 Base Case 

Calculation for Zion TMLB’ Station Blackout Event, Information Systems 

Laboratories, Inc., ISL-NSAD-TR-03-18, October 2003. 

2.15 C. F. Boyd, D. M. Helton and K. Hardesty, CFD Analysis of Full-Scale Steam Generator 

Inlet Plenum Mixing During a PWR Severe Accident, U. S. Nuclear Regulatory 

Commission, NUREG-1788, May 2004. 

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for a Zion TMLB’ Station Blackout Event, Information Systems Laboratories, Inc., 

ISL-NSAD-TR-04-05, March 2004. 

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and Thermal-Hydraulic Subcommittees Meeting, “Steam Generator Action Plan,” 

February 3-4, 2004, Rockville, MD. 

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Systems Laboratories, Inc., email to PIRT meeting participants, October 13, 2005. 

2.19 C. D. Fletcher and R. M. Beaton, “SCDAP/RELAP5 Base Case Calculation for the 

Station Blackout Uncertainty Study,” Information Systems Laboratories, Inc., 

August 2006. 

2.20 C. D. Fletcher and R. M. Beaton, “Evaluation of Uncertainties in SCDAP/RELAP5 

Station Blackout Simulations,” Information Systems Laboratories, Inc., August 2006. 

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Severe Accident (Public Meeting),” Electric Power Research Institute Washington Office, 

Washington DC, May 15, 2007. 

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Power Plants Volume 2, Part1: Code Structure and Theory,” prepared for Electric Power 

Research Institute, May 1994. 

2.23 C. C. Ferriso, et al., “Total Emissivity of Hot Water Vapor: 1. The High-Pressure Limit,” 

General Dynamics Space Science Laboratory Technical Report GDA-DBE64-055, 

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Analysis,” presentation at Joint EPRI/NRC Public Meeting, Washington DC, 

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INEL-96/0422, Revision 2, Idaho National Engineering and Environmental Laboratory, 

January 2001. 
129

3.2 F. R. Larson and J. Miller, “A Time Temperature Relationship for Rupture and Creep 

Stress,” Transactions of the ASME, July 1952, pp. 765-775. 

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Assessment for Pressurized Thermal Shock Applications, Information Systems 

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Integral Test Facility for VVER-440/213 Safety Analysis, KFKI Atomic Energy Research 

Institute, Budapest, Hungary, TIERSDI/4NT/2459/41, 1996. 

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Experiment, KFKI Atomic Energy Research Institute, Budapest, Hungary, 

NUREG/IA-0201, March 2001. 

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and Reviews of Independent Code Assessment Reports, Idaho National Engineering 

Laboratory, NUREG/CR-5535, EGG-2596, Vol. 7, June 1994, p. 25. 

3.9 H. R. Saedi and P. Griffith, The Pressure Response of a PWR Pressurizer During an 

Insurge Transient, Transactions of the American Nuclear Society,” 1983 Annual meeting, 

Detroit, Michigan, June 12-16, 1983. 

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Subsequent Reclosure, OSU-CE-13, Oregon State University, October 19, 2001. 

3.11 T. F. Habib, et al., Multiloop Integral System Test (MIST): MIST Facility Functional 

Specification, NUREG/ CR-5670, April 1991. 

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Communities, JRC 4352, LEC 93-73, December 1993. 

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RELAP5/MOD3.2 Code, Union Fenosa Generacion S.A., Central Nuclear Jose Cabrera, 

Madrid, Spain, NUREG/IA-0183, June 2000. 

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Circulation Flows in a Pressurized-Water Reactor Loop under Severe Accident 

Conditions, NUREG 1922, To be published November 2009 

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Cooled Reactors Following an Accidental Depressurization,” Journal of British Nuclear 

Energy Society, Vol. 14, No. 3, 1975, pp. 243-250. 
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3.16 W. A. Stewart, et al., Natural Circulation Experiments for PWR High Pressure Accidents, 

EPRI Project No. RP2177-5, Westinghouse Electric Corp., December 1992. 

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for SAI-SGTR Project,” Sandia National Laboratories, email to C. D. Fletcher (ISL), 

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contract,” January 3, 2008. 
A-1

APPENDIX A – RESULTS OF 2004 SENSITIVITY ANALYSES 

An extensive set of sensitivity studies were performed to evaluate the effects of various changes 

in the SCDAP/RELAP5 Westinghouse four-loop plant modeling options, event sequence 

assumptions and plant configuration. These sensitivity studies are fully documented in 

Reference 2.16. The base case accident sequence and plant model used for the sensitivity 

analyses were the same as described in Section 2.3. The sensitivity evaluations performed and 

the analysis results are summarized as follows: 

A.1 Target Values for the SG Inlet Plenum Region Mixing and Flow Parameters 

See Section 3.4 for the definitions of the mixing and flow parameters which were varied in these 

sensitivity runs. The target hot and cold mixing fractions were increased to 0.87 from the base 

case value of 0.81. The higher target mixing fraction was seen to result in only a slight 

reduction in the SG tube failure margin. The target recirculation ratio was decreased to 2.0 from 

the base case value of 2.75. The lower target recirculation ratio was seen to result in a small 

reduction in the SG tube failure margin. 

A.2 Reactor Coolant Pump Shaft Seal Leakage 

A variety of assumptions regarding the RCP shaft seal leakage were investigated. The base 

case event sequence assumes a constant leak flow area over the duration of the transient event 

sequence. That flow area provides an initial 1.32 L/s [21 gpm] leakage rate per pump. In the 

sensitivity cases, the leakage flow area was increased at different times during the event 

sequence to as high as 18.9 Ls/s [300 gpm] initial leakage rate per pump. The results of the 

sensitivity runs indicated that the SG tube failure margins are sensitive to the assumed RCP 

shaft seal leakage. Small increases in the leakage rate above 1.32 L/s [21 gpm] were seen to 

slightly lower the margin, while the lower RCS pressures caused by much larger increases in 

the leakage rate reduced the stresses on the SG tubes and significantly increased the SG tube 

failure margins. 

A.3 SG Tube Plugging 

Sensitivity evaluations were performed for 0% and 20% SG tube plugging assumptions 

(10% was assumed in the base case). The SG tube failure margin results were seen to be only 

slightly affected by the tube plugging assumption. 

A.4 SG Tube Outer Wall Heat Transfer Heat Transfer Coefficient 

The sensitivity to variations in the heat transfer processes on the outer surface of the SG tubes 

was evaluated using multipliers of 0.1, 5.0 and 10.0 on the SCDAP/RELAP5-calculated heat 

transfer coefficient. The results indicated that the SG tube failure margin is sensitive to this 

parameter. Enhanced heat transfer leads to a tighter coupling of the SG tube wall with the 

cooler steam in the SG boiler region and increased SG tube failure margins. 

A.5 Radiation Heat Transfer Modeling 

The sensitivity to variations in the modeling of thermal radiation heat transfer processes was 

evaluated using SCDAP/RELAP5 runs in which multipliers of 0.5 and 2.0 were placed on the 
A-2

steam-to-wall and wall-to-wall radiation heat fluxes on the surfaces of the RCS structures. The 

results indicated that increased radiation heat flux leads to a slightly improved SG tube failure 

margins. 

A.6 Pressurizer Surge Line CCFL 

Several SCDAP/RELAP5 sensitivity runs were performed to investigate the modeling of 

countercurrent flow limiting (CCFL) behavior related to pressurizer draining. Different CCFL 

models and applicable hydraulic diameters were evaluated. Neither the pressurizer draining 

behavior nor the SG tube failure margins were seen to be significantly affected by the CCFL 

modeling approach. 

A.7 Reactor Vessel Internal Circulations 

SCDAP/RELAP5 calculates buoyancy-driven circulations within the RV which affect the 

temperature of steam transported into the coolant loops. A SCDAP/RELAP5 sensitivity run was 

performed in which the flow losses within the vessel model were increased so as to reduce the 

flow rates of the RV internal circulations by 50%. The reduced RV circulation rates accelerated 

the core damage process. The SG tube failure margins were seen to be affected by the RV 

internal circulation rates, with the slower circulations resulting in improved margins. 

A.8 Reactor Coolant System Heat Loss 

The base case SCDAP/RELAP5 plant system model represents 4 MW of uniformly-distributed 

heat loss from the outer surfaces of the primary and secondary reactor coolant systems to the 

containment. Sensitivity runs were made with this assumption changed to 2 MW and 8 MW. 

SG tube failure margin results were seen to be moderately affected by the heat loss 

assumption, with higher heat loss leading to reduced margins. An increased heat loss 

preferentially delays the failure of the HLs and surge line with respect to the failures of the SG 

tubes because the heat loss boundary condition is applied directly to the HL and surge line 

structures but not to the SG tube structures. 

A.9 Pressurizer PORV Modeling and Operator Intervention 

A SCDAP/RELAP5 sensitivity run performed assuming that the pressurizer PORVs are blocked 

closed indicated very little effect on the SG tube failure margins. In this run the RCS pressure 

rose to the opening setpoint pressure of the pressurizer SRVs, but otherwise the closed PORVs 

had little effect on the plant response. 

A sensitivity run was also performed to evaluate the plant response to mitigative operator 

intervention. The operators were assumed to depressurize the RCS by opening the pressurizer 

PORVs following the onset of the core heat-up. The results of the sensitivity run demonstrated 

the success of this intervention strategy for mitigating containment bypass during the base case 

SBO severe accident. SG tube failures were prevented by the operator action. The core 

melted and relocated to the RV lower head, and the subsequent failure of the RV lower head 

resulted in a full depressurization of the RCS and a release into the containment. 

A.10 SG Tube Leakage Effects 

A limited investigation was performed into the effects of SG tube leakage (from 

primary-to-secondary). Assumed SG tube leakages of 3.15, 6.31 and 12.6 L/s [50, 100 and 200 
A-3

gpm] were added to the pressurizer-loop SG of the plant model. It is noted that this leakage 

represents a distributed leakage among all of the tubes in the SG and not the leakage 

associated with only one or a few tubes. The model also does not include any effects whereby 

the tube leakage might alter the distribution of hot steam into the hottest tube. The results of the 

SCDAP/RELAP5 sensitivity runs indicated that the tube leakage assumption affects the SG tube 

failure margin, with higher leakage rates leading to reduced margins. 

A.11 Core Bypass Modeling 

A SCDAP/RELAP5 sensitivity run was performed with the assumed core bypass flow due to 

leakage around the slip fit between the core barrel and RV (at the HL nozzle penetrations) 

reduced by 50%. This modeling change was seen to have virtually no effect on the SG tube 

failure margins. 

A.12 Progression of Core Damage 

The SCDAP/RELAP5 Westinghouse four-loop base case calculation indicated that the failure of 

structural components (HL and pressurizer surge line piping and SG tubes) occurs relatively 

early during the core damage and relocation processes of the SBO severe accident sequence. 

The fuel rod cladding oxidation is seen to dramatically increase the core heat load, which in turn 

leads to a rapid heat-up of components throughout the RCS. The structural failures are 

encountered shortly after the time when the oxidation power peaks. Heating of the control rods 

leads to control rod cladding failure and relocation of molten control rod absorber material to the 

RV lower head shortly after the time of the structural failures. Melting and relocation of the core 

fuel to the RV lower head are seen to occur long after the time of the structural failures. Three 

SCDAP/RELAP5 sensitivity runs were performed to evaluate the effects of the core damage 

progression by varying the modeling of the fuel rod oxidation, control rod melting and fuel rod 

melting processes. These sensitivity runs and their results are described as follows. 

At its peak, the fuel rod cladding oxidation power exceeds the fission product decay power by 

an order of magnitude. A sensitivity run was performed in which the peak oxidation power was 

limited to 43% of the peak experienced in the base case run. The results showed that limiting 

the peak oxidation power in this manner tended to slow the RCS system heat-up rate, leading to 

small reductions in the SG tube failure margins. 

A sensitivity run was performed with the control rods removed from the model. Because control 

rod melting behavior occurs after the time of structural failures in the base case run, the 

sensitivity run was instead compared against another sensitivity run in which the control rod 

melting process more affected the results. The results indicated that removing the control rods 

from the model resulted in only slight improvement in the SG tube failure margins. It was 

concluded that the effects of uncertainties related to modeling severe accident control 

rod-related behavior (cladding failure, and melting and relocation of the absorber, cladding and 

guide tube materials) on the key outcome for the containment bypass analyses are small. 

A sensitivity run was performed with a significant variation in a parameter that affects the 

melting and relocation of the core fuel (the fraction of the phase-change heat that must be 

absorbed by the fuel for it to be considered in the molten state). This sensitivity run was 

compared against another sensitivity run in which the fuel rod melting and relocation behavior 

more affected the results than in the base case. The results indicated no change in the SG tube 

failure margins between the two sensitivity runs. It was concluded that the SG tube failure 
A-4

margins are insensitive to variations in the fuel damage progression behavior (including fuel 

melting, flow blockage, re-freezing and relocation). 
B-1

APPENDIX B – ANALYSES TO SUPPORT PRA 

B.1 Introduction and Background 

An extensive series of SCDAP/RELAP5 thermal hydraulic analyses was performed in 2004 and 

2005 to support the PRA and stress/fracture mechanics activities of the Containment Bypass 

Project. These analyses were performed using variations on the base case accident scenario. 

Two sets of PRA support calculations were performed. The first set was performed in 2004 and 

was called the Task 8 PRA Calculations; results from these calculations are summarized in 

Section B.2. The second set was performed in 2005 and was called the Phase 3 Calculations; 

results from these calculations are summarized in Section B.3. References for Appendix B are 

provided in Section B.4. 

B.2 Task 8 PRA Calculation Set, September 2004 

The Task 8 series of 20 SCDAP/RELAP5 simulations for Westinghouse four-loop SBO PRA 

event sequences is documented in Reference B.1. The plant model used for the simulations is 

described in Section 2.6. The base case model featured a 50%/50% split between the hot and 

cold SG tube regions and loss coefficients were adjusted to provide hot and cold mixing 

fractions of 0.81, a recirculation ratio of 2.75 and a total SG power fraction of 30.24%. Prior to 

this series of calculations, the base case accident scenario was assumed to include a stuckopen SG secondary power operated relief valve (PORV) on the pressurizer-loop SG. However, 

in this and subsequent calculation sets, this assumption was replaced with the assumption that 

steam leakage paths, with flow areas of 3.26 cm2

 [0.5 in2], open in each of the four SGs at the 

beginning of the event sequence. 

The Task 8 PRA event sequence definitions are listed in Table B.1 (the base case event 

sequence is shown as Case 69). The SG tube failure margin results from the 20 

SCDAP/RELAP5 simulations are provided in Table B.2. 

The key results from the Task 8 analysis are summarized as follows: 

The effectiveness of operator intervention (opening the pressurizer PORVs) for 

preventing SG tube failure is demonstrated with Cases 21 and 53. Similarly, SG 

tube failure is seen to be avoided with an assumption of a stuck open pressurizer 

PORV which fails to reclose, as seen in Case 83. 

The results obtained when SG secondary depressurization is caused by a 

stuck-open PORV on SG 1 are seen to be the same as when 3.23-cm2

 [0.5-in2] 

steam leakage paths in all four SGs are assumed. See Case 183 vs. Case 69 

and Case 184 vs. Case 72. 

Increasing the assumed RCP shaft seal leakage rate from 1.32 L/s [21 gpm] per 

pump to 3.79 L/s [60 gpm] per pump is shown to result in slightly reduced SG 

tube failure margins, see Case 70 vs. Case 69 and Case 154 vs. Case 153.
B-2

Table B.1 Summary of Assumptions for the Task 8 PRA Event Sequences, 

September 2004 

Case 

No. 

RCP Shaft 

Seal 

Leakage 

or StuckOpen Pzr 

PORV1

Operator 

Action, SG 

Depress. 

before Core 

Damage2

TDAFW 

Runs Until 

Battery 

Depletion3

Valves 

Reclose 

Before 

Core 

Damage4

Operator 

Action, RCS 

Depress. 

After Core 

Damage5

Battery 

Depletion 

Time 

(Valves 

Reclose)6

Steam 

Leakage 

Flow Area 

(in2

/SG) or 

Stuck-Open 

ADV7

21 21 gpm No No N/A 1 PORV, 

TSC 4 hours 0.5 

53 21 gpm No No N/A 2 PORV, 

TSC 4 hours 0.5 

69 21 gpm No No N/A No 4 hours 0.5 

70 60 gpm No No N/A No 4 hours 0.5 

71 180 gpm No No N/A No 4 hours 0.5 

72 480 gpm No No N/A No 4 hours 0.5 

83 1 PORV No No No No 4 hours 0.5 

153 21 gpm Yes Yes N/A No 4 hours 0.5 

154 60 gpm Yes Yes N/A No 4 hours 0.5 

155 180 gpm Yes Yes N/A No 4 hours 0.5 

157 21 gpm No Yes N/A No 4 hours 0.5 

160 480 gpm No Yes N/A No 4 hours 0.5 

161 21 gpm Yes Yes N/A No 8 hours 0.5 

165 21 gpm No Yes N/A No 8 hours 0.5 

177 21 gpm No No N/A No 4 hours 0.1 

178 480 gpm No No N/A No 4 hours 0.1 

179 21 gpm No No N/A No 4 hours 1.0 

180 480 gpm No No N/A No 4 hours 1.0 

183 21 gpm No No N/A No 4 hours ADV 

184 480 gpm No No N/A No 4 hours ADV 

Notes for Table B.1: 

1 - The column headed “RCP Shaft Seal Leakage or Stuck-Open Pzr PORV” indicates the primary system leakage 

assumption. Shaft seal leakages given in gpm are on a per-pump basis. All cases have an overriding assumption 

of 21 gpm per pump shaft seal leakage starting at time zero. For cases with “21 gpm” indicated, the leakage flow 

area does not change during the sequence. For cases where a higher leakage rate is indicated, the leakage flow 

area is assumed to increase accordingly at 13 min into the event sequence. For cases where a stuck-open PORV 

is indicated, the PORV is assumed to stick open at the time of the tenth PORV opening. 

2 - The information shown in the column headed “Operator Action, SG Depress. Before Core Damage” indicates 

whether or not the operators are assumed to intervene by depressurizing the SG secondary systems at 30 min 

into the event sequence. 

3 - The information shown in the column headed “TDAFW Runs Until Battery Depletion” indicates whether or not the 

turbine-driven auxiliary feedwater system is assumed to operate until control is lost at the time when the station 

batteries are depleted. 
B-3

4 - The column headed “Valves Reclose Before Core Damage” only has significance for cases involving a stuck-open 

pressurizer PORV and is listed as not applicable for most of the cases. 

5 - The column headed “Operator Action, RCS Depress. After Core Damage” indicates if the operators are assumed 

to intervene by opening one or two pressurizer PORVs after the core uncovers. An entry of “TSC” indicates that 

the decision to intervene is made by the Technical Support Center, in which case the pressurizer PORVs are 

assumed to be opened 12 min after the time when the core exit steam temperature reaches 922 K [1,200°F]. 

6 - The column headed “Battery Depletion Time (Valves Reclose) indicates the time after the initiation of the event 

sequence when station battery power is lost, resulting in termination of turbine-driven auxiliary feedwater flow (for 

cases where it is active) and the loss of both automatic and operator control over the pressurizer PORVs and 

steam generator secondary PORVs. All PORVs are assumed to fail closed following the time of battery depletion. 

7 - The column headed “Steam Leakage Flow Area or Stuck-Open ADV” indicates the steam leakage flow area 

assumed per steam generator. For cases where “ADV” is indicated, the assumption is that the PORV on Steam 

Generator 1 (in the loop containing the pressurizer) fails open at the beginning of the event sequence and that the 

other steam generators each have the nominal steam leakage flow area of 3.23 cm2

 [0.5 in2]. 
B-4

Table B.2 Summary of SG Tube Failure Margin Results for the Task 8 PRA Event 

Sequences 

Case No. 

Highest Stress Multiplier for which 

Average SG Tube Failure Occurs 

After Pressurizer Surge Line or Hot 

Leg Failure 

Highest Stress Multiplier for which 

Hottest SG Tube Failure Occurs After 

Pressurizer Surge Line or Hot Leg Failure 

21 DNF DNF 

53 DNF 3.5 

69 4.0 1.0 

70 3.5 1.0 

71 DNF DNF 

72 DNF DNF 

83 DNF DNF 

153 3.0 1.0 

154 2.5 < 1.0 

155 6.0 3.5 

157 3.0 1.0 

160 DNF DNF 

161 2.5 1.0 

165 2.5 1.0 

177 4.0 3.5 

178 DNF DNF 

179 4.0 1.0 

180 DNF DNF 

183 4.0 1.0 

184 DNF DNF 

In this table “DNF” indicates that SG tube failure was not calculated until after pressurizer surge line failure, hot leg 

failure or a change in core configuration (melting/refreezing or relocation) for SG tube stress multipliers of 7.5 and 

less. 
B-5

Further increasing the assumed RCP shaft seal leakage rate to 11.36 L/s 

[180 gpm] and 30.28 L/s [480 gpm] per pump at 13 minutes is seen to generally 

remove the SG tube failure potential (for example see Cases 71 and 72 vs. 

Case 69). This finding results because the increased shaft seal leakage rates 

are high enough to reduce the RCS pressure and lower the stress on the tubes 

such that SG tube failure is prevented. Early in the runs with the higher shaft 

seal leak rates, the core is calculated to melt and relocate to the reactor vessel 

lower head (from which failure of the vessel head would result in a release into 

the containment). In none of the Task 8 cases with the higher RCP shaft seal 

leakage rate assumptions did any of the loop seals clear of water. 

B.3 Phase 3 PRA Calculation Set, January 2005 

The Phase 3 series of 23 SCDAP/RELAP5 simulations for Westinghouse four-loop SBO PRA 

event sequences is documented in Reference B.2. The plant model used for this series of 

calculations was the same as that described in the Task 8 simulations in Section B.2 except 

that: (1) the pressurizer surge line connection was moved from the top to the side of Hot Leg 1 

(in some Westinghouse four-loop plants this connection is made on the top of the HL while in 

others it is made on the side of the HL), and (2) based on an analysis of thermal entrance 

effects, a 50% enhancement was made to the HL inside surface convective heat transfer 

coefficient to better represent that heat transfer process. 

The Phase 3 PRA event sequence definitions are listed in Table B.3 (the base case event 

sequence is shown as Case 69). The SG tube failure margin results from the 23 

SCDAP/RELAP5 simulations are provided in Table B.4. 

The key results from the Phase 3 analysis are summarized as follows: 

Moving the pressurizer surge line connection from the top to the side of Hot 

Leg 1 results in lower temperature steam entering the pressurizer surge line than 

was previously the case. This model modification therefore generally leads to 

later surge line failure times. The results shown here for cases not involving 

locked-open pressurizer PORVs (whether by operator action or by failed-open 

assumptions) indicate that the HL failure now generally precedes the surge line 

failure. For cases involving locked-open pressurizer PORVs, the influence of hot 

steam drawn up the surge line by the opened valves generally results in surge 

line failure preceding HL failure, although in certain of these cases (Cases 37, 

185 and 200) other event-timing considerations result in the HL failure still 

preceding the surge line failure. 

The additional energy which passes out of the RCS by assuming that the RCP 

shaft seal leakage rate increases to 11.36 L/s[180 gpm] per pump at 13 minutes 

is seen to generally improve the SG tube failure margins over those where the 

leakage rate is assumed to remain at 1.32 L/s [21 gpm] per pump. This margin 

improvement is seen by comparing the results for Case 39 against Case 37, 

Case 55 against Case 53, and Case 71 against Case 69. 

The assumption of SG secondary side steam leakage significantly reduces the 

SG tube failure margins from those obtained when no leakage is assumed. This 

is seen, for example, by comparing the results from Case 198 (no leakage) and 

Case 69 (3.23-cm2

 [0.5-in2] leakage flow area per SG). SG steam leakage leads 
B-6

to lower SG secondary pressures and less thermal coupling between the outside 

of the SG tube and the steam in the secondary side of the SG. Both of these 

effects increase the potential for SG tube failure. None of the cases where no 

SG steam leakage was assumed resulted in prediction of average or hot SG tube 

failure, even for stress multipliers as high as 7.5. 

Table B.3 Summary of Assumptions for the Phase 3 PRA Event Sequences, 

January 2005 

Case 

No. 

RCP Shaft 

Seal 

Leakage 

or StuckOpen Pzr 

PORV1

Operator 

Action, SG 

Depress. 

before 

Core 

Damage 

(at 30 

min.)2

TDAFW 

Runs Until 

Battery 

Depletion3

PORV 

Recloses 

Before 

Core 

Damage4

Operator 

Action, RCS 

Depress. After 

Core Damage5

Battery 

Depletion 

Time6

Steam 

Leakage 

Flow 

Area 

(in2

)

7

5 21 gpm No No N/A 1 PORV, No 

TSC 4 hours 0.5 

7 180 gpm No No N/A 1 PORV, No 

TSC 4 hours 0.5 

21 21 gpm No No N/A 1 PORV, TSC 4 hours 0.5 

23 180 gpm No No N/A 1 PORV, TSC 4 hours 0.5 

37 21 gpm No No N/A 2 PORVs, No 

TSC 4 hours 0.5 

39 180 gpm No No N/A 2 PORVs, No 

TSC 4 hours 0.5 

53 21 gpm No No N/A 2 PORVs, TSC 4 hours 0.5 

55 180 gpm No No N/A 2 PORVs, TSC 4 hours 0.5 

69 21 gpm No No N/A No 4 hours 0.5 

71 180 gpm No No N/A No 4 hours 0.5 

155 180 gpm Yes Yes N/A No 4 hours 0.5 

159 180 gpm No Yes N/A No 4 hours 0.5 

163 180 gpm Yes Yes N/A No 8 hours 0.5 

167 180 gpm No Yes N/A No 8 hours 0.5 

185 PORV No No Yes No 4 hours 0.5 

192 21 gpm No No N/A 1 PORV, TSC 4 hours None 

198 21 gpm No No N/A No 4 hours None 

199 180 gpm No No N/A No 4 hours None 

200 PORV No No Yes No 4 hours None 

205 180 gpm Yes Yes N/A No 4 hours None 

206 180 gpm No Yes N/A No 4 hours None 

207 180 gpm Yes Yes N/A No 8 hours None 

208 180 gpm No Yes N/A No 8 hours None 
B-7

Notes for Table B.3: 

1 - The column headed “RCP Shaft Seal Leakage or Stuck-Open Pzr PORV” indicates the primary system leakage 

assumption. The shaft seal leakage rate is on a per-pump basis. All cases have an overriding assumption of 

21 gpm per pump shaft seal leakage starting at time zero. For cases with “21 gpm” indicated, the leakage flow 

area does not change during the sequence. For cases where a higher leakage rate is indicated, the leakage flow 

area is assumed to increase to the rate shown at 13 min into the event sequence. For cases where a stuck-open 

PORV is indicated, a single pressurizer PORV is assumed to fail open the tenth time that the valve opens. 

2 - The information shown in the column headed “Operator Action, SG Depress. Before Core Damage” indicates 

whether or not the operators are assumed to intervene by depressurizing the SG secondary systems at 30 min 

into the event sequence. 

3 - The information shown in the column headed “TDAFW Runs Until Battery Depletion” indicates whether or not the 

turbine-driven auxiliary feedwater system is assumed to operate until control is lost at the time when the station 

batteries are depleted. 

4 - The column headed “PORV Re-Closes Before Core Damage” only has significance for the cases involving a 

stuck-open pressurizer PORV and a “Yes” entry indicates that the stuck-open PORV is assumed to re-close when 

the reactor coolant system pressure has declined to 6.89 MPa [1,000 psia]. 

5 - The column headed “Operator Action, RCS Depress. After Core Damage” indicates if the operators are assumed 

to intervene by opening one or two pressurizer PORVs after the core uncovers. An entry of “No TSC” indicates 

that the operators are assumed to immediately open the PORVs at the time when the core exit steam temperature 

reaches 922 K [1,200°F]. An entry of “TSC” indicates that the decision to intervene is made by the Technical 

Support Center, in which case the pressurizer PORVs are assumed to be opened 12 min after the time when the 

core exit steam temperature reaches 922 K [1,200°F]. 

6 - The column headed “Battery Depletion Time” indicates the time after the initiation of the event sequence when 

station battery power is assumed to be lost, resulting in termination of turbine-driven auxiliary feedwater flow (for 

cases where it is active) and the loss of both automatic and operator control over the pressurizer PORVs and 

steam generator secondary PORVs. All PORVs are assumed to fail closed following the time of battery depletion. 

7 - The column headed “Steam Leakage Flow Area” indicates the leakage flow area assumed per steam generator.
B-8

Table B.4 Summary of SG Tube Failure Margin Results for the Phase 3 PRA Event 

Sequences 

Case 

No. 

First RCS 

Component 

Failure 

Highest Stress Multiplier for 

which Average SG Tube 

Failure Occurs After 

Pressurizer Surge Line or Hot 

Leg Failure 

Highest Stress Multiplier 

for which Hottest SG Tube 

Failure Occurs After 

Pressurizer Surge Line or 

Hot Leg Failure 

5 Surge Line DNF 7.0 

7 Surge Line DNF DNF 

21 Surge Line DNF DNF 

23 Surge Line DNF DNF 

37 Hot Leg 1.5 1.0 

39 Surge Line DNF DNF 

53 Surge Line DNF 4.0 

55 Surge Line DNF DNF 

69 Hot Leg 3.5 1.0 

71 Hot Leg 4.5 2.0 

155 Hot Leg DNF 4.5 

159 Hot Leg DNF 3.5 

163 Hot Leg DNF 5.0 

167 Hot Leg DNF DNF 

185 Hot Leg DNF 3.5 

192 Surge Line DNF DNF 

198 Hot Leg DNF DNF 

199 Hot Leg DNF DNF 

200 Hot Leg DNF DNF 

205 Hot Leg DNF DNF 

206 Hot Leg DNF DNF 

207 Hot Leg DNF DNF 

208 Hot Leg DNF DNF 

In this table “DNF” indicates that SG tube failure was not calculated until after pressurizer surge line failure or HL 

failure for SG tube stress multipliers of 7.5 and less. 
B-9

B.4 References for Appendix B 

B.1 C. D. Fletcher (ISL) Letter to C. F. Boyd (NRC), “SCDAP/RELAP5 Zion PRA Calculation 

Set 1, Contract GS-23F-0060L,” September 14, 2004. 

B.2 C. D. Fletcher (ISL) Letter to C. F. Boyd (NRC), “SCDAP/RELAP5 Zion Station Blackout 

Phase III PRA Calculation Set, Contract GS-23F-0060L,” January 18, 2005. 
B-10
C-1

APPENDIX C – EVALUATION OF PRIMARY COOLANT SYSTEM 

ENERGY FLOW 

An analysis of energy balance data was performed for the purpose of understanding the 

distribution and flow of energy in the primary RCS during the SCDAP/RELAP5 extended SBO 

base case calculation described in Section 2.8. The energy balance analysis considers the flow 

of energy into, within, and out of the primary RCS fluid following the time when the core 

uncovers and the system heat-up is in progress. In this analysis, the primary RCS is defined to 

include the fluid in the regions of the RV, HLs, SG inlet and outlet plenums, the interior of the 

SG tubes, RCPs, cold legs, pressurizer and surge line. 

C.1 Energy Balance Model and Analysis Approach 

The RCS fluid was subdivided into the control volume scheme shown in Figure C.1. Table C.1 

summarizes the specific RCS fluid regions contained within each control volume. The 

calculated behavior among the three coolant loops not connected to the pressurizer is virtually 

identical during the calculated event sequence; the RCS fluid in those three loops was lumped 

together for the purposes of the energy balance analysis. 

Because the SCDAP/RELAP5 model nodalization scheme is more detailed than the energy 

balance control volume scheme, the energy balance information for each control volume 

represents a summation of data over the SCDAP/RELAP5 hydrodynamic fluid cells that, when 

combined, make up the control volume regions. Inflows of energy result when fluid flows into a 

control volume and as heat is transferred from structures to the fluid. Outflows of energy result 

when fluid flows out of a control volume and as heat is transferred from the fluid to structures. 

Since the opening and closing of the pressurizer relief valves cause the system fluid flows and 

wall heat transfer rates to oscillate considerably during the SCDAP/RELAP5 calculation, the 

energy balance data was smoothed through integration. 

As would be expected, the energy flow patterns vary over the course of the transient sequence 

as fluid distributions, fluid conditions and the phenomena that dominate the RCS system 

thermal-hydraulic response change. The transient system heat-up period is subdivided into five 

phases for which the RCS energy flows are separately evaluated. The criteria for selecting the 

time periods for the phases and the RCS behavior during each phase are summarized as 

follows: 

Phase 1, Pressurizer Draining (9,222 s - 10,637 s) This phase extends from the time when 

the core uncovers to the time when the pressurizer tank has emptied. During this phase the 

water remaining in the pressurizer at the time of core uncovering drains out of the pressurizer 

and downward through the surge line toward the HL. Superheated steam coming up the surge 

line from the HL tends to vaporize this liquid, which enhances steam production and steam flow. 

The pressurizer PORVs cycle open and closed to limit the RCS pressurization and much steam 

and fluid energy is lost from the RCS through the flow out the pressurizer PORVs. This loss of 

RCS inventory causes the pressurizer level to decline until the tank is empty. Fuel and steam 

temperatures are generally still low and the core power is generated only as a result of the 

fission product decay process. 
C-2

9

14

2 3

11 8 4 6

1

12 13 7

Upper Plenum

& Head

Core

Upper & Lower Hot Leg

Pump & Cold Leg

Downcomer/Lower Plenum

Pressurizer

& Surge

Line

PORVs & Safety

Valves

SG Tubes

(hot & cold)

SG Inlet &

Outlet Plena

Shaft Seal Leakage

Bypass

Remaining Loops Lumped (triple)

Pressurizer Loop (single)

q

q

m

decay heat

oxidation

hydrogen

 

 

10

 

 

A B 5

C

Figure C.1 Control Volume Arrangement for the Energy Balance Analysis 
C-3

Table C.1 Description of Control Volumes for the Energy Balance Analysis 

Control 

Volume 

Number 

RCS Fluid Region 

Included in the 

Control Volume 

Notes 

1 Reactor core Includes heat structures for fuel rods. Heat generation 

considered due to core fission product decay and fuel rod 

metal-water oxidation. 

2 Reactor vessel region 

above the core and 

inside the core barrel 

Includes heat structures for vessel wall and internals in the 

upper head and plenum region. 

3 Coolant Loop 1 hot leg Includes heat structures for hot leg wall. 

4 SG 1 inlet plenum Includes heat structures for tube sheet and plenum wall. 

5 SG 1 tubes The portions of the tubes located inside the tubesheet are 

considered to be part of the inlet and outlet plena. 

The SG 1 tube control volume was separated into three 

sub-control volumes: 5A (Hot average tubes, upwardflowing section), 5B (Hot average tubes, downward-flowing 

section) and 5C (Cold average tubes, upward and 

downward-flowing section). 

6 SG 1 outlet plenum Includes heat structures for tube sheet and plenum wall 

7 Coolant Loop 1 cold leg, 

reactor coolant pump 

and pressurizer spray 

line 

Includes heat structures for the cold leg wall. Fluid exits the 

system via reactor coolant pump shaft seal leak. 

8 Coolant Loop 2/3/4 hot 

leg 

Includes heat structures for hot leg wall. 

9 SG 2/3/4 inlet plenum Includes heat structures for tube sheet and plenum wall 

10 SG 2/3/4 tubes The portions of the tubes located inside the tubesheet are 

considered to be part of the inlet and outlet plena. 

11 SG 2/3/4 outlet plenum Includes heat structures for tube sheet and plenum wall. 

12 Coolant Loop 2/3/4 cold 

legs, reactor coolant 

pumps and pressurizer 

spray line. 

Includes heat structures for the cold leg walls. Fluid exits 

the system via reactor coolant pump shaft seal leaks. 

13 Reactor vessel 

downcomer, lower head 

and lower plenum 

regions 

Includes heat structures for the vessel wall and internals. 

14 Pressurizer tank and 

surge line 

Includes heat structures for the tank and surge line walls. 

Fluid exits the system via flow through the pressurizer 

PORVs and SRVs. 
C-4

Phase 2, Empty System Heat-Up (10,637 s - 13,200 s) This phase extends from the time 

when the pressurizer has emptied until the time when the system heat-up causes the fuel rod 

oxidation rate to increase to the point where the core power is produced roughly equally by 

fission product decay and fuel rod oxidation. During this phase the pressurizer has completely 

drained and the RCS (except for the loop seals and the RV lower plenum and head) is filled with 

vapor. The pressurizer PORVs continue to cycle open and closed. Fuel temperatures, steam 

temperatures and the fuel rod oxidation power are all rising. 

Phase 3, Peak Fuel Rod Oxidation (13,200 s - 13,475 s) This phase extends from the time 

when the core power is produced roughly equally by fission product decay and fuel rod 

oxidation, through the peak in the oxidation rate and up to the time when the first significant 

structural failure is encountered. The failure time for the hottest SG tube structure with a stress 

multiplier of 1.0 was selected as the end time for this phase. Except for the loop seals and the 

RV lower plenum and head, the RCS is filled with a mixture of steam and hydrogen, which is 

released by the oxidation process. The pressurizer PORVs continue to cycle open and closed. 

Fuel and steam temperatures are now rising more rapidly. During this phase the core power is 

dominated by the fuel rod oxidation process, not by the fission product decay. The oxidation 

power peaks at about 11.2 times the fission decay power and then begins to fall as the cladding 

is consumed. A key feature of this phase is that the heat produced by the oxidation process 

tends, at first, to be retained locally in the fuel rods and core regions of the RCS. 

Phase 4, Structure Failure (13,475 s – 14,590 s) The time period for this phase includes the 

failure times for all remaining significant structures: HLs, pressurizer surge line and average SG 

tubes with stress multipliers lower than 3.0. The failure time for the average SG tube with a 

stress multiplier of 1.0 was used as the end time for this phase. Except for the loop seals and 

the RV lower plenum and head, the RCS is filled with a mixture of steam and hydrogen. Before 

14,400 s (four hours, the assumed station battery depletion time), the pressurizer PORVs 

continue to cycle open and closed, but less frequently during this phase than during the earlier 

phases. The fuel rod oxidation power continues to decline and during this phase the core power 

is produced roughly equally by the fission product decay and fuel rod oxidation processes. A 

key feature of this period is that the heat that had built up in excess in the fuel and core regions 

during the rapid peak of the oxidation process is carried by the flow of the RCS fluid outward 

into the coolant loops. It is the arrival of this excess heat in the loop components which quickly 

drives the structure temperatures upward, leading to their failure. 

Phase 5, Post-Structure Failure (14,590 s – 15,500 s) This phase extends from the time 

when the average SG tube with a 1.0 stress multiplier fails up until the time when molten control 

rod absorber is relocated to the RV lower head. The pressurizer PORVs are no longer 

functional because the station batteries are assumed to be depleted. The fuel rod oxidation 

power remains low and is only a very small portion of the total core power. The system fluid 

and structure temperatures (which had risen in order to remove the excess core power 

produced during the peak oxidation phase) are roughly at the levels which are needed to 

remove the now-lower core power. This effect causes the fluid and structure temperatures to 

generally stop rising and level off during this phase of the accident sequence. The energy 

analysis is truncated at 15,500 s because afterward the RCS energy balance is controlled by 

the relocation of large quantities of molten materials (control rod absorber and fuel rods) which 

cause significant changes in the RCS configuration. 
C-5

C.2 Results of RCS Energy Flow Analysis 

The behavior of the energy flows into, within and out of the RCS are summarized as follows. 

Figures C.2 through C.10 show the transient behavior of the various energy flow terms. The 

data points shown with the triangle symbols in these figures are located in the middle of the 

periods for the five phases and represent the average integrated energy flow during each 

phase. The data points are joined with solid lines in the figures only for clarity. 

Figure C.2 shows the average total core power resulting from fission product decay heat and 

fuel rod oxidation heat. The data for the first two phases represents the fission product decay 

power, prior to the onset of significant fuel rod oxidation. The increase seen in the third phase 

results from the acceleration and peaking of the fuel rod oxidation process. During the fourth 

and fifth phases the oxidation process is mostly complete and the core power is once again 

dominated by the fission product decay heat, which declines as a function of time after reactor 

trip. 

Figures C.3 and C.4, respectively, portray the percentages of the integrated total core power 

that are retained in the fuel and transferred to the core fluid. The figures show that, except 

during the peak in the oxidation process in Phase 3, about 20% of the core heat is retained in 

the fuel and about 80% of the core heat is transferred to the fluid in the core. The spike in total 

core power during the peak oxidation period causes these percentages to significantly change, 

with about 60% of the core heat retained locally in the fuel (where the oxidation process 

deposits it) and only about 40% of the core heat transferred to the core fluid. Subsequent to the 

oxidation peak during Phase 3, the passage of time allows the “excess” oxidation heat which 

had built up in the fuel to flow into the core fluid and from there to be distributed throughout the 

RCS. 

Figure C.5 shows the integrated changes in the RV fluid energy expressed as a percentage of 

the integrated total core power (negative values indicate a loss of fluid energy). During 

Phases 1 and 2, the negative vessel energy inventory change is caused by the loss of liquid 

mass from the RV as the core fluid is boiled off and the downcomer level declines. The small 

positive changes seen in Phases 3 through 5 reflect an increase in vessel fluid energy resulting 

from heating the vessel fluid to very high temperatures and releasing high-energy hydrogen 

from the fuel rod oxidation process directly into it. 

Figure C.6 shows the integrated changes in the pressurizer fluid energy expressed as a 

percentage of the integrated total core power. The figure reflects the rapid loss of liquid from 

the pressurizer as it empties due to draining during Phase 1 and the passing of liquid and steam 

through the PORVs when those valves open to limit the RCS pressurization during Phases 1 

through 4. The PORVs fail closed after the station batteries are assumed to be depleted at 

four hours (14,400 s). During Phase 5 this figure therefore reflects a situation where the PORVs 

no longer cycle open and closed and the pressurizer region is stagnant and vapor-filled. 

Figure C.7 shows the integrated changes in the fluid energy for RCS regions other than the RV 

and pressurizer expressed as a percentage of the integrated total core power. For Phase 1, the 

figure reflects the loss of liquid mass from the hot and cold legs as the liquid remaining at the 

time of core uncovering drains into the RV or is swept out of the RCS through the pressurizer 

PORVs. During Phases 2 through 4, the HL, SG primary and cold leg regions of the plant are 

vapor-filled and the small negative energy changes seen in the figure reflect a loss of vapor 

mass as the fluid temperatures increase. The fluid becomes hotter and its specific energy 
C-6

8000 10000 12000 14000 16000

Time (s)

0

50

100

150

200

Average Total Core Power (MW)

Figure C.2 Average Total Core Power Generated During the Five Phases of the SBO 

Accident Heat-Up Period 

8000 10000 12000 14000 16000

Time (s)

0

20

40

60

80

Portion of Integrated Core Power (%)

Figure C.3 Portion of the Integrated Core Power Retained in the Fuel During the Five 

Phases of the SBO Accident Heat-Up Period 
C-7

8000 10000 12000 14000 16000

Time (s)

20

40

60

80

100

Portion of Integrated Core Power (%)

Figure C.4 Portion of the Integrated Core Power Transferred to the Core Fluid During 

the Five Phases of the SBO Accident Heat-Up Period 

8000 10000 12000 14000 16000

Time (s)

−60

−40

−20

0

20

Energy Change as % of Integrated Core Power

Figure C.5 Change in Reactor Vessel Fluid Energy During the Five Phases of the SBO 

Accident Heat-Up Period 
C-8

8000 10000 12000 14000 16000

Time (s)

−20

−15

−10

−5

0

5

10

Energy Change as % of Integrated Core Power

Figure C.6 Change in Pressurizer Fluid Energy During the Five Phases of the SBO 

Accident Heat-Up Period 

8000 10000 12000 14000 16000

Time (s)

−30

−20

−10

0

Energy Change as % of Integrated Core Power

Figure C.7 Change in Fluid Energy in RCS Regions Other Than the Reactor Vessel and 

Pressurizer During the Five Phases of the SBO Accident Heat-Up Period 
C-9

becomes higher, but its density becomes lower and the net result is a lower absolute fluid 

energy. 

Figure C.8 shows the integrated flow of energy out of the RCS by way of the pressurizer PORVs 

and RCP shaft seal leaks expressed as a percentage of the integrated total core power. In this 

figure, negative values indicate a flow of energy out of the RCS. The figure indicates a high rate 

of energy flow out of the RCS during Phase 1, followed by successively smaller energy flows 

during Phases 2 through 5. The high rate of RCS energy loss during Phase 1 reflects a 

continued high rate of steam production prior to the time when the core completely empties of 

liquid. Opening of the pressurizer PORVs causes liquid in the core to flash and the steam 

produced requires the PORVs to cycle frequently and remain open for extended periods in order 

to control the RCS pressure. After the core dries out near the end of Phase 1, the core steam 

production rate falls, the PORVs cycle open less frequently and remain open for shorter periods. 

The reduced rates of RCS energy loss for Phases 2, 3 and 4 reflect this lowered demand on the 

pressurizer PORVs. The station batteries are depleted prior to the start of Phase 5 and the 

small negative RCS energy loss seen in the figure results solely from the RCP shaft seal 

leakage. 

8000 10000 12000 14000 16000

Time (s)

−150

−100

−50

0

Energy Flow Rate as % of Core Power

Figure C.8 Integrated Flow of Energy Through the Pressurizer PORVs and Reactor 

Coolant Pump Shaft Seal Leaks During the Five Phases of the SBO 

Accident Heat-Up Period 
C-10

Figure C.9 shows the integrated flow of heat from the tubes of the four SGs to the fluid inside 

the tubes expressed as a percentage of the integrated total core power. In this figure, negative 

values represent transfer of heat from the fluid inside the SG tubes to the tube inner wall 

surface. The figure shows data only for the heat transferred between the tube wall and the fluid; 

heat transferred between the fluid and other SG structures (the walls of the spherical inlet and 

outlet plenum walls, the plenum divider plate and the tubesheet) is not included here. The 

figure shows that, except for the peak oxidation period when much heat initially stays in the fuel, 

the portion of the total core heat which flows to the SG tubes is relatively stable at between 

about 13% and 23%. 

Figure C.10 shows the integrated flow of heat from all RCS structures other than SG tubes to 

the fluid inside the RCS expressed as a percentage of the integrated total core power. In this 

figure, negative values represent transfer of heat from the fluid to the structures. The structures 

represented by this data include the RV cylindrical wall and spherical upper and lower head 

walls, RV internals (core barrel, support plates, columns, etc.), HL, cold leg and pressurizer 

surge line pipe walls, the pressurizer tank wall, steam generator spherical inlet and outlet 

plenum walls and the SG tubesheets. When compared with the very thin SG tube structures 

which have a large heat transfer area, these structures are in general very thick, but with much 

smaller heat transfer areas. The figure shows that prior to the peak fuel rod oxidation period the 

portion of the total core heat which flows to these structures is between about 20% and 40%. 

After the peak fuel rod oxidation period, this percentage increases to about 55%. The increase 

reflects: (1) the close proximity of the thick RV heat structures to the hot vapor in the core and 

(2) the massive heat sinks provided by these thick-wall heat structures in general. 

Regarding the effectiveness of heat sinks provided by the thick-wall structures, a key feature of 

the SBO transient event sequence is that vapor temperatures are for the most part continuously 

increasing. Consider first a situation where structures might be subjected to a large 

step-change increase in fluid temperature, but where the fluid temperature is held constant 

afterward. In that situation, heat flows from the fluid into the colder wall, but the temperature 

increase that is induced in the wall near the surface tends to restrict the subsequent flow of heat 

into the wall. The fluid-wall heat transfer process becomes limited by conduction heat transfer 

within the wall. Now consider the situation we have here, where the vapor temperatures 

continuously increase. The heat transfer process still induces a temperature increase in the 

wall near the surface. But, because the vapor temperatures continue increasing, the 

fluid-to-wall differential temperature remains high and wall heat sink remains very effective. 
C-11

8000 10000 12000 14000 16000

Time (s)

−25

−20

−15

−10

−5

Energy Flow Rate as % of Core Power

Figure C.9 Integrated Heat Transfer Rate from SG Tubes to Fluid During the Five 

Phases of the SBO Accident Heat-Up Period 

8000 10000 12000 14000 16000

Time (s)

−60

−50

−40

−30

−20

−10

Energy Flow Rate as % of Core Power

Figure C.10 Integrated Heat Transfer Rate from All Structures (Except SG Tubes) to 

Fluid During the Five Phases of the SBO Accident Heat-Up Period 
C-12
D-1

APPENDIX D - ESTIMATES OF UNCERTAINTIES IN THE 

SCDAP/RELAP5 SIMULATIONS 

Analyses were performed to estimate the uncertainties in the SCDAP/RELAP5 output 

parameters of key importance for the containment bypass application. These analyses are 

summarized here and are fully documented in Reference 2.20. The key output parameters 

(temperatures, heat transfer coefficients and SG tube failure margins) listed in Section 2.7.2 

represent the dependent variables for the uncertainty study. The independent variables for the 

uncertainty study are discussed in Section 2.7.3 and are summarized in Table 2.1. The 

SCDAP/RELAP5 Westinghouse four-loop plant SBO base case calculation described in 

Section 2.8 was used as the base case run for the uncertainty analysis. 

Section D.1 identifies the SCDAP/RELAP5 sensitivity cases. Model features representing the 

independent variables are varied around the nominal conditions that were assumed in the base 

case calculation. The SCDAP/RELAP5 sensitivity case calculations are then performed and the 

results of the sensitivity and base case calculations are compared in Section D.2. The 

deviations in the dependent variables between the base and sensitivity cases are calculated 

and used to estimate the uncertainties in the dependent variables as described in Section D.3. 

The uncertainty estimates are summarized in Section D.4. References pertinent to this 

appendix are provided in Section D.5. 

D.1 Selection of Sensitivity Cases 

Section D.1.1 describes the specific forms (locations, evaluation times, smoothing 

processes, etc.) used for each of the dependent variables. Section D.1.2 describes the 

selection of the sensitivity cases, including descriptions of the SCDAP/RELAP5 modeling 

feature revisions implemented and justifications for the ranges of the variations investigated. 

D.1.1 Specific Forms of the Dependent Variables 

The locations selected for evaluation of the dependent variable SCDAP/RELAP5 output are 

those where the fluid conditions important for structural failure considerations are the most 

limiting. For the HLs, the most limiting location is in the upper section of Hot Leg 1, adjacent to 

the RV. For the pressurizer surge line, the most limiting location is at the HL end of the surge 

line. For the steam generator tubes, the most limiting locations are for the hot average tube and 

hottest tube, just above the tubesheet in SG 1. 

Since the SCDAP/RELAP5-calculated output variables are functions of time, for the purpose of 

comparing results among many similar runs, it is necessary to: (1) smooth the output in time to 

remove the oscillatory behavior related to opening and closing of the pressurizer relief valves 

and (2) use an evaluation-time selection criterion that can adjust for the effects of event 

sequence timing differences among the runs. 

The failures of the HL, surge line and SG tube structures are tightly clustered within a short 

period (of about 500 s) following the time of the peak in the fuel rod oxidation rate. The lack of 

adequate cooling for the core fission product decay heat results in a slow system heat-up prior 

to the onset of fuel rod oxidation. But it is the core power spike resulting from fuel rod oxidation 

which dramatically increases the system heat-up rate, causing the structural failures to be so 

tightly clustered. 
D-2

The structural failures of the HLs, surge line and SG tubes occur subsequent to the oxidation 

peak because time is required to transport the increasingly-hotter steam from the core through 

the HLs and out into the surge line and SGs (see the discussion of the RCS energy flow in 

Section 2.8 and Appendix C). Key aspects of the problem are therefore related to: (1) the core 

power and core heat-up rate, (2) the rates at which heat is carried away from the core and 

through the various RCS flow paths, (3) the proximity of the structures with respect to the core 

and (4) the structure geometries and materials which determine the temperatures at which the 

structures fail. The essence of the problem is whether the critical effects of the 

rapidly-increasing steam temperatures are felt in the HL and surge line structures before they 

are felt in the SG tube structures. Based on this discussion and results of the base case 

calculation, the specific forms of the dependent variables used for the uncertainty analysis were 

selected as follows: 

Average SG Tube Failure Margin

The average SG tube failure margin is represented by the tube stress multiplier (1.0 or greater) 

that results in SG tube failure coincident with the earliest RCS piping failure. The failure margin 

values are calculated by interpolating the failure time data for the HL and SG tube structures. 

Hottest SG Tube Failure Margin

The hottest SG tube failure margin is also represented by the tube stress multiplier that results 

in SG tube failure coincident with the earliest RCS piping failure. However, for cases in which 

the hottest tube is predicted to fail prior to the HL and pressurizer surge line even when a 1.0 

tube stress multiplier is applied, the hottest tube failure margin is instead expressed as the time 

interval by which hottest tube failure precedes the earlier of the HL or surge line failures. The 

time interval is expressed in negative seconds, indicating that the non-degraded hottest tube 

failure margin is negative. 

Average and Hottest SG Tube Metal Temperatures

The average and hottest SG tube metal temperatures represent the smoothed (100-s lag) 

values for the average temperatures (across the tube wall thickness) at the time of the earliest 

RCS piping failure. The data are taken for the first axial SG tube heat structure above the top of 

the tubesheet in SG 1, where the tube temperatures are the highest. The time of earliest RCS 

piping failure was selected for the evaluation time because the SG tube failure margins are most 

affected by the relative relationships between the SG tube and RCS piping wall temperatures as 

the failure conditions for both structures are approached. 

Hot Leg Steam Temperature and Wall Inside-Surface Heat Transfer Coefficient

The HL steam temperature and wall inside-surface heat transfer coefficient represent smoothed 

(100-s lag) values for those parameters 100 s after the time of the peak in the fuel rod oxidation 

rate. The data are taken for the first axial cell (adjacent to the RV) in the upper section of 

Hot Leg 1, where the HL temperature is the highest. The evaluation time was selected because 

it is the time when the rate of increase in the smoothed steam temperature is the highest. 

For the HL upper section, the wall inside surface heat transfer in the model represents a 

combination of convection from steam to the wall, radiation from steam to the wall and radiation 

from the wall to the opposing wall surfaces of the lower HL section. Both the differential 

temperature and the direction of the heat flow for the wall-to-wall radiation heat transfer process 
D-3

are different from those for the two steam-to-wall heat transfer processes, and this complicates 

the calculation of a single, effective HL inside-wall heat transfer coefficient. For the purposes of 

the uncertainty evaluation, the effective total heat transfer coefficient is calculated by dividing 

the total wall heat flux (the net from all three of the heat transfer processes) by the differential 

temperature between the steam and HL upper section wall inside surface. 

Pressurizer Surge Line Steam Temperature and Wall Inside-Surface Heat Transfer Coefficient

The pressurizer surge line steam temperature and wall inside-surface heat transfer coefficient 

represent smoothed (100-s lag) values for those parameters 100 s after the time of the peak in 

the fuel rod oxidation rate. The data are taken for the axial cell of the surge line adjacent to 

Hot Leg 1, where the surge line temperature is the highest. The evaluation time was selected 

because it is the time when the rate of increase in the smoothed steam temperature is the 

highest. 

D.1.2 Selection and Implementation of the Independent Variable Modeling Revisions 

Table D.1 identifies the sensitivity cases needed to evaluate variations in the independent 

variables for the uncertainty study as suggested by the PIRT, and summarizes the model 

feature revisions that implement those variations into the model. Table D.2 provides a concise 

list of all sensitivity cases run, including those cases used in the uncertainty study and additional 

cases which were run to address various other issues. Information regarding the selection of 

the cases, the exclusion of others, the modeling revisions and the justifications for the ranges of 

variables evaluated is described as follows. 

A1 Full loop circulation (loop seal clearing and reactor vessel lower plenum clearing)

An important underlying assumption of the analysis is that the loop seals in all coolant loops 

remain plugged with water. If this is not the case, then superheated steam flow in the normal 

direction around the coolant loops will cause the SG tubes to fail before the HL or surge line. 

The PIRT considered this a binary parameter: either all loop seals remain water plugged or 

one-or-more do not. Prior analysis for the Westinghouse plant has indicated that the margin to 

loop seal clearing is very large; therefore, no sensitivity runs were identified. 

A2 Pressurizer Behavior (phase separation, PORV flow, CCFL and draining, spray nozzle 

venting)

Spray Nozzle Venting Effects 

Based on PIRT recommendation, representations of the spray lines and valves were added to 

the base case model. This model revision was found to result in slightly faster pressurizer 

draining but no other significant effects. The base case model now better represents the plant 

configuration and no sensitivity runs related to spray nozzle venting were identified. 
D-4

Table D.1 Summary of Sensitivity Runs Implementing Variations in the Uncertainty 

Study Independent Variables 

Independent 

Variable 

Notes Regarding Implementing 

Variations into the Model 

Sensitivity Runs 

Identified to Support the 

Uncertainty Study 

A1 

Full loop 

circulation (loop 

seal clearing and 

reactor vessel 

lower plenum 

clearing) 

An underlying assumption of the analysis is 

that the loop seals in all four loops will 

remain plugged with water, setting up 

circulating flow patterns in the hot leg and 

SG tube regions. Prior analysis indicates 

that significant margin to loop seal clearing 

exists. The uncertainty that the loop seals 

will not remain plugged is very small. 

None 

A2 

Pressurizer 

Behavior (phase 

separation, PORV 

flow, CCFL & 

draining, spray 

nozzle venting) 

Spray nozzle venting effects 

CCFL and draining 

Phase separation in the tank 

Relief valve critical flow 

In the base case run, the pressurizer 

PORVs and safety relief valves are 

modeled with flow areas that are sized to 

deliver the rated flow at the rated upstream 

pressure condition. Variations in valve flow 

area account for uncertainties in modeling 

the critical flow process and in simulating 

the fluid conditions at the valve inlets. 

None 

None 

None 

Run 1A 

+30% Valve Flow Area 

Run 1B 

-30% Valve Flow Area 
D-5

Table D.1 Summary of Sensitivity Runs Implementing Variations in the Uncertainty 

Study Independent Variables 

Independent 

Variable 

Notes Regarding Implementing 

Variations into the Model 

Sensitivity Runs 

Identified to Support the 

Uncertainty Study 

A3 

Mixing, SG inlet 

plenum 

Variations in the target values for the hot 

leg discharge coefficient, recirculation ratio 

and hot/cold mixing fraction will be 

evaluated. 

The nominal values for the mixing 

parameters in the SCDAP/RELAP5 base 

case run are: 

Hot Leg CD = 0.12 

Recirculation Ratio = 2.0 

Hot and Cold Mixing Fraction = 0.85 

Hot/Cold Tube Split = 41%/59% 

The SG inlet plenum flow coefficients will be 

readjusted so as to attain the desired target 

value for the parameter that is varied while 

maintaining the base case target values for 

the other parameters. 

Run 2A 

Hot Leg CD = 0.138 

Run 2B 

Hot Leg CD = 0.102 

Run 2C 

Recirculation Ratio = 2.3 

Run 2D 

Recirculation Ratio = 1.7 

Run 2E 

Mixing Fraction = 0.95 

Run 2F 

Mixing Fraction = 0.75 

Run 2G 

Hot/Cold Tube Split = 

50%/50% 

A4 

SG tube outer wall 

heat transfer (SG 

secondary side 

heat transfer) 

In the sensitivity runs, multipliers are 

applied to the SG tube outer wall heat 

transfer coefficient. 

Run 3A 

Tube Outer Wall HTC x 

5.0 

Run 3B 

Tube Outer Wall HTC x 

0.5 

A5 

Buoyancy-driven 

flows in SG tubes 

(ratio of SG tube 

flow to hot leg 

flow) 

In the model, the calculated recirculation 

ratio represents the relationship between 

the SG tube and hot leg flows. 

Variations in the target 

recirculation ratio are 

evaluated in Sensitivity 

Runs 2C and 2D (see 

PIRT Parameter A3 

above). 
D-6

Table D.1 Summary of Sensitivity Runs Implementing Variations in the Uncertainty 

Study Independent Variables 

Independent 

Variable 

Notes Regarding Implementing 

Variations into the Model 

Sensitivity Runs 

Identified to Support the 

Uncertainty Study 

B1 

Core power, 

especially fuel rod 

cladding oxidation 

power 

Fission product decay power 

Oxidation power 

Implement into model by adding or 

subtracting heat from the core fluid at rates 

that are fixed percentages of the codecalculated oxidation power 

None 

Run 4A 

Oxidation power x 1.2 

Run 4B 

Oxidation power x 0.5 

B2 

Buoyancy-driven 

flow in vessel 

(includes effects of 

vessel internal 

flow resistances) 

Artificial increases and decreases in the 

input flow losses are made in the axial and 

crossflow vessel internal junctions to 

account for uncertainties related to 

predicting buoyancy-driven flows and 

friction losses at very low flow rates. 

Run 5A 

50% decrease in internal 

vessel flow 

Run 5B 

100% increase in internal 

vessel flow 

B3 

Buoyancy-driven 

flow in hot legs 

This parameter is represented in the model 

by the calculated hot leg discharge 

coefficient, CD, which relates the hot leg 

flow to the densities of the hot and cold 

fluids. 

Variations in the target hot 

leg discharge coefficient 

are evaluated in Sensitivity 

Runs 2A and 2B (see 

PIRT Parameter A3 

above). 

B4 

RCS heat loss to 

containment 

The base case model assumes a nominal 4 

MW heat loss from the RCS to containment 

at full-power normal operating conditions. 

The heat loss is implemented by applying a 

constant heat transfer coefficient on the 

outer surfaces of the RCS piping and vessel 

heat structures. For the sensitivity cases 

the base case heat transfer coefficient is 

multiplied by 0.5 and 2.0. 

Run 6A 

2 MW total RCS heat loss 

at full power conditions 

Run 6B 

8 MW total RCS heat loss 

at full power conditions 

B5 

Mixing at the 

vessel-to-hot leg 

connection 

SCDAP/RELAP5-calculated flow patterns in 

the region of this connection are physical 

and consistent with NRC CFD simulations. 

Therefore, no sensitivity runs are identified. 

None 
D-7

Table D.1 Summary of Sensitivity Runs Implementing Variations in the Uncertainty 

Study Independent Variables 

Independent 

Variable 

Notes Regarding Implementing 

Variations into the Model 

Sensitivity Runs 

Identified to Support the 

Uncertainty Study 

C1 

Operator 

intervention (event 

sequence 

definition item) 

Operator intervention involves recognizing 

the event sequence signature and 

depressurizing the primary and secondary 

systems according to procedures. 

Sensitivity studies evaluating operator 

intervention were previously performed; no 

new sensitivity runs are identified. 

None 

C2 

RC pump seal 

leakage (event 

sequence 

definition item) 

The base case model includes flow areas 

for the pump shaft seals that initially pass 

21 gpm/pump into the containment. For the 

sensitivity run, the flow areas are scaled up 

for the higher assumed leak rate. The 

uncertainty study assumes a +20 gpm 

simulation uncertainty for pump shaft seal 

leakage and only a 61 gpm/pump sensitivity 

case is needed for the generation of 

statistics for the uncertainty study. Note 

that sensitivity runs not used for the 

uncertainty study are identified to 

investigate other higher pump shaft seal 

leakage rates, See Table D.2. 

Run 7A 

Leak rate increases to 

61 gpm/pump at 2 hours 

(Interpolation between this 

run and the base case is 

used to provide results for 

a 41 gpm/pump leak rate 

assumption). 

Run 7G 

Leak rate decreases to 

1 gpm/pump at 2 hours 

(Note that discussions of 

additional pump seal 

leakage sensitivity runs, 

unrelated to the 

uncertainty study, are 

included in Section D.2.2, 

see Cases 7B, 7C, 7D, 7E, 

7F and 7F2.) 

C3 

SG tube leakage 

(event sequence 

definition item) 

Preexisting SG tube leakage conditions 

were evaluated in a prior sensitivity study. 

No sensitivity runs are needed to support 

the uncertainty study. However a tube 

leakage sensitivity run not used for the 

uncertainty study is identified, see Table 

D.2. 

None 

(Note that discussion of an 

additional SG tube leakage 

sensitivity run, unrelated to 

the uncertainty study, is 

included in Section D.2.2, 

see Case 8C.) 
D-8

Table D.1 Summary of Sensitivity Runs Implementing Variations in the Uncertainty 

Study Independent Variables 

Independent 

Variable 

Notes Regarding Implementing 

Variations into the Model 

Sensitivity Runs 

Identified to Support the 

Uncertainty Study 

C4 

Surge line 

orientation (plant 

configuration item) 

The configuration of the surge line and the 

location of its hot leg connection are fixed 

(the connection is made on the side of hot 

leg). No sensitivity runs are identified to 

support the uncertainty study. However a 

sensitivity run, not used for the uncertainty 

study, which evaluates the effects of 

relocating the surge line connection to the 

top of the hot leg is identified, see 

Table D.2. 

None 

(Note that discussion of an 

additional surge line 

configuration sensitivity 

run, unrelated to the 

uncertainty study, is 

included in Section D.2.2, 

see Case 8A.) 

C5 

Distribution of 

metal mass in the 

plant (plant 

configuration item) 

The distribution of metal mass in a plant is 

fixed. No sensitivity runs are identified. 

None 

Table D.2 List of Sensitivity Calculations 

Case 

Number* Sensitivity Calculation Description 

Base Case Nominal: pressurizer relief valve areas, oxidation model, hot leg and surge line 

inside wall HTCs, SG tube outer wall HTC, vessel internal circulation. No 

stuck-open SG relief valves or tube leakage. Surge line connects to side of 

Hot Leg 1. Hot Leg CD=0.120, recirculation ratio=2.0, hot/cold mixing 

fractions=0.85, hot/cold tube split=41%/59%, RCP seal leakage=21 

gpm/pump, steam leak area per SG=0.5 in2

, total RCS heat loss=4 MW. 

1A Pressurizer PORV and SRV valve flow areas increased by 30% 

1B Pressurizer PORV and SRV valve flow areas decreased by 30% 

2A Hot Leg CD increased to 0.138 

2B Hot Leg CD decreased to 0.102 

2C Recirculation ratio increased to 2.3 

2D Recirculation ratio decreased to 1.7 

2E Hot and cold mixing fractions increased to 0.95 

2F Hot and cold mixing fractions decreased to 0.75 

2G Hot/cold tube split ratio changed to 50%/50% 

3A SG tube outer wall HTC x 5.0 

3B SG tube outer wall HTC x 0.5 

4A Oxidation power x 1.2 
D-9

Table D.2 List of Sensitivity Calculations 

Case 

Number* Sensitivity Calculation Description 

4B Oxidation power x 0.5 

5A 50% decrease in reactor vessel internal circulation flow rates 

5B 100% increase in reactor vessel internal circulation flow rates 

6A 2 MW total RCS heat loss 

6B 8 MW total RCS heat loss 

7A RCP shaft seal leak rate increases to 61 gpm/pump at 2 hours 

7B* RCP shaft seal leak rate increases to 300 gpm/pump at 2 hours 

7C* RCP shaft seal leak rate increases to 182 gpm/pump at 2 hours 

7D* RCP shaft seal leak rate increases to 120 gpm/pump at 2 hours 

7E* RCP shaft seal leak rate increases to 90 gpm/pump at 2 hours 

7F* RCP shaft seal leak rate increases to 300 gpm in Loop 1 pump at 2 hours 

7F2* RCP shaft seal leak rate increases to 300 gpm in Loop 2 pump at 2 hours 

7G RCP shaft seal leak rate decreases to 1 gpm/pump at 2 hours 

8A* Pressurizer surge line connection moved to top of hot leg 

8B* Stuck open PORV on SG 1, no leakage from SG secondary in the other 3 SGs

8C* 100 gpm assumed tube leakage in SG 1, Coolant Loop 1 flow parameters 

adjusted to attain 0.14 hot leg CD, 1.75 recirculation ratio and 0.75 mixing 

fractions 

8D* Surge line and hot leg upper section inside wall HTCs x 2.0 

8E* Tubesheet HTC x 2.0 

8G* SG steam leakage flow areas of 0.4, 0.3, 0.2 and 0.1 in2 (one run with different 

leak area in each SG to determine minimum leak rate needed to depressurize 

SGs by the time of hot leg failure) 

* Runs marked with an asterisk are not used for the statistical evaluation of uncertainties, only for evaluating various 

other issues. 

CCFL and Draining 

The PIRT recommended that the effects of CCFL behavior on the pressurizer draining process 

be evaluated. A previous study investigated variations in CCFL parameters at the tank-to-surge 

line connection and found that the effects of those variations were small (Reference D.1). The 

PIRT also recommended that the possibility for CCFL limiting as a result of hydraulic jump 

conditions forming at elbows between vertical and horizontal sections of the surge line be 

evaluated. Papers describing this situation were obtained and the SCDAP/RELAP5 calculated 

surge line conditions were evaluated. It was found that the calculated steam flow from the HL 

into the surge line is so highly superheated that significant flow of liquid from the pressurizer 

tank into the HL is prevented. Liquid that enters the surge line from the bottom of the tank is 

vaporized as it drains into the surge line, creating single-phase steam and droplet flow regimes 

inside the surge line, depending on whether pressurizer relief valves are open or closed. The 

vaporization of liquid cools the steam inside the surge line and thereby delays the start of the 

heat-up of the surge line wall until after the completion of pressurizer draining. These 
D-10

evaluations indicated that pressurizer draining is controlled by CCFL at the tank-to-surge line 

connection and that the conditions that could result in hydraulic- jump effects within the surge 

line are not present. No sensitivity runs related to surge line CCFL effects were identified. 

Phase Separation in the Tank 

The upward flow of steam through the pressurizer and out the relief valves can support a frothy 

mixture inside the pressurizer tank. If the froth level is at the top of the tank, then the relief valve 

flow is a two-phase mixture of water and steam. When the froth level has dropped below the 

top of the tank, then the relief valve flow is single-phase steam, potentially with entrained liquid 

droplets. The SCDAP/RELAP5 interphase drag models determine the distribution of steam in 

the tank and the mixture level. The pressurizer fluid conditions during the pressurizer draining 

period in the base case calculation were evaluated in order to determine the interphase drag 

models that are most important for this event sequence. For periods when the pressurizer relief 

valves are open, slug flow is seen in the bottom of the tank and mist flow is seen in the upper 

regions of the tank. For periods when the relief valves are closed, vertically-stratified and 

bubbly flows are seen in the bottom of the tank and mist flow is seen in the upper regions of the 

tank. Therefore, interphase drag models for the bubbly and slug flow regimes are of most 

interest for simulating the tank mixture level. 

To evaluate the sensitivity of results to variations in the interphase drag models, a check run 

was made in which the hydraulic diameter for the pressurizer tank was reduced by a factor of 

5.0 from the actual tank diameter. For large-diameter vertical tanks, SCDAP/RELAP5 uses the 

Zuber-Findlay (Reference D.2) and Kataoka and Ishii (Reference D.3) correlations for churnturbulent bubbly and slug flows. The slip between the phases with the Zuber-Findlay correlation 

is proportional to the square root of the hydraulic diameter while for the Kataoka and Ishii 

correlation it is directly proportional to the hydraulic diameter. Therefore, the run with reduced 

hydraulic diameter effectively implements a reduction in the slip ratio by a factor of between 

2.24 and 5.0 and corresponding increases in the interphase drag and the tank mixture level. 

Compared with the base case, the check run with the reduced tank hydraulic diameter indicated 

only a small difference in the pressurizer draining process and event sequence timing and no 

effect on the calculated SG tube failure margins. As a result of this finding, no sensitivity runs 

related to phase separation in the tank were identified. 

Relief Valve Flow 

Because the pressurizer pressure remains high in this event sequence, the flow of fluid through 

the pressurizer PORVs and SRVs is controlled by critical flow processes. The relief valves pass 

liquid, two-phase fluid and steam over the course of the event sequence. The calculation of 

critical flow through the valves is subject to uncertainties related to modeling of the critical flow 

process in general and to uncertainties related to correctly simulating the fluid conditions at the 

valve inlets. Since the flow of mass and energy out of the primary coolant system by fluid 

exiting through the pressurizer relief valves is large, it is appropriate to evaluate the sensitivity of 

calculation results to variations in the relief valve critical flow. 

A survey was made of prior assessments of RELAP5 capabilities (Reference D.4) for 

representing valve and break flows in experiments in the Marviken (References D.5 and D.6), 

LOFT (References D.7, D.8 and D.9), ROSA-IV (Reference D.10) and MIST (References D.11 

and D.12 ) test facilities. These assessments cover uncertainties related both to critical flow 

modeling and to adequately representing the fluid conditions upstream of the choking location. 

Five high-pressure experiments were evaluated, one of which (MIST Test 360499) featured the 
D-11

behavior for flow through a stuck-open pressurizer PORV. (See Section 3.2.2 for more 

discussion of the RELAP5 assessment for this test) These assessments include a large range 

of upstream fluid conditions and indicate that RELAP5 overpredicted and underpredicted the 

critical flow by up to 27% and 25%, respectively. Based on these assessment findings, 

sensitivity runs with the pressurizer PORV and SRV valve flow areas varied by +30% were 

identified to account for the uncertainties in the relief valve flow. 

A3 Mixing, SG Inlet Plenum

Sensitivity calculations were identified for variations in the HL discharge coefficient, recirculation 

ratio and hot/cold mixing fraction, all of which affect mixing behavior in the SG inlet plenum 

region. A sensitivity calculation with the assumed hot/cold tube split altered is also identified. 

The ranges of the variations selected for the sensitivity runs are based on observations of the 

Westinghouse one-seventh scale experimental data (Reference D.13) and on CFD analyses. In 

these sensitivity runs, the SG inlet plenum flow coefficients are adjusted so as to attain the 

revised target value for the parameter that is varied while maintaining the base-case target 

values for the other mixing parameters. 

A4 SG tube outer wall heat transfer (SG secondary side heat transfer)

The base case model uses the maximum heat transfer coefficient among forced, free and 

laminar convection correlations. The base case model includes a 1.284 multiplier on the heat 

transfer coefficient (which is needed in order for the model to achieve a satisfactory concurrent 

match with plant data for the SG secondary pressure, SG secondary fluid mass and the SG 

heat removal rate during full-power steady state operation). The base case model also includes 

a physically-based multiplier (which is only applied on the heat transfer coefficient calculated 

using the Dittus-Boelter forced convection correlation, Reference D.14) that accounts for the 

effects of flow passing through a tube bundle parallel to the tube axis. However, it is expected 

that substantial portions of the swirling flows within the actual SG tube bundle will be across the 

tubes, not in parallel with them. Such crossflows result in still-higher heat transfer coefficients 

and the extent of this enhancement is not known. During the period when the SG boiler is 

steam filled, the calculated heat transfer coefficient is very small (~10 W/m2

-K). 

Sensitivity runs were identified to evaluate +400% and -50% variations in the SG tube outer wall 

heat transfer coefficient to bound the potential effects of the heat transfer variations described in 

the previous paragraph. 

A5 Buoyancy-driven flows in SG tubes (ratio of SG tube flow to hot leg flow)

The ratio of the SG tube and HL flows is represented in the model by the calculated recirculation 

ratio. Sensitivity runs evaluating the effect of variations in the target recirculation ratio were 

identified (see PIRT Parameter A3 above). 

B1 Core power, especially fuel rod cladding oxidation power

In the model, the core power is calculated as the sum of fission product decay power and the 

fuel rod metal-water reaction oxidation power. The fission decay power is based on the nominal 

ANS1979 standard, Reference D.15. The fission decay power response is relatively stable in 

time and its uncertainty is relatively small (~10%); placing a multiplier on the fission decay 

power to represent this uncertainty is expected to only significantly affect the timing of the 

sequence events (SG dry out, core uncovering, etc.). No sensitivity studies related to fission 
D-12

decay power were identified. The oxidation power is, however, of particular interest because its 

response is transient, the peak oxidation power is relatively high (11.2 times the fission decay 

power in the base case run) and the structural failures of reactor coolant piping and SG tubes 

occur during the period when the oxidation power is peaking. Therefore, sensitivity runs related 

to the oxidation process were identified. 

In a prior sensitivity study, Reference D.1, the impact of varying the oxidation process modeling 

was evaluated using a run in which the peak fuel rod linear oxidation heat was limited to 

1,000 W/m. That model change limited the peak oxidation rate to 57% of that seen in the base 

case run and significantly extended the length of the oxidation period. The study indicated only 

a small reduction in the SG tube failure margin resulted from the change in oxidation modeling. 

The modeling approach used in the prior study only allows for modeling decreases in the 

oxidation power (and not increases) so an alternate modeling approach for evaluating variations 

in the oxidation power is used here. 

Sensitivity studies were identified where both increases and decreases in the oxidation power 

are evaluated by installing artificial heat structures in the core region of the model to add and 

subtract heat from the core fluid at a rate that is a specified multiple of the oxidation power. 

Results from a check run made with the artificial structures included in the model but with zero 

power were compared against the base case calculation to assure that just the presence of the 

artificial structures does not significantly alter the results. The comparison indicated only slight 

biases between the output of the two runs, and the sensitivity run results used in the uncertainty 

calculations are adjusted for those biases. 

The SCDAP/RELAP5 manual describes assessments related to reactor core behavior during 

severe accidents (see Section 3.3). The code performance for predicting fuel rod oxidation 

behavior was evaluated against test data from nine experiments. The summary finding of the 

assessments for hydrogen production due to fuel rod oxidation for the nine experiments 

(Reference D.16, Volume 5, Table 3-1) is that the predicted hydrogen production from fuel rod 

oxidation ranged from 50% above to 15% below the measured hydrogen production. An 

additional assessment of the code capabilities for predicting fuel rod oxidation processes 

against measured/inferred data for the Three Mile Island accident (D.16, Volume 5, Table 4-4) 

indicates that the code overpredicted oxidation by 22%. Based on these assessment results, 

sensitivity runs were identified for +20% and -50% variations in the calculated oxidation power. 

B2 Buoyancy-driven flow in vessel (includes effects of vessel internal flow resistances)

The PIRT committee suggested that the SCDAP/RELAP5-calculated predictions of vessel 

circulation rates are “likely within a factor of two” of the physical circulation rates and two 

sensitivity runs were identified to evaluate the effects of this variation. Modeling uncertainties 

that could affect the RV internal flow rates were evaluated and it was found that the current 

model may be understating the friction losses associated with flows that decline into the laminar 

range. Based on this evaluation, a sensitivity run was identified in which the friction losses are 

increased so as to reduce the flow rates by 50%. A survey of prior RELAP5 assessments 

(Reference D.4) for predicting buoyancy-driven flows in vessels uncovered a UPTF assessment 

case (Reference D.17) in which the code underpredicted the circulating flows by 50%. 

Therefore, a second sensitivity run was identified in which the friction losses are decreased 

such that the vessel circulating flow rates are increased by 100%. 
D-13

B3 Buoyancy-driven flow in hot legs

This parameter is represented in the model by the calculated hot leg discharge coefficient, CD, 

which relates the HL flow rate to the densities of the hot and cold fluid streams. Sensitivity runs 

evaluating the effect of variations in the target hot leg discharge coefficient were identified (see 

PIRT parameter A3 above). 

B4 RCS heat loss to containment

A nominal 4 MW full power operation total heat loss from the outer surfaces of the RCS to 

containment is included in the base case model. This heat loss rate is based on the capacities 

of the containment fan coolers, which remove the heat load during normal plant operation. The 

heat loss is implemented in the model by applying a constant heat transfer coefficient on the 

outer wall surfaces of the RCS piping, SG and RV structures. A prior sensitivity study 

(Reference D.1) indicated that the SG tube failure margins are moderately affected by variation 

in the RCS heat loss. Sensitivity studies were identified with the heat loss reduced to 2 MW and 

increased to 8 MW. This factor-of-two variation is based on an EPRI report (Reference D.18) 

that evaluated the causes for plant operating containment temperatures generally exceeding 

their design values. The report found that many insulating materials did not meet the specified 

heat loss requirement and that heat losses from vertical components were greater than 

previously analyzed. To implement the changes into the model, the constant heat transfer 

coefficient that results in the 4 MW base case heat loss is halved and doubled. 

B5 Mixing at the vessel-to-hot leg connection

The PIRT committee discussed that mixing at the connection between the RV and HL is 

expected to be much less robust than mixing in the SG inlet plenum region. The cool steam 

returning to the vessel tends to fall downward into the peripheral regions of the core and does 

not mix with the hot steam that flows into the upper HL sections. Buoyancy effects therefore 

tend to keep the hot and cold streams apart at the location of this connection. 

The SCDAP/RELAP5 base case model is set up to well represent the fluid buoyancy behavior 

at the RV-to-HL connections and the calculated response is plausible. Within the RV upper 

plenum region, the code predicts a radially-outward flow of hot steam toward the HLs through 

the uppermost region of the upper plenum. The flow exiting the RV into the upper HL sections 

represents only a portion (~30%) of the hot steam carried by that flow. The remainder of the 

flow turns downward, where it is mixed with the returning cooler steam from the lower HL 

section, and then turns radially-inward toward the vessel centerline. The 

SCDAP/RELAP5-calculated behavior in the HL nozzle region results in limited local mixing 

between the cooler steam entering the RV from the lower HL sections and the hotter steam that 

flows out of the vessel into the upper HL sections. 

NRC CFD simulations also displayed this buoyancy-driven behavior and show only minimal 

mixing of the hot and cool streams at the RV-to-HL connection. Therefore no SCDAP/RELAP5 

sensitivity runs related to fluid mixing at the vessel to HL connection were identified. 

C1 Operator intervention (event sequence definition item)

Operator intervention to mitigate the accident was investigated in a prior sensitivity study 

(Reference D.1). The intervention involves recognizing the event sequence signature and 

depressurizing the primary and secondary systems according to procedures. The prior studies 
D-14

demonstrated the effectiveness of the operator intervention for mitigating the accident and the 

event sequence timing limitations involved. No new sensitivity runs were identified. 

C2 RC pump seal leakage (event sequence definition item)

Evaluations of RCP pump shaft seal leakage for SBO accident event sequences have been 

performed by Brookhaven National Laboratory (Reference D.19). Those evaluations indicate 

that a leak rate of 1.32 L/s [21 gpm] per pump is likely over the early portion of a SBO accident 

event sequence. Later during the event sequence a variety of other leak rates are possible, 

depending on failures of pump seal components. 

Sensitivity calculations were identified for a variety of pump seal leakage situations, with the 

leak rate changing from the 1.32-L/s [21-gpm] rate after two hours. Calculations were identified 

to investigate a decrease to 0.063 L/s [1 gpm] and increases to 3.83 L/s [61 gpm], 5.66 L/s 

[90 gpm], 7.54 L/s [120 gpm], 11.4 L/s [182 gpm] and 18.9 L/s [300 gpm] in each of the four 

RCPs after two hours. Calculations investigating increases to 18.9 L/s [300 gpm] in only one 

pump were also identified. Most of these calculations address issues relating to the effects of 

RCP seal leakage variations and, as described below, not for the purpose of the uncertainty 

evaluation. 

Previous sensitivity studies (Reference D.1) were performed with the SCDAP/RELAP5 model to 

evaluate the effects of various increases in the leak rate after two hours. Those studies 

indicated that an increase in the leak rate to 3.83 L/s [61 gpm] at two hours moderately 

decreased the SG tube failure margins and that larger increases in the leak rate led to early 

core melt and greatly increased SG tube failure margins. 

For the purposes of the uncertainty study it is assumed that the event sequence under 

investigation specifies a 1.32-L/s [21-gpm] leakage rate throughout the event, consistent with 

the assumption used in the base case calculation. Considerations of lower and higher leak 

rates are judged to represent separate, distinct event sequences from a PRA view. However, it 

is acknowledged that (in addition to those considerations) there are uncertainties related simply 

to the ability of SCDAP/RELAP5 to simulate leak rates in general. Those uncertainties relate to 

the simulation of the fluid conditions upstream of the leak, the configuration of the leak geometry 

as well as the ability to predict the critical flow. The uncertainty study assumes that the 

uncertainty in the SCDAP/RELAP5 simulation for the 1.32 L/s [21 gpm] rate is +1.26 L/s 

[+20 gpm]. A SCDAP/RELAP5 sensitivity run is made for the 1 gpm assumed leak rate case. 

For the 2.58-L/s [41-gpm] leak rate assumption, results are obtained by interpolating between 

the 1.32 L/s [21 gpm] leakage in the SCDAP/RELAP5 base case calculation and a 

SCDAP/RELAP5 sensitivity case calculation which assumed 3.83-L/s [61-gpm] leakage. 

C3 SG tube leakage (event sequence definition item)

The effects of introducing preexisting SG tube primary-to-secondary leakage conditions into the 

event sequence description were evaluated in a prior sensitivity study (Reference D.1). No new 

sensitivity runs were identified to address uncertainties in this parameter. However, an 

additional SG tube primary-to-secondary system leakage sensitivity run (Case 8C), unrelated to 

the uncertainty study, is discussed in Section D.2.2. 

C4 Surge line orientation (plant configuration item)
D-15

The configuration of the surge line and the location of its HL connection are fixed (the 

connection is made on the side of HL). No sensitivity runs were identified to address 

uncertainties in this parameter. However, an additional surge line configuration sensitivity run 

evaluating the effects of moving the connection to the top of the HL pipe is discussed in 

Section D.2.2. 

C5 Distribution of metal mass in the plant (plant configuration item)

The distributions of metal mass and materials among the piping and vessels in any plant are 

fixed. No sensitivity runs were identified. 

D.2 Sensitivity Run Results 

Section D.2.1 documents the results of the SCDAP/RELAP5 uncertainty evaluation sensitivity 

case runs. Section D.2.2 documents the results of additional SCDAP/RELAP5 sensitivity runs 

performed to evaluate various other modeling issues. 

D.2.1 Sensitivity Runs Used for the Statistical Evaluations of Uncertainty 

Nineteen of the SCDAP/RELAP5 sensitivity runs identified in Table D.2 were used to generate 

data for the statistical evaluations of uncertainty. The sensitivity runs were performed as 

variations on the Westinghouse four-loop plant SBO base case calculation described in 

Section 2.8. With the exception of runs made specifically to evaluate the effect of variations in 

the SG inlet plenum mixing and flow parameters, the sensitivity runs were performed with the 

SG inlet plenum region flow coefficients readjusted to retain agreement between the calculated 

and target mixing and flow parameters of the base case. 

The dependent variable output data from the base case and sensitivity calculations used in 

developing the uncertainty estimates is shown in Tables D.3 and D.4. Other results from 

the 19 sensitivity runs are summarized as follows: 

Pressurizer PORV and SRV Flow Area Variations

The nominal pressurizer PORV and SRV flow areas used in the base case calculation are those 

needed to provide the rated valve flows at the rated pressures. Two sensitivity runs were 

performed, Case 1A (with nominal PORV and SRV flow areas increased by 30%) and Case 1B 

(with nominal PORV and SRV flow areas decreased by 30%). 

The mass flow rates through one of the two pressurizer PORVs in the base case, Case 1A and 

Case 1B are compared in Figure D.1. As expected, during periods when the valve is open the 

flow rates for Cases 1A and 1B are respectively greater and less than the corresponding base 

case flow rate. Because the relief valves open as often and as long as needed to control the 

RCS pressure, the overall results from the three runs are generally not very different, as shown 

by the comparison of the RCS pressure responses for the three runs in Figure D.2. For the 

case with the larger valve area the valve opens for shorter periods than in the base case; the 

opposite is true for the case with the smaller valve area. The SG tube failure margins are only 

very slightly affected by the variations in the pressurizer relief valve flow areas. Note that the 

PORVs are not functional after the station batteries are assumed to be depleted at four hours 

(14,400 s). Afterward, the pressurization of the RCS is limited only by the opening of the 

pressurizer SRVs. 
D-16

Table D.3 Comparison of SCDAP/RELAP5-Calculated Results for Failure Times and 

Margins for the Cases Used in the Uncertainty Analysis 

Case 

Number*

First Primary 

Failure 

Component 

First Primary 

Failure Time(s) 

SG 1 Hottest Tube 

with 1.0 Multiplier 

Failure Time – 

First Primary 

Failure Time(s) 

SG 1 Average Tube 

Stress Multiplier for 

Tube Failure 

Coincident with First 

Primary Failure 

Base Case Hot Leg 1 13,630 -155 2.10 

Case 1A Hot Leg 1 13,660 -155 2.07 

Case 1B Hot Leg 1 13,685 -150 2.11 

Case 2A Hot Leg 1 13,775 -155 1.92 

Case 2B Hot Leg 1 13,470 -135 2.39 

Case 2C Hot Leg 1 13,765 -170 2.18 

Case 2D Hot Leg 1 13,615 -135 2.02 

Case 2E Hot Leg 1 13,605 -145 2.50 

Case 2F Hot Leg 1 13,740 -160 1.81 

Case 2G Hot Leg 1 13,750 -140 2.21 

Case 3A Hot Leg 1 13,550 -35 2.35 

Case 3B Hot Leg 1 13,650 -160 2.07 

Case 4A Hot Leg 1 13,435 -170 2.16 

Case 4B Hot Leg 1 14,535 -90 1.91 

Case 5A Hot Leg 1 13,355 -260 2.28 

Case 5B Hot Leg 1 14,125 -90 1.97 

Case 6A Hot Leg 1 13,295 -140 2.12 

Case 6B Hot Leg 1 14,385 -255 1.92 

Case 7A Hot Leg 1 13,465 -210 2.33 

Case 7B* Hot Leg 2 14,320 Did Not Fail 7.01 

Case 7C* Hot Leg 2 14,475 Did Not Fail 4.58 

Case 7D* Hot Leg 2 14,300 Did Not Fail 3.30 

Case 7E* Hot Leg 2 13,450 10 2.50 

Case 7F* Hot Leg 2 13,380 Did Not Fail 2.00 

Case 7F2* Hot Leg 1 13,460 -275 2.15**

Case 7G Hot Leg 1 13,395 -140 2.08 

* Runs marked with a single asterisk are not used for the statistical evaluation of uncertainties, only for evaluating 

various other issues. 

** For Case 7F2, the minimum average-tube failure margin shown is calculated in SG 3. 
D-17

Table D.4 Comparison of SCDAP/RELAP5-Calculated Results for Temperatures and Wall 

Heat Transfer Coefficients for the Cases Used in the Uncertainty Analysis 

Case 

Number*

SG 1 Average 

Tube 

Structure 

Temperature 

(K) 

SG 1 Hottest 

Tube 

Structure 

Temperature 

(K) 

Hot Leg 1 

Steam 

Temperature 

(K) 

Hot Leg 

1 Wall 

HTC 

(W/m2

-K) 

Surge Line 

Steam 

Temperature 

(K) 

Surge 

Line Wall 

HTC 

(W/m2-K) 

Base Case 1021.7 1239.6 1776.0 423.13 1373.0 490.86 

Case 1A 1023.0 1239.6 1771.9 434.52 1378.3 562.30 

Case 1B 1020.9 1238.7 1773.8 412.90 1370.6 454.83 

Case 2A 1039.3 1254.1 1744.7 428.99 1360.6 501.09 

Case 2B 999.80 1218.4 1744.5 399.42 1346.6 475.78 

Case 2C 1014.6 1247.7 1729.4 424.26 1349.2 561.65 

Case 2D 1028.6 1217.1 1729.8 404.27 1348.8 470.96 

Case 2E 986.70 1226.0 1725.1 407.90 1352.2 517.18 

Case 2F 1053.0 1247.1 1780.3 438.17 1369.0 542.98 

Case 2G 1013.8 1217.3 1788.3 407.35 1377.0 442.90 

Case 3A 1000.7 1173.0 1737.9 413.83 1353.7 499.80 

Case 3B 1023.8 1248.5 1751.0 413.18 1355.0 463.99 

Case 4A 1018.8 1240.1 1776.8 438.84 1368.1 548.26 

Case 4B 1030.9 1189.6 1677.7 297.93 1274.6 243.77 

Case 5A 999.20 1157.5 1603.3 380.91 1248.7 468.74 

Case 5B 1031.8 1231.3 1800.5 422.80 1405.7 527.39 

Case 6A 1017.9 1235.0 1764.1 415.13 1364.8 462.60 

Case 6B 1040.7 1250.6 1739.8 419.04 1325.5 490.39 

Case 7A 997.80 1180.2 1731.2 364.63 1127.6 279.77 

Case 7B* 918.10 949.70 1558.3 234.15 623.20 133.41 

Case 7C* 952.80 989.90 1481.8 247.84 720.10 180.11 

Case 7D* 960.00 1010.6 1489.1 269.00 741.00 181.79 

Case 7E* 984.20 1139.9 1719.2 332.79 745.00 284.46 

Case 7F* 950.10 1049.8 1668.0 334.26 848.20 234.29 

Case 7F2* 1007.3 1186.1 1668.1 340.33 1004.9 251.34 

Case 7G 1023.0 1234.6 1735.3 421.27 1360.7 562.50 

* Runs marked with an asterisk are not used for the statistical evaluation of uncertainties, only for evaluating various 

other issues. 
D-18

0 5000 10000 15000 20000

Time (s)

0

20

40

60

80

100

Flow Rate (kg/s)

mflowj−15700 (Case 1A) 

mflowj−15700 (Base Case) 

mflowj−15700 (Case 1B) 

0 5000 10000 15000 20000

0

44

88

132

176

220

Flow Rate (lbm/s)

Figure D.1 Mass Flow Rates Through One of the Two Pressurizer PORVs for the Relief 

Valve Flow Area Sensitivity Cases 

0 5000 10000 15000 20000

Time (s)

10.0

12.0

14.0

16.0

18.0

20.0

Pressure (MPa)

p−10001 (Case 1A) 

p−10001 (Base Case) 

p−10001 (Case 1B) 

0 5000 10000 15000 20000

1450

1740

2031

2321

2611

2901

Pressure (psia)

Figure D.2 RCS Pressures for the Relief Valve Flow Area Sensitivity Cases 
D-19

Hot Leg Discharge Coefficient Variations

The nominal target hot leg discharge coefficient in the base case calculation is 0.12. Two 

sensitivity runs were performed, Case 2A (with the discharge coefficient increased by 15% 

to 0.138) and Case 2B (with the discharge coefficient decreased by 15% to 0.102). 

The responses of the Hot Leg 1 discharge coefficients for the base case, Case 2A and Case 2B 

are compared in Figure D.3. The calculated discharge coefficients are in good agreement with 

the desired target values for all three runs. 

Figure D.4 compares the flow rates in the upper section of Hot Leg 1, near the RV, among the 

three runs. As expected, the HL flow rate is higher when the higher discharge coefficient is 

used and lower when the lower discharge coefficient is used. Figure D.5 compares the 

integrated SG 1 power fractions among the three runs. These two figures show the close 

correlation between the HL flow and the portion of the core heat that is removed to the SGs. 

The difference in SG heat removal is seen to have a moderate effect on the SG average tube 

failure margins. Stress multipliers of 1.92, 2.10 and 2.39, respectively are needed for average 

tube failure to occur coincident with the HL using the increased, nominal and reduced hot leg 

discharge coefficients. The comparisons also show a small event sequence timing effect, with 

the lower hot leg discharge coefficient leading to an acceleration of events and the higher 

discharge coefficient leading to a deceleration of events. This effect results because the 

reduced SG heat removal associated with a lower hot leg discharge coefficient leads to more 

frequent and longer opening periods for the pressurizer PORVs, which tends to reduce the RCS 

fluid inventory more rapidly and accelerate the system heat-up process. 

Subsequent to performing Cases 2A and 2B, it was uncovered that the +15% hot leg discharge 

coefficient variations assumed in these runs may not fully bound the expected range in the 

parameter. For that reason, the results from these two runs are extrapolated to effectively 

incorporate a +30% hot leg discharge coefficient variation in the uncertainty analysis. 

Recirculation Ratio Variations

The nominal target recirculation ratio used in the base case calculation is 2.0. Two sensitivity 

runs were performed, Case 2C (with the recirculation ratio increased to 2.3) and Case 2D (with 

the recirculation ratio decreased to 1.7). 

The responses of the Loop 1 recirculation ratios for the base case, Case 2C and Case 2D are 

compared in Figure D.6. The calculated recirculation ratios are in good agreement with the 

desired target values for all three runs. 

Figure D.7 compares the integrated SG 1 power fractions among the three runs. With the other 

flow and mixing target parameters held constant, an increase in recirculation ratio leads to 

increased SG heat removal. The difference in SG heat removal is seen to have a small effect 

on the average tube failure margins. Stress multipliers of 2.02, 2.10 and 2.18, respectively are 

needed for average tube failure to occur coincident with the HL using the reduced, nominal and 

increased recirculation ratios. The average tube failure margin increases as the recirculation 

ratio increases because (with a cold mixing fraction of 0.85) most of the increased cold return 

tube flow is directed to the mixing plenum, where it lowers the inlet temperature for the hot 

average tube. 
D-20

8000 10000 12000 14000 16000

Time (s)

0.08

0.10

0.12

0.14

0.16

0.18

Hot Leg Discharge Coefficient

cntrlvar−9619 (Case 2A) 

cntrlvar−9619 (Base Case) 

cntrlvar−9619 (Case 2B) 

Figure D.3 Hot Leg 1 Discharge Coefficient Responses for the Hot Leg Discharge 

Coefficient Sensitivity Cases 

8000 10000 12000 14000 16000

Time (s)

0.0

5.0

10.0

15.0

20.0

Flow Rate (kg/s)

mflowj−10001 (Case 2A) 

mflowj−10001 (Base Case) 

mflowj−10001 (Case 2B) 

8000 10000 12000 14000 16000

0.0

11.0

22.0

33.1

44.1

Flow Rate (lbm/s)

Figure D.4 Hot Leg 1 Upper Section Flow Rates for the Hot Leg Discharge Coefficient 

Sensitivity Cases 
D-21

8000 10000 12000 14000 16000

Time (s)

0.00

0.02

0.04

0.06

0.08

0.10

Integrated SG Power Fraction

cntrlvar−5121 (Case 2A) 

cntrlvar−5121 (Base Case) 

cntrlvar−5121 (Case 2B) 

Figure D.5 Integrated SG Power Fractions for the Hot Leg Discharge Coefficient 

Sensitivity Cases 

8000 10000 12000 14000 16000

Time (s)

1.5

2.0

2.5

3.0

Recirculation Ratio

cntrlvar−5144 (Case 2C) 

cntrlvar−5144 (Base Case) 

cntrlvar−5144 (Case 2D) 

Figure D.6 Loop 1 Recirculation Ratio Responses for the Recirculation Ratio 

Sensitivity Cases 
D-22

8000 10000 12000 14000 16000

Time (s)

0.00

0.02

0.04

0.06

0.08

0.10

Integrated SG Power Fraction

cntrlvar−5121 (Case 2C) 

cntrlvar−5121 (Base Case) 

cntrlvar−5121 (Case 2D) 

Figure D.7 Loop 1 Integrated SG Power Fractions for the Recirculation Ratio 

Sensitivity Cases 

Unlike the average tube failure margin, the hottest tube failure margin is seen in Table D.3 to 

decline as the recirculation ratio increases. The reason for this difference is that the modeling 

which determines the inlet temperatures for the average and hottest tubes is different. For the 

average tube, the inlet temperature is based on the temperatures in the upper HL section and 

mixing plenum and on the flow rates from those two into the SG tube. However, for the hottest 

tube the inlet temperature is based only on the HL upper section temperature and cold tube 

return temperature (and a constant which defines the hottest tube inlet temperature within the 

range between the two). So, for an increased recirculation ratio, the average tube benefits, but 

the hottest tube does not, from the cooling effects of the higher cold return flow rate that passes 

to the mixing plenum. 

The comparisons also show a small event sequence timing effect, with a lower recirculation 

ratio leading to an acceleration of events and a higher recirculation ratio leading to a 

deceleration of events. This effect results because the reduced SG heat removal associated 

with a lower recirculation ratio leads to more frequent and longer opening periods for the 

pressurizer PORVs, which tends to reduce the RCS fluid inventory more rapidly and accelerate 

the system heat up process. 

Mixing Fraction Variations

The nominal target hot and cold mixing fractions used in the base case calculation are 0.85. 

Two sensitivity runs were performed, Case 2E (with the mixing fractions increased to 0.95) and 

Case 2F (with the mixing fractions decreased to 0.75). 
D-23

The responses of the Loop 1 hot and cold mixing fractions for the base case, Case 2C and 

Case 2D are compared in Figures D.8 and D.9. The calculated hot and cold mixing fractions 

are in good agreement with the desired target values for all three runs. 

Figure D.10 compares the integrated SG 1 power fractions among the three runs. With the 

other flow and mixing target parameters held constant, a decrease in the mixing fractions leads 

to increased SG heat removal. This results because less flow is directed to the SG mixing inlet 

plenum and more flow is directed to the hot inlet plenum and cold inlet plenum. The difference 

in SG heat removal is seen to have a moderate effect on the SG average tube failure margins. 

Stress multipliers of 1.81, 2.10 and 2.50, respectively are needed for average tube failure to 

occur coincident with the HL using the decreased, nominal and increased mixing fractions. 

Hot/Cold Tube Split Variation

The nominal hot/cold tube split assumed in the base case calculation is 41%/59%. A sensitivity 

run, Case 2G, was performed with the assumed tube split ratio changed to 50%/50%. 

The mass flow rates in the SG 1 hot average tube for Case 2G and the base case are virtually 

the same, as shown in Figure D.11. Changing the partitioning of tubes into the hot and cold 

sections changes the flow areas of those sections, but the conservation of mass consideration 

requires that the mass flows through the two sections be the same, regardless of their relative 

sizes. However, the cross sectional flow area of the hot average tube section is larger (50% of 

the total) in Case 2G than it is in the base case (where it is 41% of the total). So, although the 

mass flow rates are the same, the hot average tube fluid velocities are lower in Case 2G than 

they are in the base case, as shown in Figure D.12. 

8000 10000 12000 14000 16000

Time (s)

0.6

0.7

0.8

0.9

1.0

1.1

Mixing Fraction

cntrlvar−5135 (Case 2E) 

cntrlvar−5135 (Base Case) 

cntrlvar−5135 (Case 2F) 

Figure D.8 Loop 1 Hot Mixing Fraction Responses for the Mixing Fraction Sensitivity 

Cases 
D-24

8000 10000 12000 14000 16000

Time (s)

0.6

0.7

0.8

0.9

1.0

1.1

Mixing Fraction

cntrlvar−5138 (Case 2E) 

cntrlvar−5138 (Base Case) 

cntrlvar−5138 (Case 2F) 

Figure D.9 Loop 1 Cold Mixing Fraction Responses for the Mixing Fraction Sensitivity 

Cases 

8000 10000 12000 14000 16000

Time (s)

0.00

0.02

0.04

0.06

0.08

0.10

Integrated SG Power Fraction

cntrlvar−5121 (Case 2E) 

cntrlvar−5121 (Base Case) 

cntrlvar−5121 (Case 2F) 

Figure D.10 Integrated SG 1 Power Fractions for the Mixing Fraction Sensitivity Cases 
D-25

8000 10000 12000 14000 16000

Time (s)

0.0

5.0

10.0

15.0

20.0

Flow Rate (kg/s)

mflowj−11001 (Case 2G) 

mflowj−11001 (Base Case) 

8000 10000 12000 14000 16000

0.0

11.0

22.0

33.1

44.1

Flow Rate (lbm/s)

Figure D.11 Mass Flow Rates in SG 1 Hot Average Tube for the Tube Split Sensitivity 

Cases 

8000 10000 12000 14000 16000

Time (s)

0.0

0.2

0.4

0.6

0.8

1.0

Flow Rate (kg/s)

velgj−11001 (Case 2G) 

velgj−11001 (Base Case) 

8000 10000 12000 14000 16000

0.00

0.66

1.31

1.97

2.62

3.28

Flow Rate (lbm/s)

Figure D.12 Fluid Velocities in SG 1 Hot Average Tube for the Tube Split Sensitivity 

Cases 
D-26

Lower velocities lead to lower heat transfer coefficients on the inside surfaces of the SG tubes. 

Figure D.13 shows that the fluid-to-wall heat transfer coefficient for the SG 1 hot average tube 

section (just above the tubesheet) is lower in Case 2G than in the base case. And the lower 

wall heat transfer coefficients are seen to result in lower SG 1 tube metal temperatures at that 

location in Case 2G than in the base case, as shown in Figure D.14. 

These differences result in moderately higher SG tube failure margins for Case 2G than for the 

base case. The SG average tube requires a stress multiplier of 2.21 to fail coincident with the 

HL in Case 2G, whereas in the base case a stress multiplier of 2.10 is required. 

SG Tube Outer-Wall Heat Transfer Coefficient Variations

The base case calculation employs the standard SCDAP/RELAP5 models for wall heat transfer 

on the outer surfaces of the SG tubes. Two sensitivity runs were performed, Cases 3A and 3B, 

with 5.0 and 0.5 multipliers respectively applied to the tube outer-surface heat transfer 

coefficient. 

The responses of the SG 1 hot average tube outer-surface heat transfer coefficients for the 

base case, Case 3A and Case 3B are compared in Figure D.15. The calculated heat transfer 

coefficients are in good agreement with their expected relative values. Note that the heat 

transfer coefficient multipliers in the sensitivity case runs were implemented at the time when 

the core uncovers and the temperature of the steam entering the HLs becomes superheated. 

The runs were made in this manner because: (1) it is the behavior as the system heats up which 

is of interest and (2) implementing the multipliers earlier (for example, when the SGs still contain 

water) would have resulted in significant event sequence timing differences among the runs that 

would have obscured the desired comparisons. 

The difference in the tube outer wall heat transfer coefficients is seen to have a moderate effect 

on the SG average tube failure margins. Stress multipliers of 2.07, 2.10 and 2.35, respectively 

are needed for average tube failure to occur coincident with the HL using the reduced, nominal 

and increased heat transfer coefficients. 

The behavior differences among these runs are complex and include many competing effects 

regarding the temperatures and flow rates among the regions of the primary and secondary 

coolant systems. The fluid temperatures and velocities in the SG tube primary and SG 

secondary boiler regions are strong functions of the assumed tube outer-wall heat transfer 

coefficient. Figure D.16 compares the SG 1 hot average tube wall temperatures (just above the 

tubesheet) among the three runs for a short time period which includes the HL failure times in all 

runs (which occur between 13,550 s and 13,650 s). The figure shows that the base case and 

Case 3B exhibit a similar behavior but that the much higher heat transfer coefficient in Case 3A 

causes a different behavior. That, coupled with the 100-s difference in the HL failure time, leads 

to the SG tube failure margin differences among the cases. The competing effects associated 

with this sensitivity evaluation are discussed in more detail in Reference D.1. 

Fuel Rod Cladding Oxidation Variations

The base case calculation employs the standard SCDAP/RELAP5 models for fuel rod cladding 

oxidation. Two sensitivity runs were performed, Case 4A (with an additional 20% of the 

calculated oxidation power added to the fluid in the core region) and Case 4B (with 50% of the 

calculated oxidation power removed from the fluid in the core region). 
D-27

8000 10000 12000 14000 16000

Time (s)

200

300

400

500

600

Heat Transfer Coefficient (W/m2*K)

hthtc−110100100 (Case 2G) 

hthtc−110100100 (Base Case) 

8000 10000 12000 14000 16000

35.2

52.8

70.4

88.1

105.7

Heat Transfer Coefficient (Btu/hr*ft2*F)

Figure D.13 SG 1 Hot Average Tube Wall Inside Surface Heat Transfer Coefficients for 

the Tube Split Sensitivity Cases 

8000 10000 12000 14000 16000

Time (s)

600

800

1000

1200

Heat Structure Temperature (K)

htvat−1101001 (Case 2G) 

htvat−1101001 (Base Case) 

8000 10000 12000 14000 16000

620

980

1340

1700

Heat Structure Temperature (F)

Figure D.14 Tube Wall Temperatures in SG 1 Hot Average Tube for the Tube Split 

Sensitivity Cases 
D-28

8000 10000 12000 14000 16000

Time (s)

0.0

20.0

40.0

60.0

80.0

Heat Transfer Coefficient (W/m2*K)

hthtc−110100101 (Case 3A) 

hthtc−110100101 (Base Case) 

hthtc−110100101 (Case 3B) 

8000 10000 12000 14000 16000

0.00

3.52

7.04

10.57

14.09

Heat Transfer Coefficient (Btu/hr*ft2*F)

Figure D.15 SG 1 Hot Average Tube Outer Surface Heat Transfer Coefficients for the 

Tube Outer Wall Heat Transfer Sensitivity Cases 

13000 13200 13400 13600 13800 14000

Time (s)

900

950

1000

1050

1100

Heat Structure Temperature (K)

htvat−1101001 (Case 3A) 

htvat−1101001 (Base Case) 

htvat−1101001 (Case 3B) 

13000 13200 13400 13600 13800 14000

1160

1250

1340

1430

1520

Heat Structure Temperature (F)

Figure D.16 SG 1 Hot Average Tube Wall Temperatures for the Tube Outer Wall Heat 

Transfer Sensitivity Cases 
D-29

The oxidation powers from the base case, Case 4A and Case 4B are compared in Figure D.17. 

The responses are in good agreement with their expected relative behavior. The event 

sequence timing and peak oxidation power are significantly affected by the oxidation modeling 

revisions. In Case 4A, for which supplemental power is added, the peak oxidation power is 

higher and it occurs earlier than in the base case. In Case 4B, for which supplemental power is 

removed, the oxidation power peak is much lower and later than in the base case. These 

differences are as expected because of the positive feedback between oxidation rate and 

temperature. For example, added power causes the heat-up to become more rapid, and the 

feedback effect causes the oxidation rate to be higher, which leads to still-higher powers and 

temperatures. 

The difference in the oxidation modeling is seen to have a small effect on the SG average tube 

failure margins. Stress multipliers of 1.91, 2.10 and 2.16, respectively are needed for average 

tube failure to occur coincident with the HL using the reduced, nominal and increased oxidation 

rates. This relationship between the oxidation power and average SG tube failure margin is 

created mainly because a higher oxidation rate leads to a faster system heat-up and the HLs 

are located in closer proximity to the reactor core (where the steam is the hottest) than are the 

SG tubes. 

Figure D.18 compares the Hot Leg 1 upper section fluid temperatures near the RV among the 

three runs. The system heat-up rate for the +20% oxidation case is higher than for the base 

case and much higher than for the -50% oxidation case. The average tube failure margin for 

the +20% oxidation case is higher than for the base case because the heat-up rate is faster and 

the time delay required for the increasingly-hotter steam to migrate out into the SG tubes 

becomes a more important factor. Conversely, the average tube failure margin for the -50% 

oxidation case is lower than for the base case because the heat up rate is slower and the 

migration time delay is no longer as important. In other words, for faster heat-ups the proximity 

to the core becomes more important, causing the HLs to reach failure temperature preferentially 

sooner than the SG tubes and for slower heat-ups the proximity to the core becomes less 

important, causing the SG tubes to reach to reach failure temperature preferentially sooner than 

the HLs. Unlike the average tube failure margin, the hottest tube failure margin is seen in 

Table D.3 to decline as the oxidation rate increases. The reason for this difference is the same 

as described above under “Recirculation Ratio Variations.” 

Reactor Vessel Internal Circulation Rate Variations

The SCDAP/RELAP5 base case flow circulations within the RV are based on the configuration 

of the RV fluid regions and internal structures, the fluid conditions and the flow loss coefficients 

specified in the input model. Two sensitivity runs were performed, Case 5A (with flow loss 

coefficients increased so as to reduce the vessel internal circulation flow rates by 50%) and 

Case 5B (with flow loss coefficients decreased so as to increase the vessel internal circulation 

flow rates by 100%). 

The flow rates at the top of the central core channel for the base case, Case 5A and Case 5B 

are compared in Figure D.19. The relative flow rates among the three calculations are as 

expected (flow comparisons at other locations within the RV show similar relative behavior). 

The changes in the RV internal flow loss modeling are seen to have a small effect on the 

average tube failure margins. Stress multipliers of 2.28, 2.10 and 1.97, respectively are needed 

for average tube failure to occur coincident with the HL for the cases representing the reduced, 

nominal and increased vessel circulation flow rates. 
D-30

10000 12000 14000 16000 18000

Time (s)

0

200

400

600

Total Fuel Rod Oxidation Power (MW)

bgthq−0 + cntrlvar−911 (Case 4A) 

bgthq−0 (Base Case) 

bgthq−0 + cntrlvar−911 (Case 4B) 

10000 12000 14000 16000 18000

0

189563

379127

568690

Total Fuel Rod Oxidation Power (Btu/s)

Figure D.17 Fuel Rod Cladding Oxidation Powers for the Oxidation Sensitivity Cases 

8000 10000 12000 14000 16000

Time (s)

500

1000

1500

2000

Volume Vapor Temperature (K)

tempg−10001 (Case 4A) 

tempg−10001 (Base Case) 

tempg−10001 (Case 4B) 

8000 10000 12000 14000 16000

440

1340

2240

3140

Volume Vapor Temperature (F)

Figure D.18 Hot Leg 1 Upper Section Fluid Temperatures for the Oxidation Sensitivity 

Cases 
D-31

8000 10000 12000 14000 16000

Time (s)

0.0

5.0

10.0

15.0

20.0

Flow Rate (kg/s)

mflowj−51139 (Case 5A) 

mflowj−51139 (Base Case) 

mflowj−51139 (Case 5B) 

8000 10000 12000 14000 16000

0.0

11.0

22.0

33.1

44.1

Flow Rate (lbm/s)

Figure D.19 Flow Rates at Top of Central Core Region for the Vessel Circulation 

Sensitivity Cases 

These margin differences were found to result primarily because the vessel internal circulation 

rate affects the fuel rod oxidation process. Figure D.20 compares the total fuel rod oxidation 

power responses for the three cases. The reduced vessel circulation case resulted in a lower 

and earlier peak oxidation power than the base case. The increased vessel circulation case 

resulted in a higher and later peak oxidation power than the base case. This difference in 

oxidation behavior results because, although the vessel internal circulation rates differ widely 

among the runs, the HL flow rates in all three runs are for the most part the same. Therefore, in 

the reduced vessel circulation case the cooling afforded by the flow leaving and returning to the 

vessel becomes a more significant factor, leading to lower core temperatures and lower fuel rod 

oxidation rates. 

The cases with higher vessel internal flow rates and oxidation powers lead to lower average 

tube failure margins, which is the reverse of the results discussed for the oxidation modeling 

sensitivity above. This difference appears to result because the peak temperatures achieved 

were similar in all three of the oxidation power sensitivity runs (see Figure D.18) but the peak 

temperatures achieved in the three vessel-circulation sensitivity runs are quite different, as 

shown in Figure D.21. These fluid temperature differences are important because they affect 

the peak HL wall temperatures (shown in Figure D.22) which directly affect the prediction of the 

HL failure. A spread of 395 K (711°F) is seen among the peak HL wall temperatures achieved 

for the three cases. 

Unlike the average tube failure margin, the hottest tube failure margin is seen (in Table D.3) to 

increase as the vessel internal circulation rate increases. The reason for this difference is the 

same as described above under “Recirculation Ratio Variations.” 
D-32

8000 10000 12000 14000 16000

Time (s)

0

200

400

600

Total Fuel Rod Oxidation Power (MW)

bgthq−0 (Case 5A) 

bgthq−0 (Base Case) 

bgthq−0 (Case 5B) 

8000 10000 12000 14000 16000

0

189563

379127

568690

Total Fuel Rod Oxidation Power (Btu/s)

Figure D.20 Total Fuel Rod Cladding Oxidation Power for the Vessel Circulation 

Sensitivity Cases 

8000 10000 12000 14000 16000

Time (s)

500

1000

1500

2000

2500

Volume Vapor Temperature (K)

tempg−10001 (Case 5A) 

tempg−10001 (Base Case) 

tempg−10001 (Case 5B) 

8000 10000 12000 14000 16000

440

1340

2240

3140

4040

Volume Vapor Temperature (F)

Figure D.21 Hot Leg 1 Upper Section Fluid Temperatures for the Vessel Circulation 

Sensitivity Cases 
D-33

8000 10000 12000 14000 16000

Time (s)

500

1000

1500

2000

Heat Structure Temperature (K)

htvat−1001001 (Case 5A) 

htvat−1001001 (Base Case) 

htvat−1001001 (Case 5B) 

8000 10000 12000 14000 16000

440

1340

2240

3140

Heat Structure Temperature (F)

Figure D.22 Hot Leg 1 Upper Section Average Wall Temperatures for the Vessel 

Circulation Sensitivity Cases 

Reactor Coolant System Heat Loss Variations

The base case calculation assumes a 4 MW total heat loss from the outer surfaces of the RCS 

to the containment. Two sensitivity runs were performed, Case 6A (with the heat loss reduced 

to 2 MW) and Case 6B (with the heat loss increased to 8 MW). 

The heat fluxes from the outer surface of the cylindrical RV wall (at an elevation near the center 

of the core) for the base case, Case 6A and Case 6B are compared in Figure D.23. The relative 

heat fluxes among the three calculations are as expected (heat flux comparisons at other RCS 

locations show similar relative behavior). 

The different heat loss modeling is seen to have a small effect on the SG average tube failure 

margins. Stress multipliers of 2.12, 2.10 and 1.92, respectively are needed for average tube 

failure to occur coincident with the HL for the cases representing the reduced, nominal and 

increased RCS heat losses. 

These SG tube failure margin differences were found to result primarily from sequence of 

events timing differences induced by the heat loss assumptions. Lower heat losses tend to 

accelerate the timing of events while higher heat losses tend to decelerate it. This effect is 

illustrated in Figure D.24, which shows the pressurizer level comparison among the three cases. 

The timing differences were found to result from competing effects that differentially affect the 

heat-up of the HL and surge line relative to the heat-up of the SG tubes (as discussed in 

Reference D.1) 
D-34

0 3000 6000 9000 12000 15000

Time (s)

0

1000

2000

3000

4000

5000

Heat Flux (W/m2

)

htrnr−504100301 (Case 6A) 

htrnr−504100301 (Base Case) 

htrnr−504100301 (Case 6B) 

0 3000 6000 9000 12000 15000

0.00

0.09

0.18

0.26

0.35

0.44

Heat Flux (Btu/s*ft2

)

Figure D.23 Heat Fluxes from Outer Surface of Reactor Vessel to Containment for the 

RCS Heat Loss Sensitivity Cases 

0 5000 10000 15000 20000

Time (s)

0.0

3.0

6.0

9.0

12.0

15.0

Level (m)

cntrlvar−1150 (Case 6A) 

cntrlvar−1150 (Base Case) 

cntrlvar−1150 (Case 6B) 

0 5000 10000 15000 20000

0.0

9.8

19.7

29.5

39.4

49.2

Level (ft)

Figure D.24 Pressurizer Level Responses for the RCS Heat Loss Sensitivity Cases 
D-35

Reactor Coolant Pump Shaft Seal Leakage Variations

The base case calculation simulates shaft seal leakage in all four RCPs based on an initial 

1.32 L/s [21 gpm] per pump leak rate at the start of the SBO accident event sequence. Eight 

sensitivity runs listed in Table D.2 were performed assuming that changes in the leak rate occur 

two hours following the start of the SBO sequence. 

Of these sensitivity runs, only output data from Case 7A (3.83 L/s [61 gpm]) and Case 7G 

(0.063 L/s [1 gpm]) are used for the purposes of evaluating uncertainties. The uncertainty study 

considers +1.26-L/s [+20-gpm] variations around the 1.32-L/s [21-gpm] nominal leak rate after 

two hours. The output data from Cases 7A and 7G is used to estimate the effects of those 

variations, see discussion for PIRT Parameter C2 in Section D.1.2. 

The discussion of results for the pump seal leakage sensitivity runs is grouped into symmetric 

cases (where the same leakage assumption is used in all four pumps) and unsymmetrical cases 

(where an increased leakage is assumed to occur in only one pump): 

Symmetric Cases (Same Leakage in All Four Pumps) 

The symmetric cases investigate changes in the leakage rates to 0.063 L/s [1 gpm], 

3.83 L/s [61 gpm], 5.66 L/s [90 gpm], 7.54 L/s [120 gpm], 11.4 L/s [182 gpm] and 

18.9 L/s [300 gpm] per pump. These are Cases 7G, 7A, 7E, 7D, 7C and 7B, respectively. 

Figure D.25 compares the Pump 1 leak rates from these six sensitivity cases with that in the 

base case. The figure shows that the calculated relative leakage rates among the seven cases 

are as expected. 

0 5000 10000 15000 20000 25000

Time (s)

0.0

2.0

4.0

6.0

8.0

10.0

Flow Rate (kg/s)

mflowj−12500 (Case 7G, 1 gpm) 

mflowj−12500 (Base Case, 21 gpm) 

mflowj−12500 (Case 7A, 61 gpm) 

mflowj−12500 (Case 7E, 90 gpm) 

mflowj−12500 (Case 7D, 120 gpm) 

mflowj−12500 (Case 7C, 182 gpm) 

mflowj−12500 (Case 7B, 300 gpm) 

0 5000 10000 15000 20000 25000

0.0

4.4

8.8

13.2

17.6

22.0

Flow Rate (lbm/s)

Figure D.25 Pump 1 Leakage Rates for the Symmetric Pump Shaft Seal Leak Sensitivity 

Cases 
D-36

Figure D.26 compares the RCS pressure responses among the seven cases. Prior to 10,637 s, 

when the pressurizer drains, the pressure responses in all runs are virtually the same. While 

pump leakage provides some added capabilities for reducing RCS pressurization, prior to this 

time the pressurization load is high and the pump leakage only results in less frequent opening 

of the pressurizer relief valves. However after the pressurizer drains the RCS steam production 

rate declines, the pressurization load is reduced and the added pump leakage can succeed in 

reducing the RCS pressures. The larger the assumed pump shaft seal leakage rate, the greater 

the RCS pressure relief it provides and the lower the RCS pressures it leads to. 

Figure D.27 compares the Hot Leg 1 upper section fluid temperatures among the seven cases. 

Looking at the period when the heat-up rates are the highest (from about 12,500 s to 13,200 s), 

the figure shows that the heat-up rate is generally proportional to the assumed pump shaft seal 

leakage rate. The exception is for the largest assumed leakage rate, 18.9 L/s [300 gpm] in 

Case 7B, which shows a reduced heat-up rate relative to the next-largest leakage run, Case 7C. 

The pump shaft seal leakage modeling is seen to have a large effect on the SG average tube 

failure margins. For the seven cases (0.063 L/s [1 gpm], 1.32 L/s [21 gpm], 3.83 L/s [61 gpm], 

5.66 L/s [90 gpm], 7.54 L/s [120 gpm], 11.4 L/s [182 gpm] and 18.9 L/s [300 gpm]), stress 

multipliers of 2.08, 2.10, 2.33, 2.50, 3.30, 4.58 and 7.01 respectively are needed for average 

tube failure to occur coincident with the HL failure. As indicated above, lower RCS pressures 

and faster RCS heat-ups are seen as the assumed leakage rate increases. Both of these 

effects promote increased SG tube failure margins. Lower RCS pressures reduce the 

differential pressure across the SG tubes, reducing the potential for their failure. Higher RCS 

heat up rates preferentially favor earlier HL failure relative to SG tube failure (see the discussion 

under “Fuel Rod Cladding Oxidation Variations” above). For 18.9 L/s [300-gpm] Case 7B, the 

heat-up rate is slower than for 11.48 L/s [182-gpm] Case 7C, but the RCS depressurization 

effects are much larger, which leads to the very large calculated SG tube failure margin for 

Run 7B. 

Unsymmetrical Cases (Increased Leakage in Only One Pump) 

The unsymmetrical cases investigate increased leakage rates of 18.9 L/s [300 gpm] in only one 

of the four reactor coolant pumps. In Case 7F, the increased leakage is assumed to be in 

Pump 1 and in Case 7F2 the increased leakage is assumed to be in Pump 2. 

Figure D.28 compares the leak rates from these two cases for the pumps which experience the 

increased leakage. For comparison purposes, the leak rates for these two unsymmetrical cases 

are compared with the leak rate for the 5.66-L/s [90-gpm] symmetric leakage Case 7E (with a 

total leak rate of 22.6 L/s [360 gpm]. The figure shows that the relative leakage rates among 

these three cases are as expected. 

Figure D.29 compares the RCS pressure responses among the three cases. As expected, 

because the total leak rates are about the same for all three cases, the pressure responses are 

similar. SCDAP/RELAP5 did not predict loop seal clearing in any coolant loop in any of the 

calculations described in this report. 

 
D-37

0 5000 10000 15000 20000 25000

Time (s)

0.0

5.0

10.0

15.0

20.0

Pressure (MPa)

p−10001 (Case 7G, 1 gpm) 

p−10001 (Base Case, 21 gpm) 

p−10001 (Case 7A, 61 gpm) 

p−10001 (Case 7E, 90 gpm) 

p−10001 (Case 7D, 120 gpm) 

p−10001 (Case 7C, 182 gpm) 

p−10001 (Case 7B, 300 gpm) 

0 5000 10000 15000 20000 25000

0

725

1450

2176

2901

Pressure (psia)

Figure D.26 RCS Pressures for the Symmetric Pump Shaft Seal Leak Sensitivity Cases 

10000 11000 12000 13000 14000 15000

Time (s)

500

1000

1500

2000

Volume Vapor Temperature (F)

tempg−10001 (Case 7G, 1 gpm) 

tempg−10001 (Base Case, 21 gpm) 

tempg−10001 (Case 7A, 61 gpm) 

tempg−10001 (Case 7E, 90 gpm) 

tempg−10001 (Case 7D, 120 gpm) 

tempg−10001 (Case 7C, 182 gpm) 

tempg−10001 (Case 7B, 300 gpm) 

10000 11000 12000 13000 14000 15000

440

1340

2240

3140

Volume Vapor Temperature (F)

Figure D.27 Hot Leg 1 Fluid Temperatures for the Symmetric Pump Shaft Seal Leak 

Sensitivity Cases 
D-38

0 5000 10000 15000 20000 25000

Time (s)

0.0

2.0

4.0

6.0

8.0

10.0

Flow Rate (kg/s)

mflowj−12500 (Case 7E, 90 gpm symmetric) 

mflowj−12500 (Case 7F, 300 gpm pump 1 only) 

mflowj−22500 (Case 7F2, 300 gpm pump 2 only) 

0 5000 10000 15000 20000 25000

0.0

4.4

8.8

13.2

17.6

22.0

Flow Rate (lbm/s)

Figure D.28 Single-Pump Leakage Rates for the Unsymmetrical Pump Shaft Seal Leak 

Sensitivity Cases 

0 5000 10000 15000 20000 25000

Time (s)

0.0

5.0

10.0

15.0

20.0

Pressure (MPa)

p−10001 (Case 7E, 90 gpm symmetric) 

p−10001 (Case 7F, 300 gpm pump 1 only) 

p−10001 (Case 7F2, 300 gpm pump 2 only) 

0 5000 10000 15000 20000 25000

0

725

1450

2176

2901

Pressure (psia)

Figure D.29 RCS Pressures for the Unsymmetrical Pump Shaft Seal Leak Sensitivity 

Cases 
D-39

Figure D.30 compares the Hot Leg 1 upper section fluid temperatures among the three cases. 

Looking at the period when the heat-up rates are the highest (from about 12,600 s to 13,000 s), 

the figure shows that the heat-up rates among the three runs are similar. 

The pump shaft seal leakage assumptions for the unsymmetrical cases are seen to have only a 

small effect on the SG average tube failure margins. For the four cases (the 1.32-L/s [21-gpm] 

in four pumps base case, the 5.66-L/s [90-gpm] in four pumps Case 7E, the 18.9-L/s [300-gpm] 

in Pump 1 Case 7F and the 18.9-L/s [300-gpm] in Pump 2 Case 7F2) stress multipliers of 2.10, 

2.50, 2.00 and 2.15 respectively are needed for average tube failure to occur coincident with the 

HL. Therefore the average tube failure margins for these four cases are quite similar. Note that 

in Case 7F (with the increased leakage in Pump 1) Hot Leg 2 is the first to fail and the same 

minimum average tube failure margin is calculated in SGs 2, 3 and 4. And, in Case 7F2 (with 

the increased leakage in Pump 2) note that Hot Leg 1 is the first to fail and that the minimum 

average tube failure margin is calculated in SG 3. 

The average tube failure margins calculated for the unsymmetrical pump seal leakage cases 

(7F and 7F2) are moderately lower than that calculated for the symmetrical pump seal leakage 

case with roughly the same total leakage rate (7E). The average tube failure margins for the 

two unsymmetrical cases show only a small effect of moving the leakage from the pressurizer 

loop to a non-pressurizer loop. However, as shown in Table D.3, large differences in the hottest 

tube failure margins are observed among these three cases. 

11000 12000 13000 14000

Time (s)

1200

1400

1600

1800

2000

2200

Volume Vapor Temperature (K)

tempg−10001 (Case 7E, 90 gpm symmetric) 

tempg−10001 (Case 7F, 300 gpm pump 1 only) 

tempg−10001 (Case 7F2, 300 gpm pump 2 only) 

11000 12000 13000 14000

1700

2060

2420

2780

3140

3500

Volume Vapor Temperature (F)

Figure D.30 Hot Leg 1 Fluid Temperatures for the Unsymmetrical Pump Shaft Seal Leak 

Sensitivity Cases 
D-40

D.2.2 Additional Sensitivity Runs 

Additional sensitivity runs identified with asterisks in Table D.2 are used to investigate various 

modeling, plant configuration and event-sequence assumption issues which are unrelated to the 

uncertainty evaluation. The results for these additional sensitivity runs are summarized as 

follows: 

Effect of Configuration of the Hot Leg-to-Surge Line Connection

The base case calculation models the surge line connection on the side of Hot Leg 1, which is 

consistent the configuration of some Westinghouse plants. A sensitivity run, Case 8A, was 

performed with the surge line connection moved from the side to the top of Hot Leg 1. This run 

was made to evaluate the behavior for a top-mounted surge line, which is the connection 

configuration in other Westinghouse plants. 

Figure D.31 compares the pressurizer surge line fluid temperatures (near the HL connection) 

from Case 8A (with the top-mounted surge line) and the base case (with the side mounted 

surge line). The figure shows that, as expected, the surge line temperatures are higher when 

the surge line is connected on the top of the HL. 

In the base case the HL failed first, at 13,630 s, followed by the surge line at 13,960 s. 

However, in Case 8A, the surge line failed first, at 13,660 s, followed by the HL at 13,720 s. 

Although the time of the first primary piping component failure is about the same in the two runs, 

the additional extra energy removed from the RCS through the pressurizer relief valves due to 

the hotter surge line flow in Case 8A reduced the heat-up rate in the rest of the system, 

including the SGs. The average SG tube failure margin increased slightly from a stress 

multiplier of 2.10 in the base case run to 2.33 in Case 8A. The consideration of the surge line 

connection location on the circumference of the HL therefore has a moderate effect on the SG 

tube failure margin. 

Effect of Stuck-Open Steam Generator Relief Valve

The base case calculation models nominal steam leakage from the secondary systems of all 

four SGs but no stuck-open relief valve on any SG. A sensitivity run, Case 8B, was performed 

assuming the secondary system PORV on SG 1 sticks open (at the time of its first opening) and 

no steam leakage in the other three SGs. Case 8B was run for historical comparison purposes, 

using assumptions consistent with those in the earlier analyses described in Sections 2.3 

and 2.4. 

The SG secondary pressure responses for Case 8B and the base case are compared in 

Figure D.32 for SG 1 and in Figure D.33 for SG 2. The SG 1 pressures experienced at the time 

when the HL failure occurs (14,060 s in Case 8B and 13,630 s in the base case) are not 

significantly different between the two runs. 

Figure D.34 compares the Hot Leg 1 upper section fluid temperatures (near the RV) for 

Case 8B and the base case. The different SG secondary pressure responses lead to a event 

timing difference between the two runs, however the figure shows that the heat-up rates at the 

times when the HL fails are very similar. 
D-41

8000 10000 12000 14000 16000

Time (s)

500

1000

1500

2000

Volume Vapor Temperature (K)

tempg−15307 (Case 8A) 

tempg−15307 (Base Case) 

8000 10000 12000 14000 16000

440

1340

2240

3140

Volume Vapor Temperature (F)

Figure D.31 Pressurizer Surge Line Fluid Temperature for the Top Mounted Surge Line 

Sensitivity Case 

0 5000 10000 15000 20000

Time (s)

0.0

2.0

4.0

6.0

8.0

Pressure (MPa)

p−18001 (Case 8B) 

p−18001 (Base Case) 

0 5000 10000 15000 20000

0

290

580

870

1160

Pressure (psia)

Figure D.32 SG 1 Pressure for the Stuck-Open SG Safety Relief Valve Sensitivity Case 
D-42

0 5000 10000 15000 20000

Time (s)

0.0

2.0

4.0

6.0

8.0

Pressure (MPa)

p−28001 (Case 8B) 

p−28001 (Base Case) 

0 5000 10000 15000 20000

0

290

580

870

1160

Pressure (psia)

Figure D.33 SG 2 Pressure for the Stuck-Open SG Safety Relief Valve Sensitivity Case 

0 5000 10000 15000 20000

Time (s)

500

1000

1500

2000

Volume Vapor Temperature (K)

tempg−10001 (Case 8B) 

tempg−10001 (Base Case) 

0 5000 10000 15000 20000

440

1340

2240

3140

Volume Vapor Temperature (F)

Figure D.34 Hot Leg 1 Fluid Temperature for the Stuck-Open SG Safety Relief Valve 

Sensitivity Case 
D-43

Since the temperature and pressure responses of the two runs are similar, little difference is 

noted in the average SG 1 tube failure margins. The failure margin decreased only slightly from 

a stress multiplier of 2.10 in the base case to 2.05 in Case 8A. This result occurs because the 

SG 1 steam leakage rate seen in the base case is sufficient to fully depressurize all of the SGs 

before the maximum system heat up rate is experienced. See “Effect of Varying SG Secondary 

Leakage Rate” below for considerations related to the assumed size of the steam leakage path. 

Effect of Varying the SG Secondary Leakage Flow Area

A sensitivity run, Case 8G, was performed to evaluate behavior using different assumptions for 

the SG steam leakage flow area. For this run, a different steam leakage flow area was used in 

each of the four SGs. Flow areas representing 80%, 60%, 40% and 20% of the 3.23-cm2

 [0.5-

in2

] per SG leak flow area assumed in the base case calculation were used in SGs 1 through 4, 

respectively. 

Figure D.35 compares the SG secondary pressure responses for the SGs from Case 8G with 

0.65-cm2

 [0.1-in2], 1.29-cm2 [0.2-in2], 1.94-cm2 [0.3-in2], and 2.58-cm2 [0.4-in2] leak flow areas in 

their secondary systems with the base case SG pressure. As expected the SG 

depressurization rate is proportional to the size of the assumed leak flow area. 

The average-tube failure margins from Case 8G are compared with the base case margins in 

Table D.5 (note that in the base case run the minimum margin is in the pressurizer loop SG and 

margins are slightly higher in the non-pressurizer loop SGs). The results indicate that the SG 

tube failure margin increases gradually as the leak flow area is decreased from 3.23 cm2

[0.5 in2

] to 1.94 cm2 [0.3 in2], and then increases significantly faster as the flow area falls below 

1.94 cm2

 [0.3 in2]. 

Surge Line and Hot Leg Wall Inside Surface Heat Transfer Coefficient Variation

A sensitivity run, Case 8D, was performed to simulate increased heat transfer from the fluid to 

the inside surfaces of the surge line and HL upper section walls. A multiplier of 2.0 was placed 

on the heat transfer coefficients employed in the base case for the combination of convection 

and steam-to-wall radiation heat transfer. No change was made in the HL wall-to-wall radiation 

heat transfer modeling. 

Figure D.36 compares the heat transfer coefficient on the inside surface of the upper section of 

Hot Leg 1 (near the RV) for Case 8D and the base case. The increase in the heat transfer 

coefficient in Case 8D is as expected (the comparisons at other locations within the upper HL 

sections and the pressurizer surge line are similar). 

The heat transfer modeling revisions in Case 8D are seen to result in a moderate increase in 

the SG average tube failure margin. Stress multipliers of 2.96 and 2.10, respectively, are 

needed for average tube failure to occur coincident with the HL using the increased and nominal 

HL and pressurizer surge line heat transfer coefficients. 

This margin improvement results because the increased heat transfer coefficient leads to faster 

heat-up of the HL wall (and earlier HL failure) and slower heat-up of the SG tubes (and later SG 

tube failure). Figure D.37 compares the Hot Leg 1 upper section wall temperatures for the two 

cases and Figure D.38 compares the SG 1 hot average tube wall temperatures for the two 

cases. 
D-44

0 5000 10000 15000 20000 25000 30000

Time (s)

0.0

2.0

4.0

6.0

8.0

Pressure (MPa)

p−18001 (Base Case, 0.5 in2) 

p−18001 (Case 8G, 0.4 in2) 

p−28001 (Case 8G, 0.3 in2) 

p−38001 (Case 8G, 0.2 in2) 

p−48001 (Case 8G, 0.1 in2) 

0 5000 10000 15000 20000 25000 30000

0

290

580

870

1160

Pressure (psia)

Figure D.35 SG Secondary Pressures for the SG Secondary Leakage Sensitivity Cases 

8000 10000 12000 14000 16000

Time (s)

0

500

1000

1500

2000

Heat Transfer Coefficient (W/m2*K)

hthtc−100100100 (Case 8D) 

hthtc−100100100 (Base Case) 

8000 10000 12000 14000 16000

0.0

88.1

176.1

264.2

352.2

Heat Transfer Coefficient (Btu/hr*ft2*F)

Figure D.36 Hot Leg 1 Inside Surface Heat Transfer Coefficient for the Hot Leg and 

Surge Line Heat Transfer Sensitivity Cases 
D-45

8000 10000 12000 14000 16000

Time (s)

500

1000

1500

2000

Heat Structure Temperature (K)

htvat−1001001 (Case 8D) 

htvat−1001001 (Base Case) 

8000 10000 12000 14000 16000

440

1340

2240

3140

Heat Structure Temperature (F)

Figure D.37 Hot Leg 1 Wall Temperature for the Hot Leg and Surge Line Heat Transfer 

Sensitivity Cases 

8000 10000 12000 14000 16000

Time (s)

600

800

1000

1200

Heat Structure Temperature (K)

htvat−1101001 (Case 8D) 

htvat−1101001 (Base Case) 

8000 10000 12000 14000 16000

620

980

1340

1700

Heat Structure Temperature (F)

Figure D.38 SG 1 Hot Average Tube Wall Temperature for the Hot Leg and Surge Line 

Heat Transfer Sensitivity Cases 
D-46

Table D.5 SCDAP/RELAP5-Calculated Results for Case 8G, Evaluating Sensitivity 

to SG Secondary Steam Leak Flow Area Assumptions 

SG 

Number Case Leak Flow Area (in2

) 

Average SG Tube Failure Margin 

(Stress Multiplier for Tube Failure 

Coincident with Hot Leg Failure) 

1 Base 3.23 cm2 [0.5 in2] 2.100 

1 8G 2.58 cm2 [0.4 in2] 2.076 

2 Base 3.23 cm2 [0.5 in2] 2.150 

2 8G 1.94 cm2 [0.3 in2] 2.303 

3 Base 3.23 cm2 [0.5 in2] 2.133 

3 8G 1.29 cm2 [0.2 in2] 2.679 

4 Base 3.23 cm2 [0.5 in2] 2.150 

4 8G 0.65 cm2 [0.1 in2] 2.909 

Tubesheet Wall Inside Surface Heat Transfer Coefficient Variation

A sensitivity run, Case 8E, was performed to simulate increased heat transfer from the fluid to 

the SG tubesheet structures. A multiplier of 2.0 was placed on the heat transfer coefficients 

employed in the base case for the combination of convection and steam-to-wall radiation heat 

transfer. 

Figure D.39 compares the heat transfer coefficient on the SG 1 tubesheet (near the SG inlet 

plenum) for Case 8E and the base case. The increase in the heat transfer coefficient in Case 

8E is as expected at this location (the comparisons at other tubesheet locations are similar). 

The heat transfer modeling revisions in Case 8E are seen to result in a small increase in the SG 

average tube failure margin. Stress multipliers of 2.20 and 2.10, respectively, are needed for 

average tube failure to occur coincident with the HL using the increased and nominal tubesheet 

heat transfer coefficients. 

This margin improvement results because the increased heat transfer coefficient leads to a 

faster heat-up of the tubesheet wall and a slower heat-up of the SG tubes (and later SG tube 

failure). Figure D.40 compares the SG 1 tubesheet wall temperatures for the two cases and 

Figure D.41 compares the SG 1 hot average tube wall temperatures for the two cases. 

Effect of Pre-Existing Steam Generator Tube Leakage

The base case calculation assumes no SG tube leakage exists. A sensitivity run, Case 8C, was 

performed assuming that a tube leakage path with an initial flow rate of 6.29 L/s [100 gpm] in 

SG 1 exists at the start of the SBO accident event sequence. The leak is assumed to be 

located midway between the tubesheet and the top of the U-bend in the hot average tube. To 

implement the tube leakage into the model, a valve with a flow area of 0.5972 cm2

[0.0006428 ft2

] was added to the model at the start of the transient event sequence calculation. 
D-47

8000 10000 12000 14000 16000

Time (s)

0

500

1000

1500

2000

Heat Transfer Coefficient (W/m2*K)

hthtc−110200100 (Case 8E) 

hthtc−110200100 (Base Case) 

8000 10000 12000 14000 16000

0.0

88.1

176.1

264.2

352.2

Heat Transfer Coefficient (Btu/hr*ft2*F)

Figure D.39 SG 1 Tubesheet Heat Transfer Coefficient for the Tubesheet Heat Transfer 

Sensitivity Cases 

8000 10000 12000 14000 16000

Time (s)

600

800

1000

1200

Heat Structure Temperature (K)

htvat−1102001 (Case 8E) 

htvat−1102001 (Base Case) 

8000 10000 12000 14000 16000

620

980

1340

1700

Heat Structure Temperature (F)

Figure D.40 SG 1 Tubesheet Wall Temperature for the Tubesheet Heat Transfer 

Sensitivity Cases 
D-48

8000 10000 12000 14000 16000

Time (s)

600

800

1000

1200

Heat Structure Temperature (K)

htvat−1101001 (Case 8E) 

htvat−1101001 (Base Case) 

8000 10000 12000 14000 16000

620

980

1340

1700

Heat Structure Temperature (F)

Figure D.41 SG 1 Hot Average Tube Wall Temperature for the Tubesheet Heat Transfer 

Sensitivity Cases

This flow area represents a circular hole with a diameter of 0.871 cm [0.343 in]; therefore the 

leak flow area is less than the equivalent flow area of a single SG tube. 

The SG 1 inlet plenum flow losses were adjusted to attain the following revised set of target 

values for the mixing and flow parameters: hot leg discharge coefficient 0.14 (versus 0.12 in the 

base case), recirculation ratio 1.75 (versus 2.0 in the base case) and hot and cold mixing 

fractions 0.75 (versus 0.85 in the base case). These revised target values resulted from CFD 

evaluations of the fluid conditions expected in a coolant loop with a leaking SG tube. No 

changes were made to the SG inlet plenum flow losses in the other three SGs. 

The tube leakage mass flow rate from Case 8C is shown in Figure D.42. The flow rate is erratic 

due to the changing transient conditions in the RCS and SG secondary, but it generally trends 

downward as the leaking fluid changes from water at the beginning of the event sequence to 

saturated steam and then to superheated steam. 

Relative to the base case, the results for Case 8C indicate improved SG tube failure margins for 

both the hottest tube in SG 1 and the average tube in SG 1. The hottest SG 1 tube fails 2,235 s 

after the HL fails in Case 8C, while in the base case it failed 155 s earlier than the HL. The 

SG 1 average tube stress multiplier required for tube failure coincident with HL failure rose from 

2.10 in the base case to 2.94 in Case 8C as a result of the relative changes in the HL and SG 1 

average tube failure times. 
D-49

0 5000 10000 15000 20000

Time (s)

0.0

1.0

2.0

3.0

4.0

5.0

Flow Rate (kg/s)

mflowj−14000 (Case 8C) 

0 5000 10000 15000 20000

0.0

2.2

4.4

6.6

8.8

11.0

Flow Rate (lbm/s)

Figure D.42 Tube Leak Rate for the SG Tube Leakage Sensitivity Case 

Figures D.43 and D.44, respectively, compare the Hot Leg 1 upper section and SG 1 average 

tube wall temperatures from the two runs. From the base case calculation to the Case 8C 

calculation, comparable changes are seen in the times when the HL and tube temperatures rise 

rapidly. Therefore, the improved SG tube failure margins in Case 8C do not result from 

changes in the relative timing of structure heat-up. 

Figures D.45 and D.46, respectively, compare the Hot Leg 1 and SG 1 secondary pressures 

from the two runs. On the primary side, the tube leakage leads to moderately more 

depressurization than seen in the base case. Less frequent pressurizer PORV opening is seen 

in Case 8C, however the peak RCS pressures and the behavior of the RCS pressure during the 

period when structure failures occur are nearly the same for the two cases. On the SG 1 

secondary side, the tube leakage causes the pressure to be significantly higher in Case 8C than 

in the base case. The differential pressure from primary to secondary in Case 8C is therefore 

much less than seen in the base case, and this is the explanation for the increased SG 1 failure 

margins. 

The tube failure margin improvements for the SG 1 tubes are not shared by the tubes in the 

other three SGs. The tube leakage in SG 1 does not affect the secondary pressures in SGs 2, 3 

and 4 and no readjustments of SG inlet plenum flow losses are made in SGs 2, 3 and 4. As a 

result, for Case 8C the limiting tube failure moves from SG 1 to SG 3. The increase in the SG 3, 

2.0-multiplier average tube failure time from the base case to Case 8C is virtually identical to 

that seen for the HL failure time. Therefore, only a small improvement is seen in the limiting 

average tube failure margin (a stress multiplier for tube failure coincident with HL failure of 2.21 

for the SG-3 tube in Case 8C, versus 2.10 for the SG-1 tube in the base case). The conclusion 

is therefore that the effect of pre-existing SG tube leakage in a single SG does not significantly 

affect the overall outcome of the analysis. 
D-50

0 5000 10000 15000 20000

Time (s)

500

1000

1500

2000

Heat Structure Temperature (K)

htvat−1001001 (Case 8C) 

htvat−1001001 (Base Case) 

0 5000 10000 15000 20000

440

1340

2240

3140

Heat Structure Temperature (F)

Figure D.43 Hot Leg 1 Upper Section Wall Temperature for the SG Tube Leakage 

Sensitivity Case 

0 5000 10000 15000 20000

Time (s)

400

600

800

1000

1200

1400

Heat Structure Temperature (K)

htvat−1101001 (Case 8C) 

htvat−1101001 (Base Case) 

0 5000 10000 15000 20000

260

620

980

1340

1700

2060

Heat Structure Temperature (F)

Figure D.44 SG 1 Average Tube Wall Temperature for the SG Tube Leakage Sensitivity 

Case 
D-51

0 5000 10000 15000 20000

Time (s)

8.0

10.0

12.0

14.0

16.0

18.0

Pressure (MPa)

p−10001 (Case 8C) 

p−10001 (Base Case) 

0 5000 10000 15000 20000

1160

1450

1740

2031

2321

2611

Pressure (psia)

Figure D.45 Hot Leg Pressure for the SG Tube Leakage Sensitivity Case 

0 5000 10000 15000 20000

Time (s)

0.0

2.0

4.0

6.0

8.0

10.0

Pressure (MPa)

p−18001 (Case 8C) 

p−18001 (Base Case) 

0 5000 10000 15000 20000

0

290

580

870

1160

1450

Pressure (psia)

Figure D.46 SG 1 Secondary Pressure for the SG Tube Leakage Sensitivity Case 
D-52

It is noted, however, that the Case 8C event sequence evaluated here does not include rapid 

depressurization of the SG secondary systems that could result, for example, from a stuck-open 

relief valve or main steam line break. The analysis results may be different for a case where the 

pre-existing SG tube leakage resides in a rapidly-depressurizing SG. 

D.3 Estimates of Uncertainties in the SCDAP/RELAP5 Calculation Output 

Section D.3.1 describes the method used to estimate the uncertainties in the 

SCDAP/RELAP5-calculated responses for the key output parameters, the dependent variables. 

The method compares the output from the SCDAP/RELAP5 base case calculation and 

sensitivity calculations performed to evaluate the changes in the dependent variables resulting 

from variations in the independent variables (which are parameters deemed by the PIRT 

evaluation to be important for the simulation of the dependent variables). The uncertainty 

evaluation results are described in Section D.3.2 

D.3.1 Methods for Estimating Uncertainties 

The eight dependent variables for the uncertainty study are the key parameters used by the 

project stress analysts and PRA analysts (see Section 2.7.2): 

 Failure margin for average SG tube 

 Failure margin for hottest SG tube 

 Average SG tube metal temperature 

 Hottest SG tube metal temperature 

 HL steam temperature 

 HL piping wall inner surface heat transfer coefficient 

 Pressurizer surge line steam temperature 

 Pressurizer surge line piping wall inner surface heat transfer coefficient 

The exact descriptions (location, evaluation time, smoothing process, etc.) selected for each of 

the dependent variables are provided in Section D.1.1. 

The PIRT identified 15 parameters important for the plant thermal-hydraulic response; these are 

the independent variables for the uncertainty study (see Section 2.7.3). For each PIRT 

parameter, the thermal-hydraulic phenomena, the event sequence assumptions and 

progression, the current SCDAP/RELAP5 modeling, experience from prior sensitivity analyses 

and prior SCDAP/RELAP5 assessments were evaluated. From these evaluations, the list of 19 

sensitivity runs in Table D.2 was developed to generate statistics needed for the uncertainty 

evaluation. The sensitivity runs incorporate variations into the model that cover the expected 

ranges of the important PIRT parameters. The sensitivity run output for the temperatures, heat 

transfer coefficients and SG tube failure margins is then compared against the corresponding 

output from the base case calculation and the differences are used to estimate the uncertainties 

in the dependent variables. 

A paper by Macdonald, Clark and Strachan (Reference D.20) describes methods for assessing 

the uncertainty in simulation of building energy and environmental responses. The situation 

described in the paper is analogous in many respects to the subject analysis of this report. A 

model of the physical building is assembled (similar to the SCDAP/RELAP5 plant model) 

consistent with the geometry, materials, and initial and boundary conditions. To characterize 

the building performance, the model is run using simulation software (similar to the 
D-53

SCDAP/RELAP5 computer code) to represent the physical processes, such as flow of heat and 

moisture. 

Reference D.20 indicates that the traditional and most widely-used methods for assessing 

uncertainty are based on sensitivity analysis. Sensitivity analysis allows assessing the 

relationship between variations in input parameters and resulting variations in the output 

predictions. The sources of uncertainty affecting the model need to be identified and quantified, 

which for this application has been accomplished through the PIRT and subsequent evaluations 

related to the PIRT parameters. Reference D.20 describes a differential sensitivity analysis 

method which is adopted here. This method requires a base case simulation in which the input 

parameters are set to represent their best-estimate conditions. The simulation is then repeated 

with one input parameter varied to represent its expected extreme variation in one direction and 

the effect on the output variables are noted. The method assumes linearity, which means that 

variation of the input parameter in the opposite direction results in corresponding opposite 

variations in the output variables. 

A differential sensitivity analysis is not optimized for the number of simulations required and 

does not identify parameter interactions, for which factorial designs could be used. In this 

analysis, the number of uncertain parameters is ten and 19 sensitivity runs have been 

performed in addition to the base case run. A full factorial analysis for ten parameters would 

require 1,024 SCDAP/RELAP5 runs, although fractional factorial design approaches could 

reduce the number of runs somewhat. An alternate approach for addressing parameter 

interactions using Bayesian Networks (also involving additional sensitivity runs) could be used. 

Given the complexity of performing SCDAP/RELAP5 runs, it was judged for this project that 

expanding the number of runs past 20 cannot be justified at this time for economic reasons. 

Instead, maximum use is made of the 19 sensitivity runs to determine rough estimates for the 

uncertainties in the temperatures, heat transfer coefficients and SG tube failure margins. These 

rough uncertainty estimates will be provided to the stress and probabilistic risk analysts. Should 

it later be found that the uncertainties in the thermal-hydraulic results dominate the uncertainties 

in the overall project results, then the additional effort to use a fractional factorial or Bayesian 

Network approach for addressing the interactions among the parameters may be justified. 

It is assumed that the set of sensitivity runs is normally distributed (i.e., based on a Gaussian 

distribution with the shape of the “bell curve”) around the base case run. 

Reference D.21 provides the following formula for the standard deviation, σx, of N readings of 

parameter x around a mean value, m: 

 N 

σx = { [ 1.0 / ( N – 1.0 ) ] Σ ( xi – m )2 }

0.5

 i=1 

For this application, N (the number of sensitivity runs) is 19, the xi are the values for the 

dependent variable output variables from the sensitivity runs and m is the corresponding values 

for the dependent variables from the output of the base case run. The primary results from the 

uncertainty study are the values for σx, representing rough estimates for the standard deviations 

of the SCDAP/RELAP5 calculated results, for the eight dependent variables (the SG tube failure 

margins, temperatures and wall heat transfer coefficients). For this report, the standard 

deviations in the dependent variables are reported first using the above approach. 
D-54

Next, for some of the xi parameters, there are indications that the distribution around the base 

case values may not be symmetric. For example, plant operating experience suggests that it is 

more likely that our base case calculation is underpredicting, rather than overpredicting, the 

heat loss from the RCS into the containment. The effects of modifying the standard deviation 

calculation in the following manner, which introduces weighting factors, wi, to account for known 

unsymmetrical behavior, are evaluated: 

 N 

σx = { [ 1.0 / ( N – 1.0 ) ] Σ [ wi ( xi – m )2 ] }0.5

 i=1 

This weighting-factor approach introduces, in a simplistic way, the concept of distributions in the 

independent variables, such as featured in factorial, response surface approaches to 

uncertainty evaluation. In this report the standard deviations in the dependent variables are 

also reported using this second, weighting-factor approach. 

Finally, consideration is added that the 20 runs (base case and 19 sensitivity cases) collectively, 

rather than the base case alone, represent the true mean. With this approach, the total 

uncertainty includes the effects of uncertainty in the mean itself, not just an uncertainty due to 

distribution around the mean. From Reference D.21 the uncertainty in the mean σm is given by: 

σm = σx / N0.5

For the purposes here a revised total standard deviation, σ, is developed by combining the 

uncertainty in the mean with the uncertainty of the distribution around that mean: 

σ = [ σm

2

 + σx

2

 ]0.5 = σx [ ( 1.0 / N0.5 )2 + 1.02 ]

0.5

For N = 20, this becomes: σ = 1.025 σx

The standard deviations provided in this report are therefore calculated using both unweighted 

and weighted approaches, with and without application of a multiplier that considers the 

uncertainty in the mean. 

D.3.2 Uncertainty Estimate Results 

The SCDAP/RELAP5-calculated results for the eight dependent variables (temperatures, heat 

transfer coefficients and SG tube failure margins) for the SBO base case run and the 

19 sensitivity runs are shown in Tables D.4 and D.5. For each sensitivity run, the differences 

between the results for the sensitivity and base case runs are taken for each dependent 

variable. Tables D.6 and D.7 compile the differences between the sensitivity and base case run 

results. The differences are calculated by subtracting the base case dependent variable values 

from the corresponding sensitivity run dependent variable values. 

As identified in the tables, the differences listed for certain runs reflect adjustments made to the 

output data from the SCDAP/RELAP5 sensitivity case calculations. The runs for Cases 2A 

and 2B were performed to consider +15% variations in the hot leg discharge coefficient. It was 

subsequently judged that larger variations are needed to bound the expected ranges for that 

parameter. The differences shown for Cases 2A and 2B represent twice the differences 

calculated between those runs and the base case run, thereby effectively representing +30% 

variations in the hot leg discharge coefficient. The differences shown for Cases 4A and 4B 
D-55

(variations in the fuel rod oxidation power) were adjusted to account for slight changes seen in 

the calculated response as a result of implementing the model features needed to perform the 

sensitivity runs (see discussion for PIRT Parameter B1 in Section D.1.2). The differences 

shown for Case 7A (3.83-L/s [61-gpm] per pump shaft seal leakage after two hours) reflect 

adjustments, based on interpolation of results, to represent a 41-gpm RCP shaft seal leakage 

rate assumption (see discussion for PIRT Parameter C2 in Section D.1.2). 

For each of the dependent variables, the relative magnitudes of the differences associated with 

the sensitivity cases in Tables D.6 and D.7 reflect their influence on the overall uncertainty. For 

three of the dependent variables (average SG tube failure margin, average SG tube wall 

temperature and hottest SG tube wall temperature), the uncertainties from many independent 

variables contribute relatively-equally to the overall uncertainty. For the other five dependent 

variables, the overall uncertainty is dominated by the contributions from only a few of the 

independent variables. When the number of dependent variables for which the individual 

contributions are considered dominant are counted, the following cases are seen to have the 

most important effect on the overall uncertainties (in decreasing order of importance): Case 5A 

(50% decrease in RV internal circulation rate), Case 4B (50 % decrease in fuel rod oxidation 

power) and Case 7A (RCP shaft seal leakage increased to 2.50 L/s [41 gpm] per pump at two 

hours). 

Standard deviations were calculated for each of the eight dependent variables using the 

methods described in Section D.3.1. The standard deviation results shown in Table D.8 were 

calculated with four different approaches: using equal-weighting and biased-weighting of the 

independent-variable terms and with and without considering the effects of uncertainty in the 

mean. 

The biased-weighting approach takes advantage of information, where available, regarding the 

likelihoods of the variation of a parameter in one direction versus the other direction. Pertinent 

information may be available from plant operating experience, the assessment of SCDAP 

models against specific severe accident experiments and the assessment of RELAP5 models 

against a much larger set of general reactor safety-related thermal-hydraulic experiments. The 

scheme by which biased weighting was applied in this analysis is described as follows. 

For most of the independent variables, there was no known basis supporting the weighting of 

variations in one direction differently than those in the other direction. For the cases in this 

category (1A, 1B, 2A through 2G, 3A and 3B), weighting factors of 1.0 were used. 

For the fuel rod oxidation power sensitivity cases, there are pertinent prior assessments of 

SCDAP/RELAP5 capabilities for predicting hydrogen generation in nine tests and five 

experimental facilities (see Section 3.2.2). In these assessments, the code underpredicted 

hydrogen generation in seven tests and overpredicted it in two tests. To account for this 

underprediction bias, the results for Case 4A (oxidation rate x 1.2) are weighted by 

(2 x 7 / 9 =) 1.556 and the results for Case 4B (oxidation rate x 0.5) are weighted by 

(2 x 2 / 9 =) 0.444. 

For the vessel internal circulation sensitivity, years of general RELAP5 assessment background 

suggests that, due to numerical difficulties, the code is much more likely to overpredict 

circulation rates than to underpredict them. To account for this overprediction bias, the results 

for Case 5A (50% decrease in vessel circulation rate) are weighted by (2 x 2 / 3 =) 1.333 and 

the results for Case 5B (100% increase in vessel circulation rate) are weighted by 

(2 x 1 / 3 =) 0.667. 
D-56

Table D.6 Compilation of Differences Between the SCDAP/RELAP5-Calculated 

Results from the Sensitivity and Base Case Runs for the SG Tube Failure 

Margin and SG Tube Temperature Dependent Variables 

Case Number 

and 

Description of the 

Variation 

Difference in 

SG 1 Hottest 

Tube with 1.0 

Multiplier 

Failure Time – 

First Primary 

Failure Time(s) 

Difference in 

SG 1 Average 

Tube Stress 

Multiplier for 

Tube Failure 

Coincident with 

First Primary 

Failure (-) 

Difference in 

SG 1 

Average 

Tube 

Structure 

Temperature 

(K) 

Difference in 

SG 1 Hottest 

Tube 

Structure 

Temperature

(K) 

Case 1A, Pressurizer PORV 

and SRV flow areas x 1.3 0.02 -0.03 1.33 -0.08 

Case 1B, Pressurizer PORV 

and SRV flow areas x 0.7 4.99 0.01 -0.78 -0.91 

Case 2A (adjusted), Hot Leg 

Discharge Coefficient x 1.3 0.04 -0.37 35.32 28.98 

Case 2B (adjusted), Hot Leg 

Discharge Coefficient x 0.7 40.00 0.57 -43.71 -42.46 

Case 2C, recirculation ratio 

= 2.3 -14.99 0.08 -7.10 8.02 

Case 2D, recirculation ratio 

= 1.7 19.98 -0.08 6.88 -22.54 

Case 2E, mixing fractions = 

0.95 9.99 0.40 -34.95 -13.62 

Case 2F, mixing fractions = 

0.75 -4.98 -0.29 31.31 7.49 

Case 2G, assumed hot/cold 

tube split = 50%/50% 15.00 0.11 -7.84 -22.32 

Case 3A, SG tube wall 

outside surface HTC x 5.0 120.02 0.25 -20.96 -66.66 

Case 3B, SG tube wall 

outside surface HTC x 0.5 -5.02 -0.03 2.07 8.87 

Case 4A (adjusted), fuel rod 

oxidation power x 1.2 -14.98 0.06 -3.23 0.47 

Case 4B (adjusted), fuel rod 

oxidation power x 0.5 64.94 -0.19 9.26 -50.06 

Case 5A, vessel internal 

circulation rate x 0.5 -104.98 0.18 -22.49 -82.11 

Case 5B, vessel internal 

circulation rate x 2.0 65.01 -0.13 10.10 -8.30 

Case 6A, 2 MW total RCS 

heat loss 14.97 0.02 -3.74 -4.65 

Case 6B, 8 MW total RCS 

heat loss -99.98 -0.18 19.04 11.01 

Case 7A (adjusted), 41 gpm 

pump seal leakage after 2 

hours 

-27.50 0.11 -11.93 -29.73 

Case 7G, 1 gpm pump 

leakage after 2 hours 15.00 -0.02 1.32 -5.04 
D-57

Table D.7 Compilation of Differences Between the SCDAP/RELAP5-Calculated 

Results from the Sensitivity and Base Case Runs for the Hot Leg and 

Surge Line Temperature and Heat Transfer Coefficient Dependent 

Variables 

Case Number 

and 

Description of the Variation 

Difference in 

Hot Leg 1 

Steam 

Temperature 

(K) 

Difference in 

Hot Leg 1 Wall 

Inside Surface 

HTC 

(W/m2

-K) 

Difference in 

Surge Line 

Steam 

Temperature 

(K) 

Difference in 

Surge Line 

Wall Inside 

Surface HTC

(W/m2-K) 

Case 1A, Pressurizer PORV 

and SRV flow areas x 1.3 -4.12 11.40 5.25 71.44 

Case 1B, Pressurizer PORV 

and SRV flow areas x 0.7 -2.23 -10.23 -2.45 -36.03 

Case 2A (adjusted), Hot Leg 

Discharge Coefficient x 1.3 -62.60 11.71 -24.78 20.45 

Case 2B (adjusted), Hot Leg 

Discharge Coefficient x 0.7 -63.00 -47.42 -52.80 -30.15 

Case 2C, recirculation ratio = 

2.3 -46.67 1.13 -23.86 70.79 

Case 2D, recirculation ratio = 

1.7 -46.23 -18.86 -24.19 -19.90 

Case 2E, mixing fractions = 

0.95 -50.94 -15.23 -20.80 26.32 

Case 2F, mixing fractions = 

0.75 4.27 15.04 -4.04 52.12 

Case 2G, assumed hot/cold 

tube split = 50%/50% 12.30 -15.78 3.98 -47.96 

Case 3A, SG tube wall 

outside surface HTC x 5.0 -38.13 -9.30 -19.28 8.94 

Case 3B, SG tube wall 

outside surface HTC x 0.5 -25.01 -9.95 -18.03 -26.87 

Case 4A (adjusted), fuel rod 

oxidation power x 1.2 -9.26 15.71 -4.89 57.40 

Case 4B (adjusted), fuel rod 

oxidation power x 0.5 -98.33 -125.20 -98.42 -247.09 

Case 5A, vessel internal 

circulation rate x 0.5 -172.77 -42.22 -124.27 -22.12 

Case 5B, vessel internal 

circulation rate x 2.0 24.48 -0.33 32.69 36.53 

Case 6A, 2 MW total RCS 

heat loss -11.97 -8.00 -8.23 -28.26 

Case 6B, 8 MW total RCS 

heat loss -36.20 -4.09 -47.52 -0.46 

Case 7A (adjusted), 41 gpm 

pump seal leakage after 2 

hours 

-22.41 -29.25 -122.72 -105.55 

Case 7G, 1 gpm pump 

leakage after 2 hours -40.73 -1.86 -12.28 71.64 
D-58

For the heat loss sensitivity, an EPRI report (Reference D.18) indicates that vessel and piping 

insulation installed in plants is in general performing more poorly than designed. This suggests 

that a higher RCS heat loss is more likely than a lower RCS heat loss. To account for this bias, 

the results for Case 6A (2 MW total RCS heat loss) are weighted by (1 x 2 / 3 =) 0.667 and the 

results for Case 6B (8 MW total RCS heat loss) are weighted by (2 x / 3 =) 1.333. 

Finally, for the RCP shaft seal leak sensitivity, +1.262 L/s [+20 gpm] variations around the 

nominal 1.325 L/s [21 gpm] per pump leakage are assumed. This uncertainty accounts for 

several factors related to: (1) predicting the correct conditions upstream of the leak, 

(2) adequately representing the complex geometry of the pump shaft seal configuration and 

(3) general considerations regarding the prediction capabilities of the RELAP5 critical flow 

model. Case 7G (1 gpm leakage per pump after two hours) considers that the code might 

underpredict the leak flow by a factor of (21 / 1 =) 21.0. Case 7A (adjusted for 41 gpm leakage 

per pump after two hours) considers that the code might overpredict the flow by a factor of 

(41 / 21 =) 1.95. Since RELAP5 code assessment experience shows no general bias for the 

code either underpredicting or overpredicting critical flows, the results for these two cases are 

weighted (90% x 2 =) 1.8 for Case 7A (adjusted for 41 gpm) and (10% x 2 =) 0.2 for Case 7G 

(1 gpm). 

The results for the standard deviations calculated with equal weighting and biased weighting of 

the sensitivity case results were seen to generally be similar. For only three of the dependent 

variables (HL wall inside surface heat transfer coefficient, pressurizer surge line steam 

temperature and pressurizer surge line wall inside surface heat transfer coefficient) were the 

differences in the standard deviations obtained with equal-weighting and biased-weighting 

greater than 10%. The greatest difference was only 22%. Since the weighted approach 

provides results which take advantage of various additional assessment, modeling and plant 

operation experiences, the use of the standard deviations calculated using the weighted 

approach was selected. 

Finally, the total number of cases is only 20, so the approach which applies a 1.025 multiplier to 

consider effects related to the uncertainties in the dependent variable mean values was 

selected. 

The recommended results for the standard deviations in the eight dependent variables are 

shown in the right-hand column of Table D.8. 

D.4 Summary of Uncertainty Estimates 

Standard deviations were developed for the uncertainties in eight important output parameters 

(the dependent variables, which are SG tube failure margins, temperatures and heat transfer 

coefficients) for SCDAP/RELAP5 simulations of SBO severe accident events in a Westinghouse 

four-loop PWR. The standard deviations were obtained using a sensitivity-study method 

employing 19 sensitivity runs in addition to the base-case run. 
D-59

Table D.8 Standard Deviations for the Dependent Variables Calculated Using Four 

Methods 

Parameter and Units 

Standard 

Deviations 

Approach 1 

Equal Weighting

Base Case = 

Mean 

Standard 

Deviations 

Approach 2 

Equal 

Weighting 

Uncertainty in 

the Mean 

Effects 

Included 

Standard 

Deviations 

Approach 3 

Biased 

Weighting 

Base Case = 

Mean 

Recommended

Standard 

Deviations 

Approach 4 

Biased 

Weighting 

Uncertainty in 

the Mean 

Effects 

Included 

1.0-Multiplier Hottest 

Tube Failure Margin 

[Hottest Tube Failure 

Time – First Primary 

Piping Failure Time] (s) 

51.60 52.87 53.57 54.89 

Average Tube Failure 

Margin [Stress Multiplier 

for Tube Failure 

Coincident with First 

Primary Failure] 

0.227 0.233 0.228 0.234 

Average SG Tube Wall 

Temperature (K) 19.98 20.47 20.43 20.93 

Hottest SG Tube Wall 

Temperature (K) 32.36 33.16 33.67 34.50 

Hot Leg Steam 

Temperature (K) 58.16 59.60 60.00 61.48 

Hot Leg Wall Inside 

Surface Heat Transfer 

Coefficient (W/m2

-K) 

35.37 36.24 29.06 29.78 

Pressurizer Surge Line 

Steam Temperature (K) 52.45 53.75 58.50 59.94 

Pressurizer Surge Line 

Wall Inside Surface 

Heat Transfer 

Coefficient (W/m2

-K) 

75.61 77.48 64.56 66.15 
D-60

Standard deviations were calculated through four different approaches, using equal-weighting 

and biased-weighting of the independent-variable contributions to uncertainty, and with and 

without consideration of the uncertainties in the means. Since a weighted approach provides 

results which take advantage of various additional assessment, modeling and plant operation 

experiences, the use of the standard deviations calculated using the weighted approach were 

selected. Since the total number of cases is only 20, the calculation approach which applies a 

1.025 multiplier in order to include the consideration that there is an uncertainty in the mean 

values for the dependent variables was also selected. 

The base-case values, the evaluation times and the recommended standard deviations for the 

eight dependent variables are listed in Table D.9. 

Table D.9 Base Case Values and Recommended Standard Deviations for the 

Dependent Variables 

Parameter and Units 

Evaluation 

Time for Base 

Case Value(s) 

Base 

Case 

Value 

Recommended 

Standard 

Deviation 

Hottest SG Tube Failure Margin [1.0 

Stress Multiplier Hottest Tube Failure 

Time – First Primary Piping Failure 

Time], s 

Not Applicable -155 54.89 

Average SG Tube Failure Margin 

[Stress Multiplier for Tube Failure 

Coincident with First Primary Piping 

Failure], dimensionless 

Not Applicable 2.10 0.234 

Average SG Tube Wall Temperature, K 13,630 1021.7 20.93 

Hottest SG Tube Wall Temperature, K 13,630 1239.6 34.50 

Hot Leg Steam Temperature, K 13,517 1776.0 61.48 

Hot Leg Wall Inside-Surface Heat 

Transfer Coefficient, W/m2

-K 13,517 423.1 29.78 

Pressurizer Surge Line Steam 

Temperature, K 13,517 1373.0 59.94 

Pressurizer Surge Line Wall InsideSurface Heat Transfer Coefficient, 

W/m2

-K 

13,517 490.9 66.15 
D-61

D.5 References for Appendix D 

D.1 C. D. Fletcher, R. M. Beaton and W. C. Arcieri, SCDAP/RELAP5 Sensitivity Evaluations 

for a Zion TMLB’ Station Blackout Event, Information Systems Laboratories, Inc., 

ISL-NSAD-TR-04-05, March 2004. 

D.2 N. Zuber and J. Findlay, “Average Volumetric Concentrations in Two-Phase Flow 

Systems, Journal of Heat Transfer, Vol. 87, 1965, pp. 453-568. 

D.3 I. Kataoka and M. Ishii, “Drift Flux Model for Large Diameter Pipe and New Correlations 

for Pool Void Fraction,” International Journal of Heat and Mass Transfer, Vol. 30, 1987, 

pp. 1927-1939. 

D.4 C. D. Fletcher, D. A. Prelewicz and W. C. Arcieri, “RELAP5/MOD3.2.2Gamma 

Assessment for Pressurized Thermal Shock Applications,” NUREG/CR-6857, 

Information Systems Laboratories, Inc., October 2004. 

D.5 L. Erickson, et al., “The Marviken Full-Scale Critical Flow Tests Interim Report: Results 

from Test 22,” MXC222, March 1979. 

D.6 Erickson, et al., “The Marviken Full-Scale Critical Flow Tests Interim Report: Results 

from Test 24,” MXC224, May 1979. 

D.7 D. L. Gills and J. M. Carpenter, “Experimental Data Report for LOFT Nuclear Small 

Break Experiment L3-7,” Idaho National Engineering Laboratory, EG&G Idaho, Inc., 

NUREG/CR-1570, August 1980. 

D.8 P. D. Bayless and J. M. Devine, “Experiment Data Report for LOFT Large Break Loss of 

Coolant Experiment L2-5,” Idaho National Engineering Laboratory, NUREG/CR-2826, 

EGG-2210, August 1982. 

D.9 P. D. Bayless, J. B. Marlow and R. H. Averill, “Experiment Data Report for LOFT Nuclear 

Small Break Experiment L3-1,” Idaho National Engineering Laboratory, NUREG/CR1145, EGG-2007, January, 1980. 

D.10 ISP-26, OECD/NEA/CSNI International Standard Problem No. 26, ROSA-IV LSTF ColdLeg Small-Break LOCA Experiment, Comparison Report, OECD Nuclear Energy 

Agency, NEA/CSNI/R(91)13, February 1992. 

D.11 T. F. Habib, et al., “Multiloop Integral System Test (MIST): MIST Facility Functional 

Specification,” NUREG/ CR-5670, April, 1991. 

D.12 J. A. Klingenfus and M. V. Parece, “Multiloop Integral Systems Test, Final Report,” 

NUREG/CR-5395, December 1989. 

D.13 W. A. Stewart, et al., Natural Circulation Experiments for PWR High Pressure Accidents, 

EPRI Project No. RP2177-5, Westinghouse Electric Corp., December 1992. 

D.14 F. W. Dittus and L. M. K. Boelter, “Heat Transfer in Automobile Radiators of the Tubular 

Type,” Publications in Engineering, Vol. 2, University of California, Berkeley, 1930, 

pp. 443-461. 
D-62

D.15 American National Standard For Decay Heat Power in Light Water Reactors,” 

ANSI-5.1-1979, American Nuclear Society, 1979. 

D.16 L. J. Siefken et al., SCDAP/RELAP5/MOD3.3 Code Manual, NUREG/CR-6150, 

INEL-96/0422, Revision 2, Idaho National Engineering and Environmental Laboratory, 

January 2001. 

D.17 Kraftwerk Union AG, “Upper Plenum Test Facility, Test No. 1, Fluid-Fluid Mixing Test,” 

R515/87/09, April 1987. 

D.18 EPRI Report NP-2694, Research Project No. 1730-1, “Control of Containment Air 

Temperature: An Industry Survey and Insulation Test,” Final Report, October 1982. 

D.19 C. Ruger, J. Higgins and G. Martinez-Guridi, “Evaluation of RCP Seal Models Used for 

the Zion SBO Core Damage Scenario,” Brookhaven National Laboratory (Draft), 

April 14, 2004. 

D.20 I. A. Macdonald, J. A. Clarke and P. A. Stracham, “Assessing Uncertainty in Building 

Simulation,” Proceedings of Building Simulation ‘99, Kyoto, Japan, 

September 13-15, 1999, Vol. 2, pp. 683-690. 

D.21 L. Riley, “Random or Statistical Uncertainties, Estimating Uncertainties,” 

http://webpages.ursinus.edu/lriley/ref/unc/unc.html, Ursinus College, Collegeville, 

Pennsylvania, January 10, 2006. 
D-63 

APPENDIX E – EFFECT OF MODELING REACTOR VESSEL OUTLET 

NOZZLE CARBON STEEL SAFE END 

The SCDAP/RELAP5 analyses described in this report are based on a model that employs solid 

stainless steel HL structures. The stainless steel HLs are welded to the carbon-steel RV at the 

safe ends of the RV outlet nozzles. The nozzle safe ends are carbon steel structures with 

stainless-steel cladding. As described in Section 2.10, EPRI indicated that in their analysis the 

weakest point in the HL for creep rupture failure was found to be the carbon steel safe end 

rather than the HL itself. 

SCDAP/RELAP5 lacks the multi-dimensional heat structure and creep rupture modeling 

capabilities to fully analyze creep rupture behavior within the complex RV nozzle configuration. 

However, for the purpose of estimating the effects on the SG tube failure margins that would 

result from considering a carbon steel nozzle safe end material, a SCDAP/RELAP5 sensitivity 

calculation was performed with the HLs modeled as being fabricated entirely from carbon steel. 

The SCDAP/RELAP5 Westinghouse four-loop plant SBO base case calculation described in 

Section 4 was repeated with the materials specified for the upper and lower HL structures in the 

four coolant loops revised from stainless steel to carbon steel. The HL creep rupture modeling 

was also changed from stainless steel to carbon steel, but the HL wall emissivity was not 

changed since the inside surfaces of the carbon steel HLs are clad with stainless-steel. 

A change in HL material is expected to affect the distribution and absorption of heat and the 

timing of the heat-up of the system components in many different ways. The calculation results 

indicate that the HLs fail 135 s to 140 s earlier in the sensitivity run than in the base case run. In 

the sensitivity run, the average-tube predicted failure margin (the stress multiplier indicating 

strength degradation) for tube failure to occur coincident with HL failure is 3.34, as compared 

with 2.74 in the base case run. In the sensitivity run, the hottest-tube predicted failure margin is 

2.26, as compared with 1.68 in the base case run, and the non-degraded (1.0 stress multiplier) 

hottest tube is predicted to fail 450 s after the HL, compared with 360 s in the base case run. 

In summary, the sensitivity evaluation indicates that the SCDAP/RELAP5-calculated SG tube 

failure margins, based on solid stainless steel HLs, are expected to be conservative compared 

with the outcome that is likely to be obtained using more detailed HL creep rupture failure 

analyses of the RV outlet nozzle configuration.

BIBLIOGRAPHIC DATA SHEET

(See instructions on the reverse)

NRC FORM 335

(9-2004)

NRCMD 3.7

U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER

 (Assigned by NRC, Add Vol., Supp., Rev.,

 and Addendum Numbers, if any.)

NUREG-CR-6995

3. DATE REPORT PUBLISHED

MONTH

April

YEAR

2010

4. FIN OR GRANT NUMBER

2. TITLE AND SUBTITLE

SCDAP/RELAP5 Thermal-Hydraulic Evaluations of the Potential for Containment Bypass During

Extended Station Blackout Severe Accident Sequences in a Westinghouse Four-Loop PWR

5. AUTHOR(S)

C. D. Fletcher

R. M. Beaton

V. V. Palazov

D. L. Caraher

R. W. Shumway (Consultant)

6. TYPE OF REPORT

Technical

7. PERIOD COVERED (Inclusive Dates)

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (If NRC, provide Division, Office or Region, U.S. Nuclear Regulatory Commission, and mailing address; if contractor,

Division of System Analysis Information System Laboratories

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (If NRC, type "Same as above"; if contractor, provide NRC Division, Office or Region, U.S. Nuclear Regulatory Commission, 

Same as above

provide name and mailing address.)

and mailing address.)

10. SUPPLEMENTARY NOTES

11. ABSTRACT (200 words or less)

The U.S. Nuclear Regulatory Commission has been conducting studies to evaluate the risk associated with steam generator

tube failure during low probability severe accidents in pressurized-water reactors (PWRs) employing U-tube-type steam

generators as part of the agency's Steam Generator Action Plan (ML 011300073). The evaluations focus on station blackout

events that include a series of unlikely events and conditions that result in a "high-dry-low" plant condition. 

This report summarizes thermal-hydraulic evaluations performed using the SCDAP/RELAP5 systems analysis code and a model

representing a Westinghouse four-loop PWR. An assessment is made of the SCDAP/RELAP5 capabilities for predicting the

phenomena and behavior important for this application. The plant model has benefitted from (1) extensive iterative comparisons

with evaluations of natural circulation flows and turbulent mixing using a computational fluid dynamics code and (2) from

comparison with experimental data for pertinent fluid-mixing behavior. This report documents the recent history of

SCDAP/RELAP5 model improvements for this application, numerous sensitivity evaluations, estimates of the uncertainties in the

calculated results, analyses of extended station blackout accident event sequences in a Westinghouse four-loop PWR, and a

categorization of those event sequences based on containment bypass outcome.

12. KEY WORDS/DESCRIPTORS (List words or phrases that will assist researchers in locating the report.)

steam generator tube failure

containment bypass

induced rupture

severe accident

station blackout

14. SECURITY CLASSIFICATION

13. AVAILABILITY STATEMENT

unlimited

(This Page)

unclassified

(This Report)

unclassified

15. NUMBER OF PAGES

16. PRICE

NRC FORM 335 (9-2004) PRINTED ON RECYCLED PAPER

Office of Nuclear Regulatory Research 10070 Barnes Canyon Rd

U.S. Nuclear Regulatory Commission San Diego, CA 92121

Washington, DC 20555-0001