Consequential SGTR Analysis 

for Westinghouse and 

Combustion Engineering 

Plants with Thermally Treated 

Alloy 600 and 690 Steam 

Generator Tubes

 

Draft Report for Comment

Office of Nuclear Regulatory Research

NUREG-2195

Consequential SGTR Analysis 

for Westinghouse and 

Combustion Engineering 

Plants with Thermally Treated 

Alloy 600 and 690 Steam 

Generator Tubes

Draft Report for Comment

Manuscript Completed: February 2016

Date Published: May 2016

Prepared by: S. Sancaktar1, M. Salay1, R. Iyengar1 

A. Azarm2, S. Majumdar3 

1 Office of Nuclear Regulatory Research

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

2 Innovative Engineering and Safety Solutions, LLC

702 Russell Avenue, Suite 410

Gaithersburg, MD 20877

3 Argonne National Laboratory

9700 S. Cass Avenue 

Argonne, IL 60439

Office of Nuclear Regulatory Research

NUREG-2195

 
COMMENTS ON DRAFT REPORT

Any interested party may submit comments on this report for consideration by the NRC staff. 

Comments may be accompanied by additional relevant information or supporting data. Please 

specify the report number NUREG-2195 in your comments, and send them by the end of the 

comment period specified in the Federal Register notice announcing the availability of this 

report. 

Addresses: You may submit comments by any one of the following methods. Please include 

Docket ID NRC-2016-0097 in the subject line of your comments. Comments submitted in 

writing or in electronic form will be posted on the NRC website and on the Federal rulemaking 

website http://www.regulations.gov. 

Federal Rulemaking Website: Go to http://www.regulations.gov and search for documents 

filed under Docket ID NRC-2016-0097. Address questions about NRC dockets to Carol 

Gallagher at 301-415-3463 or by e-mail at Carol.Gallagher@nrc.gov.

Mail comments to: Cindy Bladey, Chief, Rules, Announcements, and Directives Branch

(RADB), Division of Administrative Services, Office of Administration, Mail Stop: 

OWFN-12-H08, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.

For any questions about the material in this report, please contact: Selim Sancaktar, Senior 

Reliability and Risk Engineer, Probabilistic Risk Assessment Branch, 301-415-2391 or by e-mail

at selim.sancaktar@nrc.gov.

Please be aware that any comments that you submit to the NRC will be considered a public 

record and entered into the Agencywide Documents Access and Management System 

(ADAMS). Do not provide information you would not want to be publicly available.
iii

ABSTRACT

This report summarizes severe accident-induced consequential steam generator tube rupture 

(C-SGTR) analyses recently performed by the U.S. Nuclear Regulatory Commission’s (NRC’s) 

Office of Nuclear Regulatory Research. C-SGTRs are potentially risk-significant events 

because thermally induced steam generator tube failures caused by hot gases from a damaged 

reactor core can result in a containment bypass event and a large release of fission products to 

the environment. The main accident scenarios of interest are those that lead to core damage 

with high reactor pressure, dry steam generator, and low steam generator pressure 

(high-dry-low) conditions. A typical example of such an accident scenario is a station blackout 

with loss of auxiliary feedwater. The analyses described in this report include risk assessment, 

thermal-hydraulic analyses, and materials behavior analyses. This work builds on, and updates,

previous work documented in NUREG-1570, “Risk Assessment of Severe Accident-Induced 

Steam Generator Tube Rupture,” and analyses conducted under the NRC’s Steam Generator 

Action Plan (Agencywide Documents Access and Management System (ADAMS) Accession 

No. ML100340994). 

The current analyses evaluate replacement steam generators with thermally treated Alloy 600 

and Alloy 690 heat exchange tubes and use the latest tube flaw data available in the 2010 time 

frame. A main focus of this work was to compare C-SGTR results for the different steam 

generator (SG) geometries associated with Westinghouse and Combustion Engineering (CE) 

plant designs. It has been previously understood that the geometry of the steam generator 

reactor coolant inlet plenum region and the hot-leg (HL) influences the temperature of the gases

reaching the steam generator tubes during closed-loop-seal natural circulation conditions. 

Hotter gases reaching the steam generator tube reduce the time before tube failure which 

increases the likelihood of containment bypass. However, if a thermally induced failure 

sufficient to depressurize the reactor coolant system (RCS) develops in another location, fission 

product release through failed SG tubes may be prevented or minimized. Therefore, the 

possibility of an earlier failure of other RCS components (such as the reactor coolant HL) is also 

considered. Pressure-induced steam generator tube rupture scenarios, which also may lead to 

tube failure and subsequent containment bypass were also studied, but are deemed to be of 

lesser potential impact on overall plant risk.

The methods developed were intended to address the contribution of thermally induced SGTR 

during severe accidents and pressure induced SGTR during a number of design-basis 

accidents (DBAs). The methods and the pilot applications were developed in a manner that can 

establish the framework to perform a more comprehensive PRA that can address the C-SGTR 

at a level of detail suitable for other NRC needs. Extension of these methods can support the 

risk-informed decision process and can also be used to update the PRA Standards and PRA 

Procedure Guide.

Several key assumptions were made to support this study:

• The steam generators were assumed to have flaw distributions consistent with operating 

experience obtained in the 2010 time frame. The flaw distributions were based on a 

statistical analysis of a sample of SG tube inspection results obtained for replacement 

steam generators with an average operating history of 15 years in service.
iv

• A steam generator “rupture” was defined as a total steam generator tube leak area 

equivalent to a guillotine break of one or more tubes.

• A small secondary leak (equivalent to a flow area of 3.22 square centimeters (cm2

) 

[0.5 square inch (in.2

)]) is assumed for all accident scenarios involving high primary 

coolant side and dry steam generator conditions. This leakage area results in SG 

depressurization for all dry steam generators conditions studied.

• A simplified model for HL failure was used for the probabilistic risk analysis portion of the 

study. However, detailed structural analyses were conducted and determined that the 

simplified model consistently predicted later times to HL failure than more detailed 

modeling. This detailed modeling also indicated that the upper portion of the HL will fail 

earlier than other RCS regions.

• Mixing coefficients in the SG inlet plenum used in the MELCOR thermal-hydraulic 

analysis were determined based on detailed computational fluid dynamics analysis.

The results of the PRA indicate that the conditional C-SGTR probability for a station blackout 

(SBO) event is lower for Westinghouse-type SGs, as compared to CE-type SGs.

The conditional probability of C-SGTR (equivalent to 6 cm2 [0.93 in.2

] total rupture area) for the 

selected Westinghouse-type SGs is summarized as follows, for the SBO sequence with early 

failure of turbine-driven auxiliary feedwater pump (TDAFW):

Tube Material C-SGTR Probability

1 Tube Failure a 2 Tubes Failure More Than 2 Tubes Failure

Inconel 600 1.3E-02 8.2E-05 Negligible

Inconel 690 8.9E-03 3.9E-05 Negligible

a Total leakage from the RCS equivalent to double-ended rupture of a single tube for the Westinghouse plant.

The conditional probability of C-SGTR with a rupture area also equivalent to 6 cm2 (0.93 in.2

) for 

the selected CE plant is 0.22 for SBO scenarios where the TDAFW pump(s) has failed initially 

and 0.31 when TDAFW pump(s) operates for at least 4 hours. For these analyses, primary or 

secondary relief valves are assumed to reclose after opening and no failure to stick open is 

considered.

The increase in conditional C-SGTR probability for case where the TDAFW is initially available 

is because of the thermal-hydraulic parameters of the accident sequence; it is observed that in 

such a sequence, the temperature difference between the HL and SG tubes is smaller in the 

temperature ranges of creep rupture challenge (600-800 degrees Celsius (C)

[1,112–1,472 degrees Fahrenheit (F)]) compared to the sequence where the TDAFW fails early. 

However, the initial operation of the TDAFW pump, if it fails after 4 hours, can significantly delay 

the onset of core damage.

The main conclusion from this work is that the steam generator geometry and the fluid flow 

rates in different steam generator designs can significantly influence the potential likelihood of 

C-SGTRs. For the cases studied, steam generator designs with a shallow inlet plenum 

(resulting in the tubesheet located closer to the HL inlet) and a shorter HL can result in a greater 

likelihood of a C-SGTR following a core damage event associated with high-dry-low conditions. 
v

A shallow inlet plenum design reduces the mixing of the hot gases entering the steam 

generator, thereby creating a higher thermal load on the tubes. Therefore, for the specific 

replacement SG geometries analyzed in this study, the Combustion Engineering plant design 

had an increased likelihood of a C-SGTR, and therefore a higher potential for a large early 

release, than the Westinghouse plant design. It should be noted that previous conclusions on 

the effect of “loop seal clearing” are not changed; for any of the steam generator geometries, if 

loop seal clearing occurs in an accident sequence (such as one caused by a large reactor 

coolant pump seal leak), thermally induced SG tube failures are expected to occur.

vii

CONTENTS

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

CONTENTS..............................................................................................................................vii

LIST OF FIGURES ..................................................................................................................xiii

LIST OF TABLES....................................................................................................................xxi

EXECUTIVE SUMMARY ........................................................................................................xxv

ACKNOWLEDGMENTS........................................................................................................xxix

ABBREVIATIONS .................................................................................................................xxxi

1. INTRODUCTION ............................................................................................................... 1-1

1.1 Background................................................................................................................. 1-1

1.2 Objectives ................................................................................................................... 1-2

1.3 Scope.......................................................................................................................... 1-3

1.4 Summary of Differences from Previously Published Work........................................... 1-3

1.5 Summary of Research Approach and Organization of Report ..................................... 1-4

1.6 References.................................................................................................................. 1-6

2. SEQUENCE DEFINITIONS ............................................................................................... 2-1

2.1 Pressure-Induced C-SGTR Sequences of Interest ...................................................... 2-1

2.1.1 Core Damage Bridge Event Tree....................................................................... 2-2

2.1.2 Level 2 Event Tree: LERF Determination.......................................................... 2-5

2.2 Thermally Induced C-SGTR Sequences...................................................................... 2-7

2.3 Representative Sequences for a Westinghouse Plant................................................. 2-9

2.4 Representative Sequences for a Combustion Engineering Plant............................... 2-11

2.4.1 Description of the Selected TH Sequences...................................................... 2-11

2.5 Definition of “Critical Size” for C-SGTR...................................................................... 2-12

2.5.1 Critical Leakage Areas Resulting from SG Tube Failures ................................ 2-12

2.6 A LERF Model........................................................................................................... 2-16

2.7 References................................................................................................................ 2-20

3. THERMAL HYDRAULIC ANALYSES FOR WESTINGHOUSE AND COMBUSTION 

ENGINEERING PLANTS................................................................................................... 3-1

3.1 Introduction ................................................................................................................. 3-1

3.1.1 Summary of Results Obtained in NUREG/CR-6995........................................... 3-3

3.1.2 CE Plant Considerations.................................................................................... 3-7

3.2 Initial Deck and Analyses for the CE Plant .................................................................. 3-8

3.3 Computational Fluid Dynamics.................................................................................... 3-8

3.3.1 Summary of NUREG-1922 Results for Westinghouse Plants............................. 3-9

3.3.2 CFD Results for a CE Plant ............................................................................. 3-11

3.3.3 Conclusions from the CFD Analyses................................................................ 3-12

3.4 Deck Modifications and Modeling Assumptions for the CE Analysis.......................... 3-13

3.5 Loop Seal Clearing.................................................................................................... 3-16

3.6 Analysis results ......................................................................................................... 3-19

3.6.1 Discussion of MELCOR Analyses.................................................................... 3-19

3.6.2 Summary of Accident Sequences Studied and Nomenclature ......................... 3-21

3.6.3 Select CE Sequence Results........................................................................... 3-24

3.6.4 Data Output Fields Provided for Use by External Failure Calculator and 

FE Analyses .................................................................................................... 3-43

3.6.5 MELCOR Cases To Support the C-SGTR Calculator ...................................... 3-45
viii

3.7 Potential Future Analyses ......................................................................................... 3-47

3.8 Conclusions .............................................................................................................. 3-49

3.8.1 Analysis-Based Conclusions............................................................................ 3-49

3.8.2 Deck-generation-based Conclusions ............................................................... 3-51

3.9 References................................................................................................................ 3-52

4. BEHAVIOR OF RCS COMPONENTS OTHER THAN SG TUBES .................................... 4-1

4.1 Introduction ................................................................................................................. 4-1

4.2 Analyses of RCS Components for a Typical Westinghouse Plant................................ 4-1

4.2.1 HL and Surge Line............................................................................................. 4-2

4.2.2 Steam Generator Primary Manway.................................................................... 4-2

4.2.3 Resistance Temperature Detector ..................................................................... 4-3

4.2.4 Socket Weld Connection of Instrument Line to the RTD Flange......................... 4-3

4.2.5 Power-Operated Relief Valve............................................................................. 4-3

4.3 Thermal Mechanical Analyses of Selected RCS Components..................................... 4-5

4.3.1 SG Primary Manway.......................................................................................... 4-5

4.3.2 Resistance Temperature Detector Welds......................................................... 4-12

4.3.3 Socket Weld that Connects Instrument Line to RTD Flange ............................ 4-18

4.3.4 PORV Plug-to-Seat Impact Analysis ................................................................ 4-21

4.4 Thermal Mechanical Analyses of the HL and Surge Line .......................................... 4-28

4.4.1 FEM for Thermal Analysis and Boundary Conditions ....................................... 4-28

4.4.2 FEM for Structural Analysis and Boundary Conditions..................................... 4-30

4.4.3 Mechanical and Surface Heat Flux Loading..................................................... 4-33

4.4.4 Results of Thermal Mechanical Analysis of HL and Surge Line ....................... 4-34

4.4.5 Evaluation of Structural Damage ..................................................................... 4-37

4.4.6 HL Model ......................................................................................................... 4-39

4.5 Conclusions .............................................................................................................. 4-42

4.5.1 SG Primary Manway........................................................................................ 4-42

4.5.2 RTD Welds ...................................................................................................... 4-43

4.5.3 Instrument Line................................................................................................ 4-43

4.5.4 PORV Plug-to-Cage Impact............................................................................. 4-43

4.5.5 HL and Surge Line........................................................................................... 4-44

4.6 References................................................................................................................ 4-45

5. TECHNICAL BASIS FOR PREDICTING BEHAVIOR OF FLAWED SG TUBES IN 

SEVERE ACCIDENTS....................................................................................................... 5-1

5.1 Introduction ................................................................................................................. 5-1

5.2 Ligament Rupture Pressure......................................................................................... 5-2

5.2.1 Analytical Failure Models ................................................................................... 5-2

5.2.2 Validation Tests for Ligament Rupture ............................................................. 5-10

5.3 Crack Opening Rate at High Temperature ................................................................ 5-20

5.3.1 Creep Rate Equation for Alloy 600................................................................... 5-21

5.3.2 Crack Opening Area for Axial Cracks............................................................... 5-22

5.3.3 Tests on Specimens with Circumferential Notches at High Temperature ......... 5-22

5.3.4 Predicted Axial Crack Opening Rate at High Temperature .............................. 5-26

5.4 Stability of Flaws after Ligament Rupture .................................................................. 5-27

5.4.1 Failure Modes of Specimens Tested at High Temperature .............................. 5-28

5.4.2 Lower Bound Flow Stress for Computing Unstable Burst at High 

Temperature.................................................................................................... 5-31

5.5 References................................................................................................................ 5-33

6. ESTIMATION OF SG TUBE FLAW DISTRIBUTIONS....................................................... 6-1

6.1 Introduction ................................................................................................................. 6-1
ix

6.2 Data Selection............................................................................................................. 6-3

6.3 Estimation of SG Tube Flaw Distributions in Replacement SGs .................................. 6-5

6.3.1 Summary ........................................................................................................... 6-5

6.3.2 An Example Calculation..................................................................................... 6-7

6.3.3 Example Flaw Samples ..................................................................................... 6-8

6.4 OTSG Axial Loads on Tubes during Severe Accidents.............................................. 6-10

6.5 References................................................................................................................ 6-11

7. A PRA PERSPECTIVE OF SEQUENCES STUDIED ........................................................ 7-1

7.1 PRA Perspective of C-SGTR for a Westinghouse Plant .............................................. 7-1

7.1.1 Description of the Selected TH Sequences........................................................ 7-1

7.1.2 Estimating the Entry Frequency from Level 1 PRA for Level 2 PRA................... 7-8

7.1.3 Conditional Probability of C-SGTR at Each Flaw Bin ......................................... 7-9

7.1.4 Estimating C-SGTR Probability........................................................................ 7-15

7.1.5 Estimating Containment Bypass Frequency..................................................... 7-23

7.1.6 Level 2 Analysis of C-SGTR for ZNPP............................................................. 7-29

7.1.7 Quantification of Level 2 Models ...................................................................... 7-32

7.1.8 Concluding Remarks ....................................................................................... 7-34

7.2 PRA Perspective of C-SGTR for a Combustion Engineering Plant............................ 7-35

7.2.1 Description of the Selected TH Sequences...................................................... 7-36

7.2.2 Estimating the Entry Frequency from Level 1 PRA for Level 2 PRA Analysis... 7-50

7.2.3 Flaw Bins to Calculate C-SGTR Probability ..................................................... 7-52

7.2.4 SGTR Probability Estimation Using Integrated Flaw Samples.......................... 7-54

7.2.5 Level 2 Models for Containment Bypass Evaluation ........................................ 7-60

7.2.6 Quantification of Probability of Containment Bypass due to C-SGTR............... 7-64

7.2.7 Concluding Remarks ....................................................................................... 7-65

7.3 Sensitivity Analyses for C-SGTR in Different SG Types ............................................ 7-66

7.3.1 Summary of Sensitivity Analyses for Westinghouse Plant................................ 7-67

7.3.2 Summary of Sensitivity Analyses for Combustion Engineering Plant ............... 7-68

7.4 Case Studies for Pressure-Induced C-SGTR Scenarios............................................ 7-70

7.4.1 C-SGTR during Anticipated Transients without Scram (ATWS) ....................... 7-70

7.4.2 C-SGTR during Steam Line Break Scenarios .................................................. 7-72

7.4.3 C-SGTR during High Pressure Feed-and-Bleed Operation.............................. 7-74

7.4.4 LERF and Core Damage Contribution of Pressure Induced C-SGTR .............. 7-75

7.5 References................................................................................................................ 7-77

8. PRA CONCLUSIONS AND RECOMMENDATIONS ......................................................... 8-1

8.1 Insights and Observations........................................................................................... 8-1

8.2 Limitation of Supporting Analyses for PRA Models...................................................... 8-4

8.2.1 Variations in Tube Temperatures by Average Hot Tube and the Hottest Tube... 8-5

8.2.2 TH Evaluation of Accident Sequences ............................................................... 8-5

8.2.3 Severe Accident Analysis .................................................................................. 8-5

8.2.4 Creep Rupture and Fracture Mechanic Models.................................................. 8-5

8.2.5 Leak Area Models for Failed Tubes ................................................................... 8-5

8.2.6 Creep Rupture Models and Data for HL and Surge Line.................................... 8-6

8.2.7 Surveillance Data from SG Periodic Inspection.................................................. 8-6

8.2.8 Material Properties at High Temperature ........................................................... 8-6

9. OVERALL SUMMARY ...................................................................................................... 9-1

APPENDIX A HIGH TEMPERATURE DEFORMATION AND DAMAGE OF RCS 

MATERIALS......................................................................................................................A-1

A.1 Material Properties Used in Section 4 .........................................................................A-1

A.2 High Temperature Creep Rupture Test Data...............................................................A-3
x

APPENDIX B C-SGTR CALCULATOR..................................................................................B-1

B.1 Example Case.............................................................................................................B-1

B.2 Uncertainty Parameters...............................................................................................B-3

B.3 References..................................................................................................................B-3

APPENDIX C CONSIDERATIONS FOR PRESSURE-INDUCED C-SGTR ............................C-1

C.1 Introduction .................................................................................................................C-1

C.2 Events of Interest ........................................................................................................C-2

C.2.1 ATWS Event ......................................................................................................C-3

C.2.2 Large Secondary-Side Break Event...................................................................C-8

C.3 Example for Estimating CDF from Type-II C-SGTR Challenges ................................C-10

C.4 Conclusions ..............................................................................................................C-12

APPENDIX D UNCERTAINTY AND SENSITIVITY ANALYSIS..............................................D-1

D.1 Sensitivity Analyses for the Selected W Plant .............................................................D-1

D.1.1 Base Case Evaluation and the Uncertainties Calculated....................................D-1

D.1.2 Sensitivity on Temperature Difference between HL and Hot Tube ...................D-11

D.1.3 Sensitivity to HL Thickness (potential effect of an overlay)...............................D-12

D.1.4 Secondary Side Not Depressurized .................................................................D-13

D.1.5 Late Failure of Turbine Driven AFW Pump.......................................................D-15

D.1.6 Effect of TT690 Material...................................................................................D-24

D.1.7 Conclusions .....................................................................................................D-26

D.2 Sensitivity Analyses for the Selected CE Plant..........................................................D-27

D.2.1 Stuck Open Failure of Secondary Relief Valves before SG Dryout ..................D-27

D.2.2 Critical C-SGTR Leak Area..............................................................................D-38

APPENDIX E WESTINGHOUSE SBO SCENARIO AND SENSITIVITY CASES....................E-1

E.1 Westinghouse SBO Scenario and Sensitivity Cases ...................................................E-1

E.2 Case-1: WNEWBASE with 1 Large Flaw and TT600..................................................E-5

E.3 Case-2: WNEWBASE with 42 Flaws and TT600........................................................E-7

E.4 Case-3: WNEWBASE with 21 Flaws and TT690......................................................E-10

APPENDIX F PRESSURE-INDUCED C-SGTR—SUPPORTING CALCULATIONS............... F-1

F.1 Estimation of C-SGTR for a Flaw Bin ..........................................................................F-1

F.2 Estimation of Pressure Induced C-SGTR Probability................................................... F-7

F.3 Estimation of Pressure Induced SGTR-Leak Probability.............................................. F-7

APPENDIX G ESTIMATING THE ENTRY FREQUENCY FROM LEVEL 1 PRA FOR 

LEVEL 2 PRA ANALYSIS.................................................................................................G-1

G.1 Zion Nuclear Power Plant (ZNPP)...............................................................................G-1

G.1.1 Internal Event ....................................................................................................G-1

G.1.2 Seismic Initiating Event......................................................................................G-2

G.1.3 Fire Initiating Event ............................................................................................G-3

G.2 Calvert Cliffs Nuclear Power Plant (CCNP) .................................................................G-4

G.2.2 Seismic Initiating Event......................................................................................G-6

G.2.3 Fire Initiating Event ............................................................................................G-7

G.2.4 Contributions from Other Initiating Events..........................................................G-8

APPENDIX H A SCREENING APPROACH BASED ON FLAW DEPTH AND LENGTH........H-1

APPENDIX I MELTING TEMPERATURES AND STEEL OXIDATION CONSIDERATIONS 

IN MELCOR MODELING.................................................................................................... I-1
xi

APPENDIX J LOOP SEAL CLEARING CONSIDERATIONS................................................. J-1

J.1 TH Analysis Related Considerations ............................................................................J-1

J.2 PRA Analysis Related Considerations..........................................................................J-3

APPENDIX K FURTHER DISCUSSION OF SG TUBE FLAW DISTRIBUTIONS...................K-1

K.1 On Development of Distributions in Section 6.0...........................................................K-1

K.2 On the Adjusted (shifted) Flaw Distributions Used in PRA...........................................K-6

APPENDIX L A PROCESS TO COMPREHENSIVELY ESTIMATE C-SGTR CDF IN A 

PRA MODEL .....................................................................................................................L-1

L.1 Introduction ................................................................................................................. L-1

L.2 The Process................................................................................................................ L-1

L.3 Summary of the Results of the Application.................................................................. L-5

xiii

LIST OF FIGURES

Figure 1-1 Work and report layout .................................................................................. 1-5

Figure 2-1 Generic core damage bridge event tree for DBA-induced C-SGTR ............... 2-4

Figure 2-2 Unmitigated ltsbo emergency response timeline.......................................... 2-18

Figure 2-3 Unmitigated stsbo emergency response timeline......................................... 2-19

Figure 3-1 Severe accident natural circulation flows....................................................... 3-2

Figure 3-2 Conceptual model of loop seal clearing ....................................................... 3-17

Figure 3-3 Pertinent flows for loop seal clearing ........................................................... 3-18

Figure 3-4 Organization of CSGTR decks .................................................................... 3-23

Figure 3-5 Main pressures for the stsbo calculation...................................................... 3-26

Figure 3-6 SG secondary collapsed liquid level for the stsbo calculation ...................... 3-26

Figure 3-7 Main structure temperatures for the stsbo calculation.................................. 3-27

Figure 3-8 Creep rupture indices for the stsbo calculation ............................................ 3-27

Figure 3-9 HotAve tube creep rupture indices for the stsbo calculation ........................ 3-28

Figure 3-10 Hydrogen concentrations in SGA tubes for the stsbo calculation................. 3-28

Figure 3-11 Volatile fission product release fractions for the stsbo calculation................ 3-29

Figure 3-12 Main pressures for the ltsbo calculation....................................................... 3-29

Figure 3-13 SG secondary collapsed liquid level for the ltsbo calculation ....................... 3-30

Figure 3-14 Main structure temperatures for the ltsbo calculation................................... 3-30

Figure 3-15 Comparison of ltsbo pressures to those of stsbo ......................................... 3-31

Figure 3-16 Comparison of ltsbo SG boiler collapsed liquid levels to those of stsbo....... 3-31

Figure 3-17 Comparison of ltsbo loop A structure temperatures to those of stsbo .......... 3-32

Figure 3-18 Comparison of ltsbo loop B structure temperatures to those of stsbo .......... 3-32

Figure 3-19 Main pressures for the ltsbo-as calculation.................................................. 3-33

Figure 3-20 SG secondary collapsed liquid level for the ltsbo-as calculation .................. 3-34

Figure 3-21 Main structure temperatures for the ltsbo-as calculation.............................. 3-34

Figure 3-22 Creep rupture indices for the ltsbo-as calculation ........................................ 3-35

Figure 3-23 HotAve tube creep rupture indices for the ltsbo-as calculation..................... 3-35

Figure 3-24 Hydrogen concentrations in SGA tubes for the ltsbo-as calculation............. 3-36

Figure 3-25 Volatile fission product release fractions for the ltsbo-as calculation............ 3-36

Figure 3-26 Main pressures for the stsbo-a calculation................................................... 3-37

Figure 3-27 Volatile fission product release fractions for the stsbo-a calculation............. 3-37

Figure 3-28 Main pressures for the ltsbo-a calculation.................................................... 3-38

Figure 3-29 Volatile fission product release fractions for the ltsbo-a calculation.............. 3-38

Figure 3-30 Main pressures for the stsbo-as calculation................................................. 3-39

Figure 3-31 Volatile fission product release fractions for the stsbo-as calculation........... 3-39

Figure 3-32 Main pressures for the stsbo-ao calculation................................................. 3-40

Figure 3-33 Volatile fission product release fractions for the stsbo-ao calculation........... 3-40

Figure 4-1 Parts for the Zion hot-leg primary manway .................................................... 4-5

Figure 4-2 Finite-element model of manway assembly ................................................... 4-6

Figure 4-3 Time-temperature histories of inlet plenum.................................................... 4-7

Figure 4-4 Elastic-creep analysis of manway bolts ......................................................... 4-8

Figure 4-5(a) Distribution of principal creep strain around circumference of bolt 1 at 

650 °C ........................................................................................................... 4-9

Figure 4-5(b) Variation of principal creep strains in bolt 1 with time and temperature.......... 4-9

Figure 4-6(a) Distribution of contact pressure between outer periphery of insert and 

lower head flange as function of temperature and position .......................... 4-10

Figure 4-6(b) Variation of opening area with time and temperature................................... 4-10
xiv

Figure 4-7 Variation of opening area with (a) time and (b) temperature for 

two temperature histories ............................................................................ 4-10

Figure 4-8 Effect of steam leakage on opening area..................................................... 4-11

Figure 4-9 Predicted vs. observed creep curves of SA 193-B7 for duplicate tests at 

20 and 30 ksi at (a) 550 °C and (b) 450 °C .................................................. 4-12

Figure 4-10 RTD scoop and welds connecting it to HL ................................................... 4-13

Figure 4-11 Meshes used to analyze RTD scoop, welds, and HL................................... 4-13

Figure 4-12 Steam temperature histories for the hot side and the cold side of the 

RTD............................................................................................................. 4-14

Figure 4-13 Close up view of temperature (in °F) in hot-leg RTD scoop at 14,400 s....... 4-15

Figure 4-14 Variation of average temperature in ID and OD welds with time .................. 4-15

Figure 4-15 Von Mises effective stress (in psi) distribution at ID weld RTD interface 

at 14,148 s .................................................................................................. 4-16

Figure 4-16 Von Mises effective stress (in psi) distribution at OD weld RTD interface 

at 14,148 s .................................................................................................. 4-17

Figure 4-17 Time evolution of (a) average von Mises effective stress and (b) average 

effective creep strain at interfaces of ID and OD welds with RTD ................ 4-17

Figure 4-18 Simplified axisymmetric model for connection of instrument-line-to-RTDflange weld .................................................................................................. 4-19

Figure 4-19 Temperature loading applied as uniform temperature to model of 

connection of instrument-line-to-RTD flange weld ....................................... 4-19

Figure 4-20 Time evolution of (a) average von Mises effective stress and (b) 

average effective creep strain at interfaces of weld with instrument line 

and RTD...................................................................................................... 4-20

Figure 4-21 Effective creep strain distribution in instrument line at time t—14,230 s....... 4-20

Figure 4-22 Time evolution of average effective creep strain in instrument line away 

from welds................................................................................................... 4-21

Figure 4-23 Various parts included in the plug-to-cage impact analysis.......................... 4-24

Figure 4-24 Stress-plastic strain curves at 288 and 538 °C (550 and 1,000 °F) used 

in analysis ................................................................................................... 4-25

Figure 4-25 Variation of spring force with time during single impact ............................... 4-26

Figure 4-26 Variation of equivalent plastic strain with (a) von Mises effective stress 

and (b) time for most highly strained element in plug at 288 and 538 °C 

(550 and 1,000 °F)....................................................................................... 4-26

Figure 4-27 (a) Simplified axisymmetric model of plug-to-cage impact, where satellite 

overlay on plug is 2 mm thick and (b) stress-plastic-strain curves used in 

impact analysis of plug with 2-mm-thick Stellite overlay............................... 4-27

Figure 4-28 Distribution of von Mises effective stress (in psi) near contact zone of 

cage and plug with 2-mm Stellite overlay..................................................... 4-28

Figure 4-29 Components of first version of FEM for thermal conduction analysis ........... 4-29

Figure 4-30 FEM for thermal analysis............................................................................. 4-29

Figure 4-31 Components of second version of FEM for structural analysis with 

supports, flailing restraints, and hangers ..................................................... 4-31

Figure 4-32 Control volumes for thermal hydraulic analysis of the HL and surge line 

by RELAP5.................................................................................................. 4-34

Figure 4-33 Temperature dependent stress strain curves for 316 stainless steel............ 4-35

Figure 4-34 Temperature contours at inner surface at 9,222 s indicate the steady 

state condition of 623 K in the entire region of consideration....................... 4-36

Figure 4-35 Temperature contours at inner surface at 13,555 s indicate the higher 

temperature in the upper half of the HL region ............................................ 4-36
xv

Figure 4-36 Contours of accumulated creep strain at inner surface at 12,300 s 

indicate the significant creep strains in the upper half of the HL region........ 4-36

Figure 4-37 Contours of plastic strain at inner surface at 12,300 s indicate the 

concentration of plastic strains in the upper half of the HL region ................ 4-37

Figure 4-38 Contours of through-thickness damage at 12,300 s shown in the section 

of HL experiencing higher strains ................................................................ 4-38

Figure 4-39 Contours of creep damage at 12,300 s shown in the (a) outer surface 

and (b) inner surface of HL experiencing higher strains............................... 4-39

Figure 4-40 Contours of accumulated creep strain at inner surface at 12,430 s 

indicate the significant creep strains in the upper half of the HL region........ 4-39

Figure 4-41 Contours of accumulated plastic strain at inner surface at 12,430 s 

indicate the significant creep strains in the upper half of the HL region........ 4-40

Figure 4-42 Contours of through-thickness damage at 12,430 s shown in the section 

of HL experiencing higher strains ................................................................ 4-40

Figure 4-43 Contours of through-thickness damage assuming (a) creep only 

behavior at 12,140 s and (b) plasticity only behavior at 13,025 s................. 4-41

Figure 4-44 Contours of through-thickness damage assuming no spatial adjustment 

of heat transfer coefficient obtained from RELAP ........................................ 4-41

Figure 4-45 Contours of through-thickness damage for the HL pipe with weld overlay 

at 12.500 s .................................................................................................. 4-42

Figure 5-1 Predicted vs. observed (a) ligament rupture pressures and (b) unstable 

burst pressures of Alloy 600 tubes with axial notches at room 

temperature................................................................................................... 5-4

Figure 5-2 Flow stress curves for various product forms of Alloy 600 ............................. 5-5

Figure 5-3 Larson-Miller plot for Alloy 600 tubes............................................................. 5-6

Figure 5-4 Stress distributions through section at failure of tubes with (a) two 

symmetrically located part-through circumferential cracks and (b) single 

part-through circumferential crack ................................................................. 5-8

Figure 5-5 Variations of experimental failure bending moments with crack angle and 

those predicted by (a) Kurihara model and (b) ANL model .......................... 5-10

Figure 5-6 Predicted vs. observed time to failure of flawed and unflawed tubes 

under constant temperature and pressure condition.................................... 5-12

Figure 5-7 Predicted vs. observed failure pressures for isothermal (700–840 °C) 

pressure ramp tests on unflawed and flawed tubes 0.25–1 in. long and 

65–80 % deep by (a) creep rupture model and (b) flow stress model .......... 5-13

Figure 5-8 Effective flow stress curves (dashed lines) computed from the pressure 

ramp tests (symbols) vs. temperature of test ............................................... 5-14

Figure 5-9 Comparison of observed failure temperatures with those predicted by (a) 

creep rupture model and (b) flow stress model for temperature ramp 

tests ............................................................................................................ 5-15

Figure 5-10 Comparison of predicted failure temperatures by the creep rupture and 

flow stress models for flawed specimens as a function of temperature 

ramp rate..................................................................................................... 5-15

Figure 5-11 Calculated and ANL simulation of (a) INEL ramp and (b) EPRI ramp for 

high-temperature tests................................................................................. 5-17

Figure 5-12 Observed vs. predicted failure temperatures by (a) creep rupture model 

and (b) flow stress model for tests simulating severe accident transients .... 5-17

Figure 5-13 Variation of failure temperatures with crack angle for specimens with 

two symmetrical cracks of various depths.................................................... 5-18
xvi

Figure 5-14 Experimental failure temperatures and failure temperatures predicted by 

the Kurihara and ANL models for two symmetrical part-through 

circumferential cracks of various semiangular length θ................................ 5-19

Figure 5-15 Failure temperatures for specimens with one (n = 1) and two (n = 2) 

circumferential cracks.................................................................................. 5-20

Figure 5-16 INEL creep rate on Alloy 600 vs. stress data plotted using activation 

energy of 65 kcal/mole and stress normalized by Young’s modulus at 

temperature................................................................................................. 5-21

Figure 5-17(a) Variation of h2 (c/b,n) with c/b for various values of n .................................. 5-22

Figure 5-17(b) Variation of h2 (0,n) with n ........................................................................... 5-22

Figure 5-18(a) Tube with two symmetrical through-wall circumferential notches................. 5-23

Figure 5-18(b) Axial loading on a tube with two symmetrical 45 ° notches plotted after 

making an axial cut and unfolding the tube circumference into a plane ....... 5-23

Figure 5-19 Variation of h2 with c/b for creep rate exponents n = 3.7 and 6.1 ................ 5-24

Figure 5-20 Experimentally measured and predicted variation of total notch opening 

with time for specimens with 2 × 45° circumferential notches loaded at 

(a) 1,106.8 kgf (2,440 lb) and (b) 1,224.7 kgf (2,700 lb)............................... 5-24

Figure 5-21 Experimentally measured and predicted variation of total notch opening 

with time for specimens with 2 symmetrical circumferential notches 

loaded at 1,108 kg (2,400 lb) for notch lengths (a) 6.35 mm (0.25 in.) 

and (b) 5.1 mm (0.20 in.)............................................................................. 5-25

Figure 5-22 Time vs. temperature plot for tests CR 106 and CR 108.............................. 5-26

Figure 5-23 Comparison of predicted (solid line) and experimentally measured 

(symbols) notch opening displacements for (a) Test CR 106 and (b) Test 

CR 108........................................................................................................ 5-26

Figure 5-24 Variations of (a) crack opening displacement rate with through-wall axial 

crack length for a tube subjected to internal pressure of 2,350 psi at 

700 °C and (b) crack opening area with crack length at final 

temperatures 700 and 750 °C for a tube subjected to severe accident 

transient ...................................................................................................... 5-27

Figure 5-25(a) Crack opening rate in mm/min versus crack length at 732 °C and 871 °C.... 5-28

Figure 5-25(b) Time to open initially closed through-wall cracks to a crack opening 

angle (COA) of 45° for a 22.3-mm (7

/8-in.) diameter SG tube at 732 °C 

(1,350 °F) and 871 °C (1,600 °F) under a constant internal pressure of 

16 MPa (2,350 psi)...................................................................................... 5-28

Figure 5-26 Measured (a) crack opening displacements (CODs) and (b) crack 

opening angles (COAs) in failed high temperature test specimens as a 

function of initial axial flaw depth and initial flaw length................................ 5-29

Figure 5-27(a) Initial flaw depth (a/h) versus axial crack length plot for specimens tested 

at high temperature ..................................................................................... 5-30

Figure 5-27(b) Flaw depth (a/h) versus pressure plot for constant-pressure tests on 

specimens with 1 in. part-through axial crack conducted isothermally or 

under a temperature ramp........................................................................... 5-30

Figure 5-28 Variation of failure pressure with failure temperature for tests conducted 

on specimens with a 25-mm (1-in.)-long crack ............................................ 5-31

Figure 5-29 Temperature variation of flow stress (using k=0.5) of Alloy 600 

specimens derived from tensile test data as reported in the literature.......... 5-32

Figure 5-30 Pressure at failure as a function of temperature at failure for all 

specimens with a (a) 6-mm (0.25-in.)-long axial crack and (b) 51-mm (2-

in.) long axial crack...................................................................................... 5-32
xvii

Figure 5-31 Critical crack length as a function of temperature for a 22.3-mm (7

/8-in.) 

diameter Alloy 600 tube at an internal pressure of 16 MPa (2,350 psi)........ 5-33

Figure 6-1 Table 2 reproduced from NUREG/CR-6521 .................................................. 6-2

Figure 6-2 Average number of flaws as a function of EFPY for 4 SGs............................ 6-8

Figure 6-3 TT600 flaws for 10 SGs—distribution by length............................................. 6-9

Figure 6-4 TT600 flaws for 10 SGs—distribution by depth............................................ 6-10

Figure 7-1(a) TH results for Wnewbase .............................................................................. 7-4

Figure 7-1(b) Difference between the HL temperature and the temperatures of the 

hottest tube and the average hot tube and cold tube for Wnewbase.............. 7-5

Figure 7-2 TH results for Case F2 .................................................................................. 7-6

Figure 7-3 TH results for Case F3 .................................................................................. 7-7

Figure 7-4 Shifted distribution for flaw depth (600 TT) .................................................... 7-8

Figure 7-5 Shifted distribution for flaw length (690 TT) ................................................. 7-10

Figure 7-6 RCS survival probability as a function of accident time for Wnewbase ........ 7-11

Figure 7-7 Percentiles of the SG leak area distribution as a function of accident time .. 7-18

Figure 7-8 Survival functions for RCS and SG tube failures with critical leak rate......... 7-19

Figure 7-9 Percentiles of the SG leak area distribution as a function of accident time .. 7-20

Figure 7-10 Survival probability functions for RCS and flawed tubes .............................. 7-20

Figure 7-11 Definition of bounding SBO sequences with high/dry/low (H/D/L) 

conditions.................................................................................................... 7-25

Figure 7-12 An estimate of bounding SBO sequences frequencies leading to CSGTR and containment bypass................................................................... 7-27

Figure 7-13 Another estimate of bounding SBO sequences frequencies leading to CSGTR and containment bypass................................................................... 7-28

Figure 7-14 Loop A temperature profiles of the HL and SG tubes for the SBO with an 

early failure of TDAFW pumps..................................................................... 7-40

Figure 7-15 Loop B temperature profiles of the HL and SG tubes for the SBO with an 

early failure of TDAFW pumps..................................................................... 7-41

Figure 7-16 Difference in loop A temperature of the HL and SG tubes for the SBO 

with an early failure of TDAFW pumps ........................................................ 7-42

Figure 7-17(a) Difference in loop B temperature of the HL and SG tubes for the SBO 

with an early failure of TDAFW pumps ........................................................ 7-43

Figure 7-17(b) Primary and secondary pressure for the SBO with an early failure of 

TDAFW pumps............................................................................................ 7-44

Figure 7-18 Loop A temperature profiles of the HL and SG tubes for the SBO with a 

delayed failure of TDAFW pumps................................................................ 7-45

Figure 7-19 Loop B temperature profiles of the HL and SG tubes for the SBO with a 

delayed failure of TDAFW pumps................................................................ 7-46

Figure 7-20 Difference in loop A temperature of the HL and SG tubes for the SBO 

with a delayed failure of TDAFW pumps...................................................... 7-47

Figure 7-21(a) Difference in loop B temperature of the HL and SG tubes for the SBO 

with a delayed failure of TDAFW pumps...................................................... 7-48

Figure 7-21(b) Primary and secondary pressure for the SBO with a delayed failure of 

TDAFW pumps............................................................................................ 7-49

Figure 7-22 The RCS survival probability and percentiles of SGTR leak areas for 

stsbo-a-average hot tubes........................................................................... 7-55

Figure 7-23 The RCS survival probability and percentiles of SGTR leak areas for 

stsbo-a-hottest tubes................................................................................... 7-56

Figure 7-24 The RCS survival probability and the probability of SGTR with a leak 

area less than 3 cm2 for stsbo-a-b, aggregated over average hot and 

hottest tubes................................................................................................ 7-57
xviii

Figure 7-25 The RCS survival probability and the probability of SGTR with a leak 

area less than 3 cm2 for stsbo-a-a, aggregated over average hot and 

hottest tubes................................................................................................ 7-57

Figure 7-26 The RCS survival probability and the probability of SGTR with a leak 

area less than 3 and 6 cm2 for stsbo-a-b-scf................................................ 7-58

Figure 7-27 The RCS survival probability and the probability of SGTR with a leak 

area less than 6 cm2 for the whole plant for an SBO scenario with failure 

of TDAFW at time zero and no stuck open secondary relief valves 

(stsbo-a-scf) ................................................................................................ 7-59

Figure 7-28 The RCS survival probability and the probability of SGTR with a leak 

area less than 3 and 6 cm2 for ltsbo-a-b-scf................................................. 7-60

Figure 7-29 The sensitivity results for (stsbo-a) for C-SGTR leak area of 12 cm2 and 

6 cm2 ........................................................................................................... 7-70

Figure A-1 Creep curves for SA 193 B7 material at (a) 450, (b) 550, (c) 650 °C..............A-4

Figure A-2 Comparison of fitted and test variation of creep strain vs. time for creep 

tests conducted on SA 193 B7 at 450 °C at (a) 20, (b) 30, and (c) 40 ksi.......A-6

Figure A-3 Comparison of fitted and test variation of creep strain vs. time for creep 

tests conducted on SA 193 B7 at 550 °C at (a) 10, (b) 20, and (c) 30 ksi.......A-7

Figure A-4 Comparison of fitted and test variation of creep strain vs. time for creep 

tests conducted on SA 193 B7 at 650 °C at (a) 7.5, (b) 10, and (c) 20 ksi......A-8

Figure A-5 Creep strain vs. time curves of SA-240 Grade 316 stainless steel at 

700 °C (a) 26 ksi (179 MPa) and (b) 28 ksi (193 MPa) and 30 ksi (207 

MPa) .............................................................................................................A-9

Figure A-6 Creep strain vs. time curves of SA-240 Grade 316 stainless steel at 

800 °C (a) 13 ksi (90 MPa) and (b) 15 ksi (103 MPa)...................................A-10

Figure A-7 Creep strain vs. time curves of SA-240 Grade 316 stainless steel at (a) 

1,000 °C, 4 ksi (28 MPa) and (b) 1,100 °C, 2 ksi (14 MPa) ..........................A-11

Figure A-8 Predicted vs. test minimum creep rate of SA 240 Grade 316 stainless 

steel ............................................................................................................A-11

Figure A-9 Larson-Miller parameter plot for time to stress rupture of SA 240 Grade 

316 stainless steel at 538–1,100 °C.............................................................A-12

Figure A-10 Predicted vs. test time to stress rupture of SA 240 Grade 316 stainless 

steel at 538–1,100 °C ..................................................................................A-13

Figure A-11 Steady state creep ductility vs. stress of SA 240 Grade 316 stainless 

steel at (a) 538 and (b) 566 °C.....................................................................A-13

Figure A-12 Steady state creep ductility vs. stress of SA 240 Grade 316 stainless 

steel at (a) 593 and (b) 649 °C.....................................................................A-14

Figure A-13 Steady state creep ductility vs. stress of SA 240 Grade 316 stainless 

steel at (a) 700 and (b) 760 °C.....................................................................A-14

Figure A-14 Steady state creep ductility vs. stress of SA 240 Grade 316 stainless 

steel at 800 °C.............................................................................................A-15

Figure A-15 Estimate mean, upper and lower bounds to the steady state creep 

ductility of SA 240 Grade 316 stainless steel...............................................A-15

Figure A-16 Creep strain vs. time curves of SA-351 Grade CF8M cast stainless steel 

at 700 °C (a) 15–16 ksi (103–110 MPa) and (b) 17 ksi (117 MPa)...............A-16

Figure A-17 Creep strain vs. time curves of SA-351 Grade CF8M cast stainless steel 

at 800 °C (a) 12 and 14 ksi (83–97 MPa) and (b) 10 ksi (69 MPa)...............A-17

Figure A-18 Creep strain vs. time curves of SA-351 Grade CF8M cast stainless steel 

at 1,000 °C (a) 3 ksi (21 MPa) and (b) 2 ksi (14 MPa)..................................A-17
xix

Figure A-19 Confidence bounds for the prediction of (a) creep rate and (b) LarsonMiller parameter for time to rupture of SA-351 Grade CF8M cast 

stainless steel based on ANL and Japanese data .......................................A-19

Figure A-20 Predicted vs. observed time to stress rupture of SA-351 Grade CF8M 

cast stainless steel ......................................................................................A-19

Figure A-21 Variation of (a) steady state ductility of U.S. and Japanese CF8M heats 

and (b) total elongation of U.S. CF8M heat with stress................................A-20

Figure A-22 Creep curves for SA-516 Grade 70 carbon steel at (a) 500, (b) 650, and 

(c) 800 °C ....................................................................................................A-22

Figure A-23(a) Predicted vs. observed creep rates .............................................................A-23

Figure A-23(b) Larson-Miller plot for time to stress rupture of SA-516 Grade 70 and SA216 Grade WCC..........................................................................................A-23

Figure A-24(a) Predicted vs. observed time to stress rupture..............................................A-24

Figure A-24(b) Variation of steady state ductility with stress and temperature of 

carbon steels...............................................................................................A-24

Figure C-1 ATWS event tree top events to address Type-II C-SGTR..............................C-5

Figure C-2 ATWS event tree top events to address Type-II C-SGTR—example 

quantification .................................................................................................C-7

Figure C-3 L-SSB event tree top events to address Type-II C-SGTR..............................C-8

Figure C-4 L-SSB event tree top events to address Type-II C-SGTR SGTR—

example quantification.................................................................................C-10

Figure D-1 Temperature and pressure profile of the base case (at the flaw location)......D-2

Figure D-2 Leak area of the base case (4 cm wear flaw with 40% depth) .......................D-3

Figure D-3 Probabilities of HL and surge line failure .......................................................D-7

Figure D-4 Temperature and pressure profile of the case where secondary side is 

not depressurized........................................................................................D-14

Figure D-5 SBO with TDAFW operating for 0 hours with MSSVs stuck open; Calvert 

Cliffs............................................................................................................D-28

Figure D-6 SBO with TDAFW operating for 0 hours; Calvert Cliffs loop A .....................D-29

Figure D-7 Temperature differences in SBO with TDAFW operating for 0 hours; 

Calvert Cliffs loop A.....................................................................................D-29

Figure D-8 SBO with TDAFW operating for 0 hours; Calvert Cliffs loop B .....................D-30

Figure D-9 Temperature differences in SBO with TDAFW operating for 0 hours; 

Calvert Cliffs loop B.....................................................................................D-31

Figure D-10 SBO with TDAFW operating for 4 hours; Calvert Cliffs loop A .....................D-31

Figure D-11 Temperature differences in SBO with TDAFW operating for 4 hours; 

Calvert Cliffs loop A.....................................................................................D-32

Figure D-12 SBO with TDAFW operating for 4 hours; Calvert Cliffs loop B .....................D-33

Figure D-13 Temperature differences in SBO with TDAFW operating for 4 hours; 

Calvert Cliffs loop B.....................................................................................D-34

Figure D-14 Probabilities of SGTR leak rates less than 3 and 6 cm2 vs. HL survival 

probability for stsbo-as-a-scf........................................................................D-35

Figure D-15 Probabilities of SGTR leak rates less than 3 and 6 cm2 vs. HL survival 

probability for stsbo-as-b-scf........................................................................D-35

Figure D-16 Probability of SGTR less than 6 cm2 and probability of RCS survival...........D-36

Figure D-17 Probability of SGTR leak rate less than 3 cm2 for loop B with and without 

open secondary relief valves after SG dryout ..............................................D-37

Figure D-18 Probability of SGTR leak rate less than 6 cm2 with and without open 

secondary relief valves after SG dryout .......................................................D-38

Figure D-19 Probability of SGTR with leak rates smaller than a specific value and 

probability of RCS survival as a function of accident time............................D-40
xx

Figure D-20 Probability of SGTR as a function of critical leak area .................................D-41

Figure E-1 WNEWBASE scenario parameters................................................................E-2

Figure E-2 Delta T (in degrees C) between HL and hot tube—WNEWBASE ..................E-3

Figure E-3 Histogram for flaw distribution (by size) for TT600.........................................E-4

Figure E-4 Histogram for flaw distribution (by size) for TT690.........................................E-5

Figure F-1 Assumed TH behavior for ATWS for CSGTR analysis................................... F-2

Figure F-2 Assumed TH behavior for SLB for CSGTR analysis ...................................... F-3

Figure I-1 The parabolic rate constant for steam-H2O reaction...................................I-3

Figure I-2 Steel mass loss at a fixed temperature ...................................................I-4

Figure I-3 Loss of steel thickness .........................................................................I-4

Figure K-1 Graphical presentation of aggregate flaw data ..............................................K-2

Figure K-2 Graphical presentation of aggregate flaw data ..............................................K-3

Figure K-3 Flaw depth distribution...................................................................................K-5

Figure K-4 Flaw depth distribution (shifted gamma)........................................................K-7

Figure L-1 Insertion of C-SGTR event tree node in SSB event trees............................L-4

Figure L-2 Insertion of C-SGTR event tree node in ATWS event tree .........................L-5
xxi

LIST OF TABLES

Table 2-1 Selected DBA Accident Sequences Causing Challenges To SG Tubes........ 2-2

Table 2-2 Selected Sequences to Evaluate C-SGTR for Severe Accident 

Sequences .................................................................................................... 2-8

Table 3-1 Timing of Selected Events........................................................................... 3-25

Table 3-2 Failure Times and Release Fractions to Environment.................................. 3-43

Table 3-3 MELCOR Cases to Support C-SGTR Calculator ......................................... 3-46

Table 4-1 Spring Rates of Steam Generator Supports ................................................ 4-32

Table 4-2 Surge Line Supports in FEM for Structural Analysis .................................... 4-33

Table 4-3 Weights and Pressure Loading and Mass Densities Used in 

Thermal-Mechanical Analysis of the HL and Surge Line.............................. 4-33

Table 4-4 Summary of Predicted HL Failure Times for the Various Analyses.............. 4-45

Table 6-1 SG Properties for Flaw Distribution Estimates for C-SGTR Studies............... 6-5

Table 6-2 SG Tube Flaw Distributions Taken from Reference 4.................................... 6-6

Table 7-1 Contributions of Various Events to Long Term SBO Scenarios ..................... 7-8

Table 7-2 Related Information from Zion Nuclear Stations for This Study...................... 7-9

Table 7-3 Probability that a Detected Flaw Belongs to a Bin Size at 15 EFPY............. 7-12

Table 7-4 Expected Number of Flaws That Belong to a Flaw Bin Defined by Depth 

and Length Range for Zion SGs with Tubes Made of Inconel 600 ............... 7-12

Table 7-5 Expected Number of Flaws That Belong to a Flaw Bin Defined by Depth 

and Length Range for Zion SGs with Tubes Made of Inconel 690 ............... 7-13

Table 7-6 Probability that a Flaw That Belongs to a Bin Defined by Depth and 

Length Range Fails before the HL Failure for Inconel 600 Tubes for 

“Wnewbase” TH File for Westinghouse Representative Plant...................... 7-14

Table 7-7 Probability that a Flaw That Belongs to a Bin Defined by Depth and 

Length Range Fails before the HL Failure for Inconel 690 Tubes for 

“Wnewbase” TH File for Westinghouse Representative Plant...................... 7-14

Table 7-8 Probability of Single- and Multi-Tube Failure in C-SGTR for 

Inconel 600/690 (Westinghouse)................................................................. 7-16

Table 7-9 Summary of 3 Types of C-SGTR Failure Probability Estimates 

Discussed in Sections 7.1.4.2, 7.1.4.3, and 7.1.4.4 ..................................... 7-22

Table 7-10 Timing of Major Events during an SBO with Early Failures of TDAFWs 

(Wnewbase with Inconel 600 TT SG) .......................................................... 7-30

Table 7-11 Timing of Major Events during an SBO with Failures of TDAFWs after 

Battery Depletion (SCDAP/RELAP case 153 with Inconel 600 TT SG)........ 7-31

Table 7-12 Conditional LERF Probabilities for an SBO with Early and Late Failures 

of TDAFW for Representative W Plant ........................................................ 7-34

Table 7-13 Related Information from the Reference CE Plant....................................... 7-51

Table 7-14 Contributions of Various Events to the Long Term SBO Scenarios for 

Single and Dual Unit Core Damage............................................................. 7-52

Table 7-15 Expected Number of Flaws per Each SG That Belong to a Flaw Bin 

Defined by Depth and Length Range........................................................... 7-53

Table 7-16 Expected Number of Flaws per Loop A and Loop B (one Unit; 2 SGs), 

That Belong to a Flaw Bin Defined by Depth and Length Range ................. 7-53

Table 7-17 Comparison of C-SGTR probability for SBO................................................ 7-60

Table 7-18 Timing of Major Events during an SBO with Early Failures of TDAFWs....... 7-61

Table 7-19 Timing of Major Events during an SBO with Failures of TDAFWs after 

Battery Depletion......................................................................................... 7-63
xxii

Table 7-20 Conditional LERF Probabilities for an SBO with Early and Late Failures 

of TDAFW for Representative CE Plant....................................................... 7-64

Table 7-21 Sensitivity Results for Early Stick Open Failures of the Secondary Relief 

Valves ......................................................................................................... 7-68

Table 7-22 Sensitivity Results for Opening the Secondary Relief Valves after 

SG Dryout ................................................................................................... 7-69

Table 7-23 Contributors to Electrical RPS Failures Which Do Not Impact Manual 

Scram.......................................................................................................... 7-72

Table 7-24 Changes in Core Damage Frequency and LERF as a Result of Pressure 

Induced C-SGTR for the Representative Westinghouse Plant..................... 7-76

Table 7-25 Changes in Core Damage Frequency and LERF as a Result of Pressure 

Induced C-SGTR for the Representative CE Plant ...................................... 7-76

Table 8-1 Summary of the Frequency Estimates for Containment-Bypass and 

LERF............................................................................................................. 8-3

Table 8-2 Summary Table for Conditional Probability of C-SGTR Studied as Base 

Cases............................................................................................................ 8-3

Table A-1 Range of Temperatures (°C) for Which High-Temperature Material 

Properties Data Are/Are Not Available...........................................................A-2

Table A-2 Materials and Temperature Ranges (°C) over Which Materials 

Properties Data Were Generated by ANL......................................................A-2

Table A-3 Summary of Creep Data for SA 193 B7 Bolt Material ....................................A-3

Table A-4 Best-Fit Values of the Parameters B, m, Q and n of SA 193 B7 As 

Determined from the Creep Tests .................................................................A-5

Table A-5 Summary of Creep Data for SA 240 Grade 316 Stainless Steel ....................A-9

Table A-6 Creep Rate Parameters for Available Data on Type 316 Stainless Steel.....A-10

Table A-7 Summary of Creep Data for SA 351 Grade CF8M Cast Stainless Steel ......A-16

Table A-8 Mean and ±95% Confidence Bounds of Creep Rate Parameters for 

Combined ANL and Japanese Data on SA-351 Grade CF8M Cast 

Stainless Steel at Various Temperatures (stress in ksi and creep rate 

in 1/h)..........................................................................................................A-18

Table A-9 Summary of Creep Data for SA 516 Grade 70 Carbon Steel.......................A-21

Table A-10 Creep Rate Parameters for Combined ANL and Literature Data on 

SA-216 Grade 70 and SA-216 Grade WCC Carbon Steels .........................A-23

Table A-11 Summary of Creep Data for SA 240 Grade 316 /SA 516 Grade 70 

Weldment....................................................................................................A-25

Table B-1 Example Input-Output (Condensed and Processed)......................................B-4

Table D-1 Output for the Total Leak Area in the Base Case...........................................D-4

Table D-2 Probabilities of HL and Surge Line ................................................................D-8

Table D-3 Calculation of Margin for the Base Case......................................................D-10

Table D-4 Margin with Smaller Temperature Difference between HL and Hot Tube ....D-12

Table D-5 Margin with Thicker HL................................................................................D-13

Table D-6 Margin with Secondary Side NOT Depressurized (at 1100 psi) ...................D-15

Table D-7 T&H Input Parameters for Case 153............................................................D-17

Table D-8 Margin for the Case with Failure of TDAFW Pump at 4 Hours .....................D-24

Table D-9 Comparison of TT690 Cases between W vs. CE Type SGs ........................D-26

Table D-10 Sensitivity Results for Early Stick Open Failures of the Secondary Relief 

Valves .........................................................................................................D-36

Table D-11 Sensitivity Results for Opening the Secondary Relief Valves after 

SG Dryout ...................................................................................................D-38

Table E-1 WNEWBASE Results for Case-1...................................................................E-6

Table E-2 Summary Output for the Final Scenario with 42 “Large” Flaws ......................E-8
xxiii

Table E-3 WNEWBASE Results for Case-2...................................................................E-9

Table E-4 WNEWBASE Results for Case-3 with TT690 ..............................................E-11

Table F-1 TH Input File for C-SGTR for Simulating ATWS Scenarios............................ F-1

Table F-2 TH Input File for C-SGTR for Simulating SLB Scenarios ............................... F-2

Table F-3 Example of Expected Flaw Set Plus One Large Flaw of 70% Depth and 

3 cm Length for a CE Plant............................................................................F-3

Table F-4 Results of Intermediate File from CSGTR for Flaw #126, at 70% Depth 

and 3 cm Length for a CE Plant and TH File Representing SLB.................... F-4

Table F-5 Results of Cumulative Leak Area File From CSGTR for Expected Flaws 

Plus One Flaw at 70% Depth and 3 cm Length for a CE Plant and TH 

File Representing SLB...................................................................................F-4

Table F-6 Case Results of Pressure Induced C-SGTR during ATWS............................ F-5

Table F-7 Case Results of Pressure Induced C-SGTR during SLB ............................... F-5

Table F-8 Bounding C-SGTR Probability per a Flaw Bin To Be Used for Both SLB 

and ATWS Scenarios for Westinghouse and CE Plants ................................ F-6

Table F-9 Bounding Probability for SGTR—Leak per a Flaw Bin To Be Used for 

Both SLB and ATWS Scenarios for Westinghouse and CE Plants ................ F-6

Table F-10 Probability that a Detected Flaw Belongs to a Bin Size at 15 EFPY............... F-6

Table F-11 C-SGTR Probability for SLB or ATWS Scenarios per Flaw............................ F-7

Table G-1 Information from Zion Nuclear Station ...........................................................G-2

Table G-2 Information from Calvert Cliffs Nuclear Station ..............................................G-5

Table G-3 Core Damage for SBO Scenarios with Early Failure of TDAFWS..................G-6

Table G-4 CDF for the SBO and the Failures of TDAFWs due to Overfill (for 

Internal Event Initiators Affecting One or Both Units).....................................G-6

Table G-5 CDF for an SBO and the Failures of All TDAFWs after the Battery 

Depletion (Internal Event Initiators Affecting One or Both Units)....................G-6

Table G-6 CDF for the SBO, and Failures of TDAFWs due to a Potential Overfill 

(Seismic Events Affecting One or Both Units)................................................G-7

Table G-7 CDF for SBO and Failures of TDAFWs after the Battery Depletion 

(Seismic Events Affecting One or Both Units)................................................G-7

Table G-8 CDF for SBO, and Failures of TDAFWs due to Potential Overfill (Control 

Room Fire Events Affecting One or Both Units).............................................G-8

Table G-9 CDF for SBO and Failures of TDAFWs after Battery Depletion (Control 

Room Fire Events Affecting One or Both Units).............................................G-8

Table H-1 Probability that a Large Wear Flaw in the Last Cycle Has the Specific 

Ranges of the Length and Depth...................................................................H-2

Table H-2 Probability of C-SGTR Occurring before HL Failure for Different Sizes of 

Flaws in Inconel 600 in Zion Wnewbase Case ..............................................H-3

Table H-3 Probability of C-SGTR Occurring before HL Failure for Different Sizes of 

Flaws in Inconel 690 in Zion Wnewbase Case ..............................................H-3

Table H-4 Probability of Single- and Multi-Tube Failure in C-SGTR for 

Inconel 600/690.............................................................................................H-4

Table L-1 Process Summary for Event Trees and CDF Sequences.......................... L-4

Table L-2 Summary of C-SGTR Modeling Applied to a Specific PRA Model for a 

 4-Loop Westinghouse Plant .............................................................. L-7

xxv

EXECUTIVE SUMMARY

Over the last 2 decades, the U.S. Nuclear Regulatory Commission (NRC) and the nuclear 

industry have investigated the safety implications and risk associated with consequential steam 

generator tube rupture (C-SGTR) events; i.e., events in which steam generator (SG) tubes leak 

or fail as a consequence of the high differential pressures or elevated temperatures during 

accident sequences. Accidents involving SG tube ruptures have shown in various probabilistic 

risk assessments (PRAs) to be contributors to plant risk because of their potential for causing a 

release of fission products outside containment (containment bypass sequences).

The analysis methods, tools, and expertise previously developed as a part of the NRC Steam 

Generator Action Plan (SGAP) were sufficient to resolve the associated technical issues in the 

SGAP. However, certain limitations restrict its usefulness in supporting future risk assessments.

Consequently, several areas were identified for additional research and updates. After closure 

of the SGAP in 2009, and building upon the research conducted for resolution of the SGAP, this 

study was chartered to address development of a simplified method for assessing the risk 

associated with consequential tube rupture/leakage in design-basis accident (DBA) and severe 

accident events. This report integrates work done by three disciplines in the NRC Office of 

Nuclear Regulatory Research (RES)—thermal-hydraulic and computational fluid dynamics 

analysis, materials, and probabilistic risk assessment. Updated SG flaw distributions 

representing the current population of SGs were used along with the new thermal-hydraulic (TH) 

results from the MELCOR thermal hydraulic code for a representative Combustion Engineering 

plant.

This report documents a method for a quantitative risk assessment of C-SGTR during a severe 

accident (i.e., after the onset of core damage), and during a DBA event (before the onset of core 

damage). The focus of this study is the estimation of the large early release frequency (LERF) 

because of C-SGTR and containment bypass. Specifically, the probability of containment 

bypass because of C-SGTR and an assessment of the fraction of containment bypass that 

constitutes LERF, were estimated. Simplified LERF calculation methods were developed and 

applied to two representative pressurized water reactor (PWR) plants: a Westinghouse (W) and 

a Combustion Engineering (CE) design. In addition, the generic stylized models were used to 

address C-SGTR related to DBA issues. The scope of this report does not include the 

development of Level 1 PRA modeling, though full Level 1 PRA for internal and external events 

were used to obtain the frequency of the sequences related to the C-SGTR. The method is 

illustrated with applications to plants containing replacement steam generators with thermally

treated Inconel Alloy 600 and 690 SG tubes.

A key consideration for C-SGTR sequences is the relative timing between failure of SG tubes 

and failure of other locations of the reactor coolant system (RCS). If a thermally induced failure 

sufficient to depressurize the primary coolant develops in another RCS location either before or 

shortly after SG tube failure, fission product release through failed SG tubes may be prevented 

or minimized. In that case, the RCS leakage will preferentially go into the containment, thus 

significantly reducing or altogether eliminating potential leakages from the RCS into the 

secondary side of the SG. To properly account for this relative timing, this analysis used the 

latest available thermal-hydraulics analyses for both representative W and CE plant types, 

updated flaw statistics pertinent to current reactors, and the latest available models and 

software for estimating the failure probability and failure timing of SG tubes and other RCS 

components (i.e., HL and surge line). A software “calculator” was developed in conjunction with 
xxvi

this study to simulate multiple flaws in SG tubes and to calculate C-SGTR tube leakage 

probabilities. Inputs for the calculator include thermal-hydraulic parameters of an accident 

sequence, SG tube flaw distribution, and material properties. This software allows making 

numerous “what-if” runs with a minimal effort to better understand progression of an accident, 

and pressure and temperature challenges to the tubes.

Several key assumptions were made to support this study:

• The steam generators were assumed to have flaw distributions consistent with operating 

experience obtained in the 2010 time frame. The flaw distributions were based on a 

statistical analysis of a sample of SG tube inspection results obtained for replacement 

steam generators with an average operating history of 15 years in service.

• Existing models for the high-temperature behavior of RCS components and SG tubes 

were used to estimate the potential for a C-SGTR event. The limitations associated with 

these models are discussed in Chapter 8.

• A steam generator “rupture” was defined as a total steam generator tube leak area 

equivalent to a guillotine break of one or more tubes.

• A small secondary leak (equivalent to a flow area of 0.5 square inch) is assumed for all 

accident sequences involving high pressure in primary coolant side and dry steam 

generator conditions. This leakage area results in SG depressurization for all dry steam 

generators conditions studied.

• A simplified model for HL failure was used for the probabilistic risk analysis portion of the 

study. However, detailed structural analyses were conducted and determined that the 

simplified model consistently predicted later times to HL failure than more detailed 

modeling without introducing excessive conservatism. This detailed modeling also 

indicated that the upper portion of the HL will fail earlier than other RCS regions.

• Mixing coefficients in the SG inlet plenum used in the MELCOR thermal-hydraulic 

analysis were determined based on detailed computational fluid dynamics analysis.

The main conclusion from this work is that the steam generator geometry and the fluid flow 

rates in different steam generator designs can significantly influence the potential likelihood of 

C-SGTRs. For the cases studied, steam generator designs with a shallow inlet plenum 

(resulting in the tubesheet located closer to the HL inlet) and a shorter HL can result in a greater 

likelihood of a C-SGTR after a core damage event associated with high-dry-low conditions. A 

shallow inlet plenum design reduces the mixing of the hot gases entering the steam generator, 

thereby creating a higher thermal load on the tubes. Therefore, for the specific replacement SG 

geometries analyzed in this study, the CE plant design had an increased likelihood of a CSGTR, and therefore a higher potential for a large early release, than the Westinghouse plant 

design.

Moreover, the study has concluded that clearing of the RCS cold leg loop seal, which changes 

the natural circulation flow path within the SG inlet plenum and subjects the SG tubes to hotter 

gas flow, could cause SG tube failure and be a contributor to C-SGTR for W plants. For CE 

plants, significant SG tube failures are expected even if the loop seal is not cleared.
xxvii

The PRA method developed and illustrated in this report, although applied to specific plants and 

cases, may offer general insights and a process to obtain quantitative measures (e.g., fraction

of C-SGTR given a severe accident) that could be used to support risk-informed regulatory 

decision-making. For example, this work may benefit significance determination process 

reviews of findings related to steam generators, inform NRC reviews for new reactors, or 

support license renewal reviews for issues related to steam generator material management.

xxix

ACKNOWLEDGMENTS

In addition to the authors listed on the cover page of this document, many others from the 

U.S. Nuclear Regulatory Commission (NRC) and outside of the NRC contributed to the 

analyses or documentation of the work. Former NRC employee Charles Harris contributed to 

Section 6 of this report, for the estimation of steam generator tube flaw distributions and related 

subjects discussed in the same section. Chris Boyd performed detailed computational fluid 

dynamics calculations to support determination of steam-generator inlet plenum mixing 

coefficients used in the work described in Section 3 of this report. Kevin Coyne’s multiple 

rigorous reviews of this report, his persistence to move the deliverables forward, and technical 

understanding of the overall report also need to be mentioned.

In addition, the authors would like to acknowledge the following individuals (listed alphabetically 

by last name.)

From the NRC:

Michelle Gonzalez

Ken Karwoski

Emmett Murphy

Antonios Zoulis

From Information Systems Laboratories and their contractors:

Robert Beaton (currently at the NRC)

Terry Gitnick

Maria Morell Gonzales

Qiming He

Andrew Mlynarczyk

Marcos Ortiz.

Many other NRC staff members from different NRC offices also contributed to this effort by 

reviews and supporting meetings.

xxxi

ABBREVIATIONS

ac alternating current

ACRS Advisory Committee on Reactor Safeguards

ADAMS Agencywide Documents Access and Management System

ADV atmospheric dump valve

AFW auxiliary feedwater

ANL Argonne National Laboratory

ARTIST Aerosol Trapping in Steam Generator

ATWS anticipated transient(s) without scram

CCDP conditional core damage probability

CCF common cause failure

CCW component cooling water

CD core damage

CDF core damage frequency

CE Combustion Engineering

CFD computational fluid dynamics

cm centimeter

COA crack opening angle

COD crack opening displacement

CSGTR (C-SGTR) consequential steam generator tube rupture

CST condensate storage tank

DBA design-basis accident

dc direct current

DEGB double-ended guillotine break

ECCS emergency core cooling system

EDG emergency diesel generator

EDM electrostatic discharge machine

EFPY effective full power year

EPRI Electric Power Research Institute

FB feed and bleed

FE, FEM finite element model

FEA front-end analysis

FP fission product

FWIV feed water isolation valve

gpm gallons per minute

HL hot-leg

HPI high-pressure injection

HPR high-pressure recirculation

HRA human reliability analysis
xxxii

ID inside diameter

IE initiating event

IPE individual plant evaluation

IPEEE individual plant evaluation for external events

ISI in-service inspection

L-SSB large secondary side break

LERF large early release frequency

LOCA loss-of-coolant accident

LOOP loss of offsite power

Lpm liters per minute

ltsbo long-term SBO (TDP fails after battery depletion)

MA mill annealed

MFW main feedwater

MSIV main stem isolation valve

MSLB main steam line break

MSSV main steam safety valve

NPP nuclear power plant

NRC U.S. Nuclear Regulatory Commission

NRR Office of Nuclear Reactor Regulation

OD outside diameter 

ODSCC outside diameter stress corrosion cracking

PORV power-operated relief valve

PRA probabilistic risk assessment

PTW part-through-wall

PWR pressurized-water reactor

PWSCC primary water stress corrosion cracking

PZR pressurizer

RCP reactor cooling pump

RCS reactor coolant system

RES Office of Nuclear Regulatory Research

RF release fraction

RHR residual heat removal

RPV reactor pressure vessel

RS recirculation spray

RTD resistance temperature detector

RWST reactor water storage tank

SAI single axial crack/indication

SAMG severe-accident management guideline

SBO station blackout

SCF suppress creep failure

SCI single circumferential crack

SG steam generator

SGAP Steam Generator Action Plan

SGT steam generator tube
xxxiii

SGTR-INIT steam generator tube rupture initiator

SHR secondary heat removal

SL surge line

SNL Sandia National Laboratories

SPAR standardized plant analysis risk

SRV safety relief valve

SSB secondary side break

Stsbo short-term SBO (AFW pump fails early in SBO)

TDAFW turbine-driven auxiliary feedwater (Pump)

TDP turbine-driven pump

TH (T&H) thermal-hydraulic

TT600 thermally treated Inconel 600

TT690 thermally treated Inconel 690

TYPE-I (C-SGTR) temperature-induced (by creep rupture) C-SGTR

TYPE-II (C-SGTR) pressure-induced C-SGTR

VDC Volts DC

W Westinghouse

ZNPP Zion Nuclear Power Plant

NUREG-2195 has been

reproduced from the best available copy.

1-1

1

2 1. INTRODUCTION

3

4

5 1.1 Background

6

7 The U.S. Nuclear Regulatory Commission (NRC) and the nuclear industry have expended 

8 considerable resources over the last 2 decades to better understand the safety implications and 

9 risk associated with consequential steam generator tube rupture (C-SGTR) events; i.e., events 

10 in which steam generator (SG) tubes leak or fail as a consequence of the high differential 

11 pressures or elevated temperatures during accident sequences. Accidents involving SG tube 

12 ruptures have shown in various probabilistic risk assessments (PRAs) to be contributors to plant 

13 risk, mainly because of their potential for causing a release outside containment (containment 

14 bypass sequences).

15

16 The analysis methods, tools, and expertise previously developed as a part of the NRC Steam 

17 Generator Action Plan (SGAP) were sufficient to resolve the associated technical issues in the 

18 SGAP. However, certain limitations restrict its usefulness in supporting future risk assessments. 

19 Several areas were identified for additional research and updates. Building upon the research 

20 conducted for resolution of the SGAP, this study was chartered to address development of “a 

21 simplified method for assessing the risk associated with consequential tube rupture/leakage in 

22 design-basis accident (DBA) and severe accident events.” Updated SG flaw distributions 

23 representing the current population of SGs were used along with the new thermal-hydraulic (TH) 

24 results from the MELCOR thermal hydraulic code for Combustion Engineering (CE) plants.

25

26 The scope of this study is limited to estimating the probability of containment bypass because of 

27 C-SGTR, and an assessment of the fraction of containment bypass that constitutes large early 

28 release frequency (LERF). It is assumed that a Level 1 PRA is available for both internal and 

29 external events such that the frequency of the sequences related to the C-SGTR evaluation can 

30 be easily obtained. The method defines the characteristics of the sequences of interest and 

31 demonstrates how they can be obtained from the existing PRAs or standardized plant analysis 

32 risk (SPAR) models for the two representative plants. The scope also includes an assessment 

33 of the probability that tube failures (rupture and leaks) can occur before failure of other RCS 

34 components. This is shown for two sets of sequences: severe accidents and DBAs. Severe 

35 accidents involve all sequences of core damage, where the SGs are dry (no secondary heat 

36 removal), and the primary pressure is high (generally at the set point of the primary relief 

37 valves). DBAs involve initiating conditions, where the pressure across the tubes is significantly 

38 higher than nominal pressure during operation. These sequences include: steam line break, 

39 feed line break, stuck open SG safety valve or atmospheric dump valve, and anticipated 

40 transients without scram.

41

42 It is expected that the method described in this report can be applied to a range of PRA 

43 applications. The insights from this study can be used to better inform simplified risk 

44 approaches by relying on a set of probabilities to screen and categorize emergent issues such 

45 as those identified through inspection findings or operational events. The more detailed 

46 methods used in this study could support a more comprehensive risk assessment suitable to 

47 support risk-informed decisions and the rule making process.

48

49 This work has significantly leveraged other ongoing or recently completed NRC activities 

50 associated with material characterization and behavior, and severe accident analysis. 
1-2

1 For example, this project relied on updated flaw distributions for reassessment of the conditional 

2 probabilities of C-SGTR. Flaw data from SG in-service inspections (ISI) were analyzed to 

3 characterize the flaw parameters and update flaw statistics. TH runs for the representative W 

4 plant generated by the RELAP code, and documented in NUREG/CR-6995, “SCDAP/RELAP5 

5 Thermal-Hydraulic Evaluations of the Potential for Containment Bypass during Extended Station 

6 Blackout Severe Accident Sequences in a Westinghouse Four-Loop PWR,” were used for this 

7 study. New calculations using the MELCOR severe accident code were run for selected 

8 sequences for a representative CE plant. This information was used as input to C-SGTR 

9 software to arrive at the probability of SG tube failure, before failure of the other RCS 

10 components. Uncertainties were treated to the extent possible throughout this evaluation. 

11 Although this study used the existing Electric Power Research Institute (EPRI) correlations for 

12 failure of the HL (HL) and surge line, these correlations can be readily updated within the 

13 existing C-SGTR software calculator should improved models become available.

14

15 This study represents an important update of the probability values used in prior analyses, 

16 which were based on the flaw data from earlier generation of SGs with older TH results, and for 

17 Westinghouse plants only. A comparison of the updated conditional probability values with 

18 values from previous studies was made, and key areas of disagreement were found to be 

19 attributed to the updated methodology and data.

20

21 Although SGTRs have been considered in risk analyses, thermally induced C-SGTR have 

22 typically not been considered. In the previous analyses the tube rupture was considered to be 

23 the initiating event. This rupture can lead to a severe accident if corrective actions are not taken 

24 in time. This type of SGTR is a design basis event for which plants are designed to cope 

25 without progressing to a severe accident. Plants have coped with all SGTRs to date. A 

26 C-SGTR differs from this sequence in that the severe accident causes the tube rupture.

27

28 C-SGTR thermal-hydraulic behavior has been studied extensively for Westinghouse plants in 

29 NUREG/CR-6995(Ref. 1) and also in NUREG-1570, “Risk Assessment of Severe 

30 Accident-Induced Steam Generator Tube Rupture” (Ref. 2). Some work was performed on CE 

31 plants with SCDAP/RELAP but, having predated the final Westinghouse analysis, it did not 

32 incorporate all the modeling improvements made for them. EPRI considered CE plants in its 

33 2002 steam-generator-tube-related risk analysis (Ref. 3).

34

35 Because of the capability to predict fission product releases in addition to thermal hydraulic 

36 behavior, the decision was made to switch to the MELCOR code to perform the CE C-SGTR 

37 analysis. Lessons-learned during the previous Westinghouse analyses were applied to the 

38 CE analysis during the work described in this report. This is further discussed in Section 3.0.

39

40 1.2 Objectives

41

42 The objective of this report is to document a simplified method for a quantitative assessment of 

43 probability of C-SGTR and LERF associated with consequential steam generator tube rupture 

44 during a severe accident after the onset of core damage, and during a DBA event before the 

45 onset of core damage. Estimating the probabilities of large early releases and containment 

46 bypass is the main focus for severe accidents. Screening probabilities for both core damage 

47 and containment bypass are addressed for DBA events.

48

49 The simplified methods are developed for two representative pressurized-water reactor (PWR)

50 plants: a Westinghouse (W) and a CE design. The study used the latest available TH for both 

51 plants, and updated flaw statistics pertinent to current reactors. It also used software tools 
1-3

1 containing the latest available model for estimating the failure probability/timings of SG tubes, 

2 and other reactor coolant system (RCS) components (i.e., HL and surge line). The results from 

3 these calculations were distilled into tables that showed the failure probabilities for SG tubes 

4 and RCS components. For PRA analysis, the bounding values for the probabilities of 

5 equipment failures and human errors were tabulated using of a spectrum of representative 

6 accident conditions. These tables could be used in lieu of conducting a detailed plant-specific 

7 analysis for performing simplified C-SGTR large early release frequency (LERF) evaluation.

8

9 Although the methods developed here were intended to address the study objectives (i.e., the 

10 screening method), they are intended to establish the framework to perform a more 

11 comprehensive PRA that can address the C-SGTR at a level of detail suitable for other needs. 

12 Extension of these methods can support the risk informed decision process and also be used to 

13 update the PRA Standards and PRA Procedure Guide.

14

15 1.3 Scope

16

17 The scope of this study is limited to estimating the probability of containment bypass because of

18 C-SGTR, and an assessment of the fraction of containment bypass that constitutes LERF. It is 

19 assumed that a Level 1 PRA is available for both internal and external events such that the 

20 frequency of the sequences related to the C-SGTR evaluation can be easily obtained. The 

21 method defines the characteristics of the sequences of interest and demonstrates how they can 

22 be obtained from the existing PRAs or SPAR models for the two representative plants. The 

23 scope also includes an assessment of the probability that tube failures (rupture and leaks) can 

24 occur before failure of other reactor coolant system components. This is shown for two sets of 

25 sequences: severe accidents and design basis accidents. Severe accidents involve all 

26 sequences of core damage, where the SGs are dry (no secondary heat removal), and the 

27 primary pressure is high (generally at the set point of the primary relief valves). DBAs involve 

28 initiating conditions, where the pressure across the tubes is significantly higher than nominal 

29 pressure during operation. These sequences include: steam line break, feed line break, stuck 

30 open SG safety valve or atmospheric dump valve, and anticipated transients without scram.

31

32 1.4 Summary of Differences from Previously Published Work

33

34 The study used the latest available thermal-hydraulics for both plants, updated flaw statistics 

35 pertinent to current reactors, and the latest available models and software for estimating the 

36 failure probability/timings of other SG tubes, and RCS components (i.e., HL and surge line). 

37 A C-SGTR software “calculator” was developed in conjunction with this study to simulate 

38 multiple flaws in SG tubes and to calculate tube leakage probabilities. Inputs for the calculator 

39 include thermal-hydraulic parameters of an accident sequence, tube flaws, and material 

40 properties. This software allows making numerous “what-if” runs with minimal effort to better 

41 understand progression of an accident, and pressure and temperature challenges to the tubes. 

42 Appendix B describes this software.

43

44 The other improvements for this study, as compared to previous studies, are the following:

45

46 • detailed computational fluid dynamics analysis and MELCOR severe accident modeling 

47 for a representative CE plant design

48

49 • detailed finite element analysis for the RCS HL nozzle to confirm the timing of structural 

50 failure
1-4

1

2

3 • consideration of more typical replacement SG tube materials such as thermally treated 

4 Alloy 600 and 690

5

6 • comprehensive integration of analyses from different fields, which include thermal 

7 hydraulic analyses, study of behavior of “other” RCS components, calculator software 

8 that allows study and documentation of many sequences; limited extension into fission 

9 product release analysis using MELCOR and, separately, estimation of LERF.

10

11 • insights obtained about failure behavior of flaws by making a multitude of runs with the 

12 Calculator.

13

14 1.5 Summary of Research Approach and Organization of Report

15

16 The work described in this report uses a probabilistic risk assessment approach. However, it 

17 includes other work from thermal hydraulic analyses using MELCOR (Section 3 of this report), 

18 and failure of assessment of “other RCS components” using ABAQUS (Section 4 of this report). 

19 Section 5 of this report offers a detailed description and technical bases for predicting the 

20 severe accident behavior of SG tubes. In addition, tube flaw distributions are generated for 

21 tubes with Alloy 600 and Alloy 690 materials (Section 6 of this report); these distributions are 

22 used in the probabilistic risk assessment.

23

24 The PRA sections of this report consist of Sections 2, 7, and 8. Figure 1-1 outlines the report 

25 structure and the flow of information among the work generated by the three different fields, 

26 namely, PRA, TH analyses, and materials analyses.

27

28 The new TH analyses for the reference Combustion Engineering Plant are made by using the 

29 MELCOR software. The MELCOR output can be viewed as consisting of two sets of outputs:

30

31 • TH profiles (e.g., temperature and pressure as a function of time) in the SG tubes and 

32 SG inlet regions (HL and surge line) for severe accidents

33

34 • fission product release results

35

36 The TH results from these analyses (item 1 above) are used in the PRA as input. Further 

37 conclusions drawn by the MELCOR analyses for fission product release, based on a set of 

38 modeling assumptions are independently generated and are not used by the PRA, which 

39 defines and estimates C-SGTR and LERF frequencies, independent of the other types of 

40 analyses.

41

42 Similarly, PRA used the existing EPRI correlations to estimate failure times for HL and surge 

43 line, compared to the failure times of the SG tubes. The extra analyses in Section 4 by 

44 ABAQUS are used for confirmatory purposes.

45

46 The PRA conclusions are summarized in Section 8. Other overall conclusions for the materials 

47 TH and PRA work are presented in Section 9.
1-5

1

2

Figure 1-1 Work and report layout 3
1-6

1 1.6 References

2

3 1. U.S. Nuclear Regulatory Commission, “SCDAP/RELAP5 Thermal-Hydraulic Evaluations 

4 of the Potential for Containment Bypass during Extended Station Blackout Severe 

5 Accident Sequences in a Westinghouse Four-Loop PWR,” NUREG/CR-6995, March 

6 2010, Agencywide Documents Access and Management System (ADAMS) Accession 

7 No. ML101130544.

8 2. U.S. Nuclear Regulatory Commission, “Risk Assessment of Severe Accident-Induced 

9 Steam Generator Tube Rupture,” NUREG-1570, March 1998, Agencywide Documents 

10 Access and Management System (ADAMS) Accession No. ML070570094. 

11 3. Electric Power Research Institute, “Steam Generator Tube Integrity Risk Assessment: 

12 Volume 1: General Methodology, Revision 1,” Technical Report 1006593, Palo Alto, CA, 

13 2002.
2-1

1 2. SEQUENCE DEFINITIONS

2

3

4 This section discusses accident sequences that are of interest for consequential steam 

5 generator tube rupture (C-SGTR) analysis, and identifies limiting (most challenging) sequences 

6 for steam generator (SG) types typically used in Westinghouse (W) and Combustion 

7 Engineering (CE) plants. The section initially describes accident sequence selection for 

8 pressure-induced failures of the SG tubes, which are caused by high differential pressure 

9 across the SG tubes but do not involve significant thermally induced creep growth of flaws. 

10 Next, the accident sequence selection process for thermally induced SG tube failures for severe 

11 accidents associated with high reactor coolant system (RCS) pressure and dry secondary-side 

12 conditions is described. The sequence selection process assumes that a Level 1 PRA is 

13 available, but the sequences identified are expected to be typical of a pressurized-water reactor 

14 (PWR) probabilistic risk analysis (PRA). The remaining subsections define the “critical” leak 

15 size for defining an SG fault as C-SGTR and provide a large early release frequency (LERF) 

16 model.

17

18 2.1 Pressure-Induced C-SGTR Sequences of Interest

19

20 Table 2-1 lists the sequences of interest for design-basis accident (DBA) events that could 

21 establish a delta pressure across the SG tube walls, and therefore, potentially challenge the 

22 integrity of the tubes because of pressure-induced failures. These DBA events were selected 

23 based on the expected differential pressure across the tubes. Several PRA sequences are 

24 combined and grouped based on their thermal-hydraulic (TH) behavior to yield a smaller set of 

25 candidate DBA sequences with similar challenges to the SG tubes. Plant-specific design 

26 features would determine if a sequence is applicable. For example, sequences involving a total 

27 loss of secondary cooling, but successful feed and bleed operation, are not applicable to plants 

28 that cannot feed and bleed (e.g., CE plants with no power operated relief valves (PORVs).

29

30 Generally, Level 1 PRA sequences can be grouped into one of these selected DBA sequences. 

31 The frequency of each of the DBA sequences then can be estimated by summing the individual 

32 frequencies of all the PRA sequences. PRAs compile the frequencies of the full accident 

33 sequences that result in core damage; however, they do not explicitly provide the frequencies of 

34 the partial accident sequences, which have not yet progressed to core damage. The required 

35 information for estimating the frequencies of the partial sequences can be easily obtained from 

36 the Level 1 PRA for internal and external hazards.

37
2-2

1 Table 2-1 Selected DBA Accident Sequences Causing Challenges To SG Tubes

2

Delta P 

Across the 

Tubes

Conditions Causing Delta 

P Across the Tubes Accident Sequence

SG Secondary-Side 

Condition [Pressure, 

Water Inventory]

~1,000 psi Normal power operation SGTR event Not known, will be 

determined by resulting 

core damage sequences

~1,500 psi Feed and bleed sequences 

with medium-head a

Emergency Core Cooling 

System (ECCS) pumps

All sequences involving 

loss of secondary heat 

removal but success of 

feed and bleed

Low pressure and dry SGs 

before rupture

Low pressure and dry SG 

condition is expected after 

core damage (CD) 

~2,000 psi 1. Un-isolable main steam 

line breaks (MSLB)

2. Inadvertent opening of 

SG relief valves, or 

turbine bypass valves 

with failure to isolate

All sequences are 

expected to result in loss 

of secondary cooling 

followed by feed and bleed 

cooling

Low pressure but not dry 

SGs before rupture.

Low pressure and possibly 

dry SG condition after CD

~2,250 psi Feed and bleed with high 

pressure ECCS pumps

All sequences involving 

loss of secondary heat 

removal but success of 

feed and bleed with stuck 

open secondary relief 

valves

Low pressure and dry SGs 

before rupture

Low pressure and dry SG 

condition after CD

~2,200 psi ATWS sequences when 

secondary cooling is not 

lost and pressure peak is 

limited to <3,200 psi

ATWS sequences with a 

favorable moderator 

temperature coefficient 

can result in a pressure 

peak as high as 3,200 psi 

in the primary

High pressure but not dry; 

however, failure of SG tube 

will induce core damage

All such CD sequences 

during ATWS are treated 

as LERF

~3,200 psi ATWS sequences when 

secondary cooling is lost 

and pressure peak is limited 

to <3,200 psi

ATWS sequences with a 

favorable moderator 

temperature coefficient 

can result in a pressure 

peak as high as 3,200 psi 

in the primary

High pressure and dry; 

however, failure of SG tube 

will induce core damage. 

All such CD sequences 

during ATWS are treated 

as LERF a The ECCS pumps used in U.S. PWRs can have a shutoff head as low as 1,200 psi and as high as 2,650 psi.

3

4 2.1.1 Core Damage Bridge Event Tree

5

6 As discussed in Section 2.1, DBA events of interest and the types of challenges to the SG tubes 

7 were characterized in Table 2-1. The C-SGTR is characterized by its occurrence probability 

8 and the size of its leak area. The occurrence probability of C-SGTR was estimated using the 

9 C-SGTR Calculator (see Appendix B), and the latest flaw data as discussed in Chapter 6. The 

10 leak area sizes could be divided into two or more bins (e.g., Small, Medium, and Large) to help 

11 in the estimation of time-sensitive human error probability values. A bridge tree was also 

12 developed to depict further progression of the accidents from the occurrence of C-SGTR 

13 through the onset of core damage. A general assumption used in developing this bridge tree is 

14 that the core damage has resulted from the C-SGTR, and it is not the result of the original 

15 initiator. It is assumed that the impact of the original initiator (e.g., main steam line break 

16 (MSLB) or anticipated transient without scram (ATWS)) would have been mitigated, if C-SGTR 

17 had not occurred. For example, it is assumed that a proper response would be provided to an

18 MSLB initiator, and the reactor would reach a safe, stable condition if C-SGTR had not 
2-3

1 occurred. The occurrence of C-SGTR, therefore, results in a transfer of the sequence of 

2 interest (entry level sequence) to a bridge tree that would be similar to that of an SGTR initiator 

3 (SGTR-INIT) tree in Level 1 PRAs. However, the boundary conditions imposed by the entry 

4 level sequence should be preserved by setting proper conditions on the branches of the 

5 SGTR-INIT event tree. Plant-specific SPAR trees for SGTR-INIT can be used for this purpose. 

6 The generic core damage bridge event tree is shown in Figure 2-1. The plant-specific event

7 tree can be used if available.

8

9 The headings of the top branches for the event tree in Figure 2-1 are defined as follows:

10

11 • SGTR-INIT: Induced SGTR from DBA events

12

13 • HPI: High-Pressure Injection systems: both safety injection pumps and charging pumps 

14 if applicable

15

16 • SHR: Secondary Heat Removal system: Main Feedwater (MFW) or Auxiliary 

17 Feedwater (AFW)

18

19 • FB: Feed and Bleed operation and the supporting relief path

20

21 • EQ: Operator actions for equalization, which involves control of primary pressure, and 

22 depressurization below the pressure set point for the secondary relief valves

23

24 • RWST-MU: Long term makeup water to RWST

25

26 • HPR: High-Pressure Recirculation and the associated operator action

27

28 • RHR: Operator action to cool down to cold shutdown, and align the Residual Heat 

29 Removal system

30

31 • RS: Recirculation Spray cooling in those plants that do not use RHR heat exchangers 

32 as a part of HPR

33

34 The end state CD refers to core damage.

35

36 With the exception of the ATWS sequence, the effect of other entry sequences will be 

37 superimposed on this bridge tree. For example, for sequences involving feed and bleed using 

38 the high pressure ECCS, the following conditions will be imposed:

39

40 • Top event FB is set to success.

41

42 • SHR and EQ are both set to failure.

43

44 • Depending on plant-specific design features, HPR may not be possible, because most of 

45 the leakages happen through the SGTR rather than ending up in the containment sump.

46

47 For ATWS sequences, the C-SGTR is conservatively assumed to result in core damage and 

48 LERF because of the added complication of boron concentration control because of loss of 

49 borated coolant through the ruptured tube.
2-4

1

2

Figure 2-1 Generic core damage bridge event tree for DBA-induced C-SGTR 3

SGTR-INIT

SGTR Initiator

HPI

High Pressure Injection

SHR

Secondary Heat 

removal--AFW

FB

Feed and Bleed

EQ

Equalization of primary 

and secondary pressure

RWST-MU

Make up to RWST

HPR

High Pressure 

Recirculation

RHR

Cool down and align 

RHR

RS

Recirculatio

cooling to sup
2-5

1 2.1.2 Level 2 Event Tree: LERF Determination

2

3 A detailed Level 2 PRA model should address the following:

4

5 • The operation of primary and secondary components after the occurrence of core 

6 damage with an existing C-SGTR determines the status (e.g., the pressure) of the 

7 primary and secondary systems. The status of primary and secondary are needed to 

8 determine different release categories. The probability of the successful operation of the 

9 primary and secondary relief valves under the harsh environment of the severe 

10 accidents, are needed to determine the release categories associated with C-SGTR.

11

12 • Modeling of Severe Accident Managements requires performing a detailed human 

13 reliability analysis that can address human decision making under limited knowledge and 

14 guidance.

15

16 • Close coordination among PRA modeling needs, the supporting TH, and severe 

17 accident analyses is needed to address adequately the effectiveness of severe accident 

18 management guideline (SAMG) activities and their effects on release categories.

19

20 • Identifying the time when the emergency actions levels (EALs) are triggered, especially 

21 the time when general emergency is activated, in comparison to time of release, is 

22 considered necessary to define the evacuation effectiveness and differentiate between 

23 early and late releases.

24

25 The simplified Level 2 models considered for this study have limited scope and are intended to 

26 address LERF. The following are two commonly used definitions of LERF:

27

28 (1) ASME PRA Standard (Ref. 6) defines LERF as; “The rapid, unmitigated release of 

29 airborne fission products from the containment to the environment occurring before the 

30 effective implementation of offsite emergency response and protective actions.”

31

32 (2) RG 1.174 (Ref. 7) defines LERF as; “The frequency of those accidents leading to 

33 significant, unmitigated releases from containment in a time frame prior to effective 

34 evacuation of those close-in population such that there is a potential for early health 

35 effect.........”

36

37 The effective evacuation is not precisely defined. It was generally assumed that if 95 percent or 

38 more of the close-in population is evacuated before release, the sequence is not considered a 

39 LERF. This has been considered as the state of practice for risk-informed applications that 

40 relied on Delta-CDF (core damage frequency) and Delta-LERF as criteria including the SDP 

41 portion of ROP.

42

43 The occurrence of C-SGTR after an ATWS is considered as a general emergency and will 

44 activate the evacuation process as a part of emergency planning. Any large un-isolable leakage 

45 outside containment through C-SGTR is considered as a site emergency, because it will affect 

46 both the reactor coolant and the containment barrier. General emergency will ensue when 

47 potential fuel barrier degradation occurs (at the onset of core uncovery). Therefore, in both 

48 cases, there would be a high potential for effective evacuation.

49
2-6

1 The likelihood of the occurrence of LERF sequences for pressure-induced C-SGTR during DBA 

2 sequences is relatively low. The dominant contributor to the risk is the failure to equalize and 

3 isolate the faulted SG followed by the failure to make up to reactor water storage tank (RWST). 

4 The core damage resulting from such sequences typically occur late enough, such that 

5 evacuation can be credited and LERF be eliminated. Early core damage and potential LERF 

6 sequences require additional failures; such as failure of high-pressure injection (HPI) and dry 

7 SGs. SGs are generally not expected to be dry unless the sequence involves failure of both 

8 Main and Auxiliary feed water systems. In such cases, there are two major SAMG actions 

9 typically credited for controlling the release, and possibly arresting further core melt progression 

10 within the vessel. These SAMG actions are:

11

12 • to arrest the core melt within the vessel by depressurizing and injecting water into the 

13 primary system

14 • to reduce releases by depressurizing the SG, and filling it up with an alternate source of

15 water

16

17 The vessel can be depressurized by opening all PORVs, thereby allowing coolant injection from 

18 the low-pressure emergency core cooling system. RCS depressurization could also take place 

19 because of a medium or a large loss-of-coolant accident (LOCA), but not generally from a small 

20 LOCA. Primary depressurization through secondary cool down using the intact SGs and the 

21 pressurizer spray could also be credited for success of RCS depressurization. However, to 

22 provide this credit, the analyst should identify the probability that one or more SGs remain intact 

23 (not isolated because of SGTR). Although there could be several possible means for the 

24 primary depressurization, all are driven by dependent operator actions.

25

26 Primary depressurization could result in the injection of accumulator water into the vessel, which 

27 could provide additional time for the operator to align makeup water to RWST for injection into 

28 the vessel. This is sometimes referred to as post core damage RCS injection to arrest core melt 

29 within the vessel. Injection to the vessel is assumed to arrest core melt, and therefore, it 

30 significantly limits the amount of in-vessel releases. RCS depressurization or the occurrence of 

31 a medium or large LOCA would also create a major path of release to the containment rather 

32 than through SG tube rupture. Therefore, if any of these SAMG actions are successful, the 

33 release through SGTR is expected to be negligible.

34

35 In addition, severe accident analyses are required to examine the effectiveness of such 

36 strategies, including an examination of possible re-criticality because of injecting nonborated 

37 water to refill the RWST. Failure to inject from the accumulators would significantly reduce the 

38 time available for operators to align makeup to the RWST. It is, therefore, assumed that 

39 makeup to RWST cannot be successfully performed without the injections from accumulators.

40

41 A simplified model was proposed for the current study. This model relies on five factors as 

42 defined below:

43

44 (1) frequency of DBA sequences with potential for C-SGTR fAC

45 (2) C-SGTR probability PCSGTR

46 (3) conditional core damage probability PCCD

47 (4) failure probability of all SAMG actions PSAMG

48 (5) probability that early effective evacuation is not successful PEVAC

49
2-7

1 LERF is defined by the product of these five factors. Conservative estimates were assigned to 

2 the above factors for the purpose of screening study, and it has been further discussed in 

3 Section 7.

4

5 2.2 Thermally Induced C-SGTR Sequences

6

7 This section details the sequences of interest for potential occurrence of C-SGTR after the 

8 onset of core damage during severe accidents. These sequences generally involve high 

9 primary pressure with at least one or more dry SGs, and low secondary pressure known as 

10 high-dry-low Sequences. The best way to identify such sequences is to use the binning 

11 information generated for defining plant damage states (PDSs) from Level 2 PRAs. Those 

12 PDSs that are binned into a class with a high primary pressure and with at least one or more dry 

13 SGs (i.e., loss of both MFW and AFW are required), are candidates of severe accidents with a 

14 potential for C-SGTR. Therefore, the identification and determination of the frequencies for 

15 these sequences are readily available for those plants that have developed Level 2 PRA 

16 models.

17

18 However, for all other plants without Level 2 PRA models, a selected number of sequences are 

19 generically identified for the purpose of characterizing their TH behaviors, time of core damage, 

20 and other information important to C-SGTR. These sequences are shown in Table 2-2 below. 

21 They are selected based on the expected TH behavior, and the type of challenges they will 

22 have on SG tubes. They are not the same as PRA core damage sequences. Several PRA core 

23 damage sequences from internal and external hazards with similar TH behavior are combined 

24 and grouped together under each of these selected sequences. There are a total of five base 

25 case sequences, noted as Base Cases 1 through 5. Each base case sequence could be 

26 slightly changed to obtain some alternative sequences. The time of the onset of core damage 

27 from the occurrence of an initiator, is specified as early or late in the second column of the table. 

28 As will be discussed, “early” generally means less than 8 hours, and “late” generally means 

29 greater than 8 hours. The exact timing for “early” and “late” depends on the time when a 

30 general emergency is activated. The period of interest is generally between the activation of 

31 general emergency to the onset of core damage. It is not associated with the time that the plant 

32 initiator occurred.

33

34 The extended station blackout (SBO) sequences are the most representative sequences that 

35 can cover all the sequences identified in Table 2-2. The thermal hydraulic results from the 

36 limiting accident sequence resulting for the selected Westinghouse and CE plants are discussed 

37 on Sections 2.3 and 2.4 respectively. The critical size for C-SGTR to be considered LERF and 

38 the proposed LERF model are discussed in Sections 2.5 and 2.6 respectively.

39
2-8

1

Table 2-2 Selected Sequences to Evaluate C-SGTR for Severe Accident Sequences

Core Damage 

(CD) Sequences

Time for the Onset of 

Core Damage 

Relative to the 

Activation of a 

General Emergency 

(GE)

Availability of DC for 

Primary/Secondary 

Depressurization and 

Performing 

SAMG Activities

Notes

Base Case-1: SBO 

with failure of TDAFW 

at time zero, small 

reactor cooling pump 

(RCP) leakage 

(21 gpm), and 

equivalent 0.5 inches of 

leakage (relief path) 

from the SG secondary 

to the environment

Early Yes Base case probability 

of C-SGTR before HL 

failure

Alternate 1: Base 

Case-1 and 1 PORV or 

an SRV sticks open

Early Yes Lower probability of 

C-SGTR before HL 

failure due to lower 

primary pressure

Alternate 2: Base 

Case-1 except RCP 

seal leakage greater 

than 180 gpm per 

pump

Early Yes Possibly higher 

probability of C-SGTR 

due to possible 

clearing of the loop 

seals 

Alternate 3: Base 

Case-1 except no 

leakage or smaller 

leakages than 

0.5 inches from 

secondary side of SG 

to the environment

Early Yes Lower probability of 

C-SGTR than nominal 

since the secondary 

pressure is maintained 

and the delta pressure 

across the tubes are 

reduced 

Alternative 4: Base 

Case-1 except larger 

leak area through the 

secondary of SGs; 

e.g., as a result of a 

stuck open SG PORV

Early Yes Higher probability of 

C-SGTR is assumed 

since after tube failure, 

the larger area through 

SG secondary would 

depressurize the 

primary, and therefore, 

reduce the likelihood of 

HL failure

Base Case-2: SBO 

with failure to load shed 

to extend battery life, 

rendering the failure of 

TDAFW to continue to 

run 

Early or Late:

Depending of battery 

duration could be 

considered either late 

or early

No Similar C-SGTR 

probability to Base 

Case-1
2-9

Table 2-2 Selected Sequences to Evaluate C-SGTR for Severe Accident Sequences

Core Damage 

(CD) Sequences

Time for the Onset of 

Core Damage 

Relative to the 

Activation of a 

General Emergency 

(GE)

Availability of DC for 

Primary/Secondary 

Depressurization and 

Performing 

SAMG Activities

Notes

Base Case-3: SBO 

with successful load 

shed to extend battery 

life. Failure of TDAFW 

to continue to run after 

battery depletion

Late No Similar C-SGTR 

probability to Base 

Case-1

Base Case-4: 

Non-SBO sequences 

with total failure of 

secondary cooling at 

time zero and failure to 

do feed and bleed 

operation

Early Yes Similar to Base Case-1 

probability

Base Case-5: 

Non-SBO sequences a

with delayed failure of 

secondary cooling and 

feed and bleed 

operation [ e.g., loss of 

service water, loss of 

chilled water due to 

external hazards]

Late Yes Varying probability of 

C-SGTR depending on 

plant-specific features 

and the details of the 

sequences. These 

sequences could also 

cause RCP seal 

failures, with varying 

degrees of leakages a Seal LOCAs for CE plants could occur as a result of loss of cooling and failure of operator to trip the pumps. 

Seal leakages of 1,703 Liters per minute (450 gallons per minute) per pump could result. Failure of this 

operator action is normally assigned a probability of 1.0E-3 per demand.

1

2 2.3 Representative Sequences for a Westinghouse Plant

3

4 The TH analysis and the success criteria used for developing the PRA models for C-SGTR for a 

5 representative Westinghouse Plant were gleaned from the information reported in 

6 NUREG/CR-6995, “SCDAP/RELAP5 Thermal-Hydraulic Evaluations of the Potential for 

7 Containment Bypass during Extended Station Blackout Severe Accident Sequences in a 

8 Westinghouse Four-Loop PWR,” (Ref. 1). NUREG/CR-6995 documents the TH evaluations 

9 performed using the SCDAP/RELAP5 systems analysis code and a model representing a 

10 Westinghouse four-loop PWR; i.e., the Zion Nuclear Power Plant (ZNPP). The plant model 

11 benefitted from the following:

12

13 • extensive iterative comparisons with evaluations of natural circulation flows and turbulent 

14 mixing using a computational fluid dynamics code

15

16 • comparison with experimental data for pertinent fluid-mixing behavior

17

18 NUREG/CR-6995 also included some sensitivity evaluations and uncertainty analyses of the 

19 station blackout accident sequences.

20
2-10

1 The base sequences were modeled assuming a pre-existing leakage through the secondary 

side of each SG, equivalent to a hole of 3.2 square centimeters (cm2

) (0.5 square inch [in.2 2 ]). 

3 This size of leakage is sufficient to ensure that the pressures in the secondary side of the SGs 

4 approach the atmospheric pressure after steam generator dryout, as discussed in Appendix A of 

5 Reference 2. However, the assumed leakage area was shown to be insufficient to maintain a 

6 low SG secondary-side pressure after the occurrence of a guillotine break of a single SG tube.

7

8 The following points taken from Reference 2 are provided to emphasize the expectation that, 

9 during a severe accident sequence, the secondary-side depressurization is highly like to be 

10 present:

11

12 • The findings from the TH analyses indicate that secondary leak areas of 3.22 and 

6.45 cm2 (0.5 and 1.0 in.2 13 ) result in essentially full depressurization of the steam 

14 generator by the time the severe accident-induced temperature ramp occurs.

15

16 • Leaks directly to atmosphere. Given closure of the main stem isolation valves 

17 (MSIVs), feed water isolation valves (FWIVs), and steam generator blowdown 

18 valves, such leaks would need to be in the stems or seals of these valves; the 

19 stems or seals of other valves or ports upstream of these valves; or the stems, 

20 seals, or seats of the secondary-side PORVs or SRVs. Such leaks would be 

21 present during normal operation. Another potential leakage source could occur if 

22 a secondary-side PORV or SRV re-closes, but does not re-close completely 

23 (e.g., allows a small amount of leakage).

24

25 • Leaks into the secondary piping. Perhaps more significant is the potential for 

26 leakage past the isolation valves into the downstream piping in the secondary 

27 system. The long, large runs of piping have a significant volume and so could 

28 accept small leakage rates without themselves pressurizing to provide any 

29 backpressure. The amount of leakage past the valve seats would be very small 

30 relative to the total size of the valve. A 508-centimeter (20-inch) diameter MSIV 

would have a total flow area of over 1,935 cm2 (300 in.2 31 ). Therefore, an MSIV 

32 that is 99.9 percent closed will still not be sufficient to maintain secondary 

33 pressure. Not being part of the containment boundary, steam generator isolation 

34 valves are not required to meet containment isolation leak rate requirements. 

35 The performance requirements for these valves are established based on 

36 maintaining pressure in the steam generators when full, and so they are not 

37 required (nor are they designed, qualified, or tested) for this kind of leak 

38 tightness.

39

40 The main two sequences modeled were:

41

42 (1) station blackout with early failure of the turbine-driven auxiliary feed water (TDAFW) 

43 pump resulting in core damage and a potential for C-SGTR because of creep rupture

44

45 (2) station blackout with failure of TDAFW after battery depletion

46

47 Several sensitivity case studies were also performed. These sensitivity case studies generally 

48 addressed different issues as summarized below:

49
2-11

1 • The effect of RCP seal leakage was examined by considering various sizes of RCP seal 

2 leakages from 79.5 liters per minute (lpm) (21 gallons per minute (gpm)) per pump and 

3 up. The case runs evaluated the pressure and temperature impact on primary and 

4 secondary systems, and examined the impact on loop seal clearing potential.

5

6 • The effect of early depressurization on the sequence progression was also examined by 

7 considering the operator’s action to depressurize SGs at 30 minutes, by opening at least 

8 one SG atmospheric dump valve (ADV) or SG PORV per SG. This action drops the 

9 primary pressure below 4.83 megapascals (MPa) (700 pounds per square inch [psi]). 

10 This actuates the accumulator discharge. Two cases have been analyzed depending on 

11 the rate of depressurization (slower and faster rates).

12

13 • The effect of C-SGTR with an equivalent guillotine break of one tube on primary 

14 depressurization and therefore preventing/delaying HL (HL) failure was also examined. 

15 It was found that this results in a slow depressurization of the primary; however, it is not 

16 fast enough to prevent HL failure.

17

18 Several other sensitivity studies were performed. A detailed discussion of these sensitivity case 

19 runs, along with their TH behavior, and their effect on PRA results for the representative 

20 Westinghouse plant, is made in Section 7.1.

21

22 2.4 Representative Sequences for a Combustion Engineering Plant

23

24 The TH analyses used to support the development of the PRA models and success criteria 

25 were based on the information contained in Calvert Cliffs individual plant evaluation/individual 

26 plant evaluation for external events (IPE/IPEEE) and the MELCOR results. Section 3 discusses 

27 the TH evaluations performed using the MELCOR severe accident analysis code and a model 

28 that represents a CE plant (i.e., Calvert Cliffs Nuclear Power Plant (CCNPP)). MELCOR 

29 analyses were performed in two stages. The first stage of analyses was considered preliminary. 

30 All discussion in this document relies on the second stage of MELCOR analysis. Some insights 

31 gained from the first stage sensitivity analyses were used to shape some of the PRA arguments.

32

33 2.4.1 Description of the Selected TH Sequences

34

35 The following two representative base sequences were evaluated using the latest MELCOR 

36 evaluation for use in estimating the base probability of C-SGTR. In these two sequences, a 

leakage through the secondary side of each SG, equivalent to an area of 3.22 cm2 (0.5 in.2 37 )

38 hole, was modeled. This size of leakage was sufficient to ensure that the pressure in the 

39 secondary side of the SGs approached the atmospheric pressure after steam generators have 

40 been dried out. This size of leakages, however, is not sufficient to maintain low secondary-side 

41 pressure if SG tubes have ruptured.

42

43 The results from the MELCOR evaluation were slightly different in format from the 

44 SCDAP/RELAP5 results reported in NUREG/CR-6995. The MELCOR results are provided for 

45 each plant loop separately (i.e., RCS loop A with pressurizer and RCS loop B without the 

46 pressurizer). Furthermore, the MELCOR results represent two types of hot tubes: one exposed 

47 to the hottest gas temperature, and the other exposed to an average hot gas temperature. This 

48 additional information was used in PRA evaluation for CE plants.

49
2-12

1 (a) An SBO with failure of the TDAFW pumps early in the sequence (i.e., at time zero) 

2 followed by an early core damage with a potential for C-SGTR because of creep rupture 

3 is considered for this sequence. An RCP seal leakage of 79.5 lpm (21 gpm) per pump is 

4 also considered for this sequence. The MELCOR results for these case runs are 

5 applicable to several PRA accident sequences with similar behavior (see earlier 

6 discussion in this Section). For SBO sequences, this includes an SBO sequence with 

7 simultaneous failures of TDAFW pumps because of common cause failure to start, and 

8 an SBO with an initial availability of TDAFW pumps followed by their failures because of

9 SG overfill in an hour.

10

11 (b) An SBO with delayed failures of TDAFW pumps after battery depletion is considered for 

12 this sequence. TDAFW is initially available, but it will fail shortly after the depletion of 

13 the battery because of the loss of direct current (dc) power. A normal RCP seal leakage 

14 of 21 gpm per pump is considered. The MELCOR analysis assumes that the TDAFW 

15 pumps were operating for a period of 4 hours.

16

17 A set of sensitivity analyses was performed using the MELCOR evaluation by assuming that 

18 there is zero leakage through secondary system at the start of SBO (instead of the generally 

assumed leakage area of 3.2 cm2 [0.5 in.2 19 ]), such that the secondary relief and safety valves will 

20 be demanded early during accident and before the onset of core damage. MELCOR evaluation 

21 for this case further assumes that the secondary relief and safety valves fail to reclose after the 

22 first opening.

23

24 MELCOR evaluations performed other sensitivity analyses to further examine the effect of 

25 various sequences. The following were noted:

26

27 • C-SGTR with an equivalent leakage area of the guillotine break of less than one tube will 

28 not result in depressurization of the primary.

29

30 • An equivalent leakage area of one or more tubes could result in a significant release of 

31 one or more of the SG safeties, or the relief valves are left open or stick open.

32

33 • The primary is initially depressurized and the accumulator discharges when one or more 

34 secondary relief valve sticks open early in the accident. This will further delay HL/surge 

35 line creep rupture failures. The probability of C-SGTR because of creep rupture, 

36 however, is not affected as much because the lower secondary-side pressure increases 

37 the delta pressure across the tube.

38

39 A detailed discussion of these sensitivity case runs, along with their TH behavior, and their 

40 effect on PRA results for the representative CE plant is made in Section 7.2.

41

42 2.5 Definition of “Critical Size” for C-SGTR

43

44 2.5.1 Critical Leakage Areas Resulting from SG Tube Failures

45

46 The leakage area through the failed SG tubes determines the consequence and severity of the 

47 C-SGTR accident. It is generally assumed that there is a threshold or a critical leakage area, 

48 beyond which the impact of larger leak areas on the accident severity will be negligible. The 

49 considerations for determining these critical leakage areas are discussed in this section.

50
2-13

1 Occurrence of C-SGTR early during other accident sequences considered for PRA analyses 

2 (such as large secondary-side break, ATWS, etc.) would require the operator to respond and 

3 perform additional actions as if they are responding to an SGTR initiator. For such events, the 

4 size of the leakage determines how fast the operator should attempt to cool down and 

5 depressurize the primary to isolate the affected steam generators. The most striking PRA effect 

6 of larger leakage areas through SG tubes during DBA events is a higher failure probability of the 

7 related operator actions.

8

9 For C-SGTR during a severe accident, the size of the leakage area would determine the size of 

10 release through containment bypass. It determines if the end state of a particular containment 

11 bypass sequence should be categorized as LERF. For a small leakage, the primary is expected 

12 to stay pressurized (generally at primary relief set point which is about 15.5 MPa [2,250 psi]), 

13 resulting in a failure of other RCS components (e.g., HL) shortly after the failure of the tubes. 

14 The failure of the RCS component, therefore, significantly reduces and eliminates any release 

15 through the SG tubes. These sequences of containment bypass because of C-SGTR may not 

16 be categorized as LERF.

17

18 Larger leakages could pressurize the secondary side of the affected SG such that both primary 

19 and secondary sides equalize at the pressure set point of the SG relief valves (which are about 

20 8.27 MPa [1,200 psi]). In this case, there is a lower failure probability of the other RCS 

21 components (e.g., HL) because of lower primary pressure. This pressure assumes that the SG 

22 PORVs and safety relief valves (SRVs) cycle as many times as needed without any failures. If 

23 any of the SG relief valves fails to open (sticks open), the primary will be depressurized and this 

24 eliminates any possibility of failure of other RCS components. There could also be a threshold 

25 for larger leakage areas through the failed SG tubes such that the countercurrent flow through 

26 the HL cannot be maintained. In such cases, the hot steam will flow through the SG tubes, 

27 causing massive tube failures resulting in a large containment bypass.

28

29 A discussion of the critical leak areas for DBA and severe accident sequences has been 

30 detailed below.

31

32 2.5.1.1 Critical Leakage Areas for DBA Accidents

33

34 The key mitigating actions, in response to a DBA-induced SGTR (except ATWS) sequences), 

35 are to:

36

37 • Establish a secondary heat sink.

38 • Isolate the affected SGs.

39 • Depressurize the RCS to avoid cycling of the safety valves on the affected SG.

40 • Refill the RCS.

41 • Establish long-term cooling.

42

43 If the secondary heat sink is lost, feed and bleed cooling can be used. When feed-and-bleed 

44 cooling is used, long-term actions are needed for cold leg recirculation or for continued makeup 

45 to the reactor water storage tank (RWST).

46

47 All pressure-induced SG tube ruptures (i.e., burst) during ATWS sequences are conservatively 

48 assumed to result in core damage and LERF.

49
2-14

1 The main effect of larger leakage areas from SG tubes during DBAs is the reduction in the 

2 amount of time that the operators have to cool down and depressurize the primary system. 

3 Because of reduced time, the probability of an operator error causing an SG over-fill could 

4 significantly increase. This, in turn, could result in flooding of the steam lines, and possibly 

5 cause an SG safety or relief valve to fail to reclose. SG over-fill would also cause the failure of 

6 the TDAFW because of water carryover. If one were to assume a tube rupture sequence

7 exceeding several tubes failing, it would ensure a stuck-open safety valve. This would lead to a 

8 failure of isolating the affected SG with an increased likelihood of core damage. Although the 

9 timing for the plant response is shortened for some actions as described above, the remaining 

10 time available for other key actions in the accident sequence (such as initiation of feed and 

11 bleed) may not be affected by the size of the C-SGTR leakage areas.

12

13 The following guidelines for the critical areas associated with C-SGTR during DBA sequences 

14 were considered for this scoping study.

15

16 (a) For ATWS sequences, tube failures are assumed to directly result in core damage and 

17 LERF regardless of the size of leakage (without further analysis).

18

19 (b) For all other sequences, a leakage area equivalent to a guillotine break of one tube is 

20 assumed to have occurred. This size of the break requires the operator to follow the 

21 emergency operating procedure associated with SGTR initiators. For PRA purposes, 

22 such C-SGTR events are transferred to the PRA SGTR event tree for estimating the 

23 delta core damage frequency and delta LERF.

24

25 2.5.1.2 Critical Leakage Areas for Severe Accidents

26

27 Earlier studies (such as a Sandia National Laboratories (SNL) study documented in Reference 

28 2) showed that SG tube failures generally occur shortly after the onset of fuel damage for 

29 severe accidents. The SNL study performed a rough estimate of a critical SG tube leak area 

30 that could release the whole primary volume in 4 hours. This was done because of a lack of 

31 detailed severe accident analysis of post SG tube rupture. The SNL report therefore, 

32 determined that:

33

34 • Flow through the cracks is choked (no secondary to primary pressure equalization).

35

36 • Early containment bypass occurs if the contents of the RCS are released through the 

37 cracks in less than 4 hours (no HL failure or failure of other RCS components was 

38 considered).

39

40 An uncertainty distribution for the required crack opening area was determined by considering 

41 the uncertainties in:

42

43 • the release time for containment bypass

44 • the temperature of the gas exiting the break

45 • the specific heat ratio for the gas mixture

46 • the average molecular weight of the gas mixture

47

48 Using this analytical approach, the mean crack opening area for containment bypass is 

calculated to be 0.52 cm2 (0.081 in.2 49 ). The lower and upper 90-percent confidence limits for this 

value were calculated to be 0.34 cm2 (0.053 in.2

) and 0.8 cm2 (0.124 in.2 50 ), respectively.
2-15

1

2 Sandia’s estimate is considered to be conservative by this study: for example, this size of 

3 leakage is not expected to depressurize the primary fast enough to prevent the failure of the 

4 HLs. The likelihood of the failures of an RCS component is expected to be close to one, if the 

5 primary is not significantly depressurized.

6

7 The current study defines critical leak areas by considering three SGTR leak areas that could 

8 affect the progression of the accident and the amount of releases. These are:

9

10 (1) For small C-SGTR leak areas less than guillotine break of one tube; between 

4.8–6.4 cm2 (0.75–1 in.2 11 ) and greater than the areas considered by the SNL report, the 

12 primary is not expected to depressurize, and the likelihood of failure of the HL or other 

13 RCS components, is expected to be quite high. For these sizes of leak areas, repeated 

14 cycling of primary SRVs, including the possibility that at least one SRV sticks open, is 

15 expected to be high. Therefore, most of the in-vessel releases will end up in the 

16 containment rather than leaking through the small C-SGTR leak area. The probability 

17 that such leakages (i.e., containment bypass) results in LERF is negligible.

18

19 There is also a leak area that can pressurize the SG secondary side such that a significant 

20 amount of cycling of the SG PORV is expected (and therefore a release path to the 

21 environment). In such cases, the primary and secondary side will equalize at a pressure of 

22 around 8.3 MPa (1,200 psi), unless the SG PORV fails to re-close. The results of severe 

23 accident analysis (RELAP runs for the representative W plant and MELCOR for the 

24 representative CE plant) indicate that tube leak areas equivalent to a guillotine break of one 

tube; between 4.8–6.4 cm2 (between 0.75–1 in.2 25 ), generally satisfy this criterion. A typical 

26 guillotine break for plants discussed in Section 7 has a maximum total leak area of about 

6 cm2

(0.9 in.2 27 ).

28

29 An SG tube leak area could be large enough to reverse the countercurrent flow described in 

30 Chapter 3.1 and transform it to a unidirectional flow regime. In such cases, a large number of 

31 tubes are assumed to fail because of exposure to hot gas temperatures. The release is also 

32 expected to be large and early similar to the previous case (case b), without sufficient time 

33 available for recovery actions or arresting the melt progression within the core. The 

34 countercurrent flow limit between the hot gas and the cold air is an issue that has been 

35 considered for the purpose of fire modeling in tunnels. In such analysis, one is to determine the 

36 cold flow velocity (e.g., through ventilation) such that it prevents the hot gases from progressing 

37 toward a protected area. The criterion typically used in such analysis, uses the Froude (Fr) 

number analogy (Ref. 4). Leak area of approximately 18.5 cm2 (or about 2.8 in.

2 38 ), which is 

39 equivalent to a guillotine break of three tubes) was roughly estimated for this sequence. 

Therefore, if the critical leak area of 18.5 cm2 (2.8 in.

2 40 ) is reached, a significant number of tubes 

41 are expected to start failing because of the collapse of countercurrent flow.

42

43 From the discussion provided above, two critical areas of containment bypass were considered 

for this scoping PRA study. Leak areas equivalent to a 4.8–6.4 cm2 (0.75–1 in.2 44 ); guillotine 

45 break of a tube are considered to have a potential for LERF, if an SG relief valve sticks open. 

46 On the contrary, this size of leakage has no LERF potential if the primary relief valve sticks 

open, and none of the SG relief valves fail. The small secondary hole; 3.2 cm2 (0.5 in.

2 47 ), that is 

48 assumed in the analysis to depressurize a dry SG does not provide a significant contribution to 

49 LERF and it is not of sufficient size to depressurize the SG secondary side after C-SGTR 

50 occurs.

51
2-16

1 A leakage area equivalent to the areas of three tubes is treated as LERF because the SG relief 

2 valves are expected to fail eventually because of repeated cycling. Similar assumptions were 

3 made for cases where the loop seals are cleared during a severe accident.

4

5 2.6 A LERF Model

6

7 The end state associated with Level 1 event trees generally corresponds to the time when the 

8 fuel begins to uncover. For some sequences, there is a large inventory of water in the 

9 secondary sides of the steam generators at the time when the fuel begins to be uncovered. 

10 It could, therefore, take some time (about an hour and a half) for the steam generator to become 

11 dry. The countercurrent flow regime occurs in the HLs after SGs become dry. If the PORV and 

12 the direct current power are available or recovered during this period, the operator could open 

13 the PORVs and depressurize the primary, therefore, avoiding or significantly diminishing the 

14 probability of C-SGTR.

15

16 If the operators fail to depressurize the primary, and SGTR occurs before HL failure 

17 (i.e., C-SGTR), the primary pressure would remain high for small SGTR leak areas. The 

18 likelihood of HL failure should then be considered. For larger C-SGTR leaks, however, when 

19 the primary is depressurized partially through the ruptured tubes, the likelihood of HL failure is 

20 expected to be smaller. Furthermore, after SGs have dried up, it typically takes another 6 to 

21 8 hours for the vessel breach to occur. This provides a sufficient time period for SAMG 

22 activities to arrest the core melt within the vessel, and scrub any possible releases through the 

23 ruptured SG tubes.

24

25 The release through C-SGTR will nearly stop when the core melt is arrested and the SG 

26 secondary is filled with water. Therefore, the time it takes for SAMG actions to become 

27 effective, determines the magnitude of the release. This is considered as an important step for 

28 categorizing the size of releases in terms of the magnitude of source term.

29

30 The release categories are generally binned into several groups depending on the magnitude of 

31 release and the time of release after evacuation. Some past studies (Ref. 3) have suggested 

32 the following release bins:

33

34 • large-early release (LER)

35 • large-late release (LLR)

36 • medium-early release (MER)

37 • medium-late release (MLR)

38 • small-early release (SER)

39 • small-late release (SLR)

40 • negligible or controlled late releases (CLR)

41

42 The exact definitions of these release categories in terms of the timing and the magnitude of the 

43 releases have not yet been reported in open literature. The magnitude of releases is sometimes 

44 defined by the fractional releases of iodine (I) and cesium (Cs). For example, large, medium, 

45 and small could correspond to a release fraction (RF) of greater than 5 percent (RF>5%), 

46 between 1 and 5 percent (1% ≤ RF ≤ 5%), and less than 1 percent (RF <1%) of either Cs or I to 

47 environment. The category of no release or negligible release is retained for cases where core 

48 damage is arrested within the vessel, and all partial releases are scrubbed. The amount of 

49 release in no release category is generally comparable to that of the fuel gap release plus the 
2-17

1 radioactivity inventory in the primary coolant (it approximately translates into less than 

2 0.01 percent of I or Cs).

3

4 Early and late are defined based on the duration of time between the activation of general 

5 emergency, requiring start of evacuation, and the time of major radioactivity releases. Early 

6 generally reflects a duration of less than 12 hours, and late is defined by a duration greater than 

7 12 hours. Using 12 hours as the threshold is intended to cover the external hazards; therefore, 

8 it is considered to be a conservative value for internal event initiators. For most internal event 

9 initiators in PRA, a value of 8 hours might be more appropriate.

10

11 An example emergency response timeline for the unmitigated long-term SBO (ltsob) sequence

12 (An SBO with failure of TDAFW after batteries are depleted) is shown in Figure 2-2 (Ref. 5).

13 The timing of emergency classification declarations in this figure was based on the emergency 

14 action levels (EALs) contained in site emergency plan implementing procedure at Surry. Surry 

15 was selected as a particular example. Application of this method may be applied to other 

16 nuclear stations with proper consideration of site specific considerations. Note that this 

17 information is intended as an illustration of the general time frames and accident sequence 

18 progression. This sequence triggers EAL SS1.1, which specifies that a site area emergency 

19 (SAE) is declared if all offsite power and all onsite alternating current power is lost for more than 

20 15 minutes. If the restoration of power seems unlikely within 4 hours, EAL SG1.1 requires that 

21 a general emergency be declared. It is, therefore, expected that SAE is declared in about 15 

22 minutes, and plant operators would recognize that restoration of power within 4 hours is unlikely 

23 within the first 2 hours. A period of 2 hours from the loss of power was selected as a 

24 reasonable time for declaration of a general emergency. From the MELCOR analysis, the first 

25 fission product gap release occurs 16 hours into the event. This timing diagram basically 

26 reveals a high likelihood of an effective evacuation during ltsbo sequences.

27
2-18

1

2

3

4

5 Figure 2-2 Unmitigated ltsbo emergency response timeline

6

7 Similarly, the emergency response timeline for the unmitigated short-term SBO (stsbo)

8 sequence (Simultaneous SBO with failure of TDAFW) is shown in Figure 2-3. For this 

9 sequence, SAE is also declared after 15 minutes of SBO since EAL SS1.1 is triggered. In 

10 stsbo, the core is expected to be uncovered in less than an hour and a half with core exit 

11 thermocouple reading in excess of 1,200 degrees F, and the reactor vessel water level lies 

12 below the top of active fuel prompting the declaration of general emergency. From the 

13 MELCOR analysis, the first fission product gap release occurs about 3 hours into the event with 

14 a significant radioactive release through the containment, if no C-SGTR occurs, in 25.5 hours 

15 into the event. This timing diagram basically reveals that there is a high likelihood that an 

16 effective and complete public evacuation may not be possible before some radioactive releases.

17
2-19

1

2

3

4 Figure 2-3 Unmitigated stsbo emergency response timeline

5

6 A simplified LERF model that relies on five factors, similar to what was defined earlier for 

7 C-SGTR because of DBA accidents, was also defined for C-SGTR because of severe 

8 accidents. LERF is estimated by product of these five factors. These factors are defined below:

9

10 (1) frequency of severe accident sequences with potential for C-SGTR fAC

11 (2) C-SGTR probability PCSGTR

12 (3) conditional probability that the subsequent failure of RCS including the stuck open relief 

13 valves do not occur PNDEP

14 (4) failure probability of all SAMG actions PSAMG

15 (5) probability that early effective evacuation is not successful PEVAC

16

17 The above model is used in Section 7 for the representative W and CE plants to make LERF 

18 estimates.

19
2-20

1 2.7 References

2

3 1. U.S. Nuclear Regulatory Commission, “SCDAP/RELAP5 Thermal-Hydraulic Evaluations 

4 of the Potential for Containment Bypass during Extended Station Blackout Severe 

5 Accident Sequences in a Westinghouse Four-Loop PWR,” NUREG/CR-6995, 

6 March 2010. Agencywide Documents Access and Management System (ADAMS) 

7 Accession No. ML101130544.

8 2. Sandia National Laboratories, “Severe Accident Initiated Steam Generator Tube 

9 Ruptures Leading to Containment Bypass-Integrated Risk Assessment,” February 2008, 

10 JCN Y6486.

11 3. Azarm, M.A., et al., “Feasibility Study of Risk Informing Emergency Action Levels of 

12 Fission Product Barriers Using Level 2 PRA,” PSA 2013, Columbia, SC.

13 4. Chen, Falin, “Smoke Propagation in Road Tunnels,” 2000 American Society of 

14 Mechanical Engineers, Vol. 53, No. 8, Institute of Applied Mechanics, National Taiwan 

15 University, August 2000.

16 5. U.S. Nuclear Regulatory Commission, “State-of-the-Art Reactor Consequence Analyses 

17 Project Volume 2: Surry Integrated Analysis,” NUREG/CR-7110, Vol. 2, Rev. 1, 

18 Agencywide Documents Access and Management System (ADAMS) Accession 

19 No. ML13240A242. (The two figures are Figure 6-2 and 6-4 taken from the NUREG/CR, 

20 and supplemented.)

21 6. American Society of Mechanical Engineers, “Standard for Level 1/Large Early Release 

22 Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications,” 

23 ASME/ANS RA-Sa-2009, New York, NY, 2009.

24 7. U.S. Nuclear Regulatory Commission, “An Approach for Using Probabilistic Risk 

25 Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing 

26 Basis,” Regulatory Guide 1.174, Revision 2, May 2011, ADAMS Accession 

27 No. ML100910006.
3-1

1 3. THERMAL HYDRAULIC ANALYSES FOR WESTINGHOUSE AND 

2 COMBUSTION ENGINEERING PLANTS

3

4

5 Thermal hydraulic (TH) analyses were performed to study a Combustion Engineering (CE) 

6 plant’s response to reactor coolant system (RCS) conditions that could lead to consequential 

7 steam generator tube rupture (C-SGTR). The results and insights of Sections 4, 5, and 7 were 

8 generated from the TH sequences associated with SCDAP/RELAP runs reported in 

9 NUREG/CR-6995, “SCDAP/RELAP5 Thermal-Hydraulic Evaluations of the Potential for 

10 Containment Bypass during Extended Station Blackout Severe Accident Sequences in a 

11 Westinghouse Four-Loop PWR,” for the Westinghouse plant, and the MELCOR runs discussed 

12 below for the CE plants.

13

14 This section summarizes the TH work conducted to study thermally induced C-SGTR for 

15 Westinghouse plants, and provides a detailed analysis for CE plants that use replacement 

16 steam generators. The work includes (1) the development of updated CE computation fluid 

17 dynamics (CFD) and MELCOR models, (2) the application of these models on select risk18 significant sequences to evaluate expected TH behavior, (3) the comparison of results against 

19 previous analyses, (4) an uncertainty analysis for the effect of TH parameters, (5) the 

20 generation of TH datafiles in the SGTR probabilistic calculator and finite element (FE) analyses, 

21 (6) the generation of release data in updating the risk contribution from these events, and (7) an 

22 assessment of the effect of instrument tube failures.

23

24 The introduction section contains a description of the TH analysis and lists the previous work on 

25 the subject. The Initial Deck and Analysis section describes Sandia National Laboratories 

26 (SNL) deck generation and summarizes some of their analyses. The CFD Analyses section 

27 describes the CFD analyses and input used for the SNL and U.S. Nuclear Regulatory 

28 Commission (NRC) analyses. The Deck Modifications section describes two stages of deck 

29 modifications made by the NRC, one before the initial set of simulations and one used for the 

30 final set of simulations. The Loop Seal Clearing section describes a conceptual model for loop 

31 seal clearing. The results section summarizes the major simulation results. A conclusions 

32 section provides conclusions and recommendations from the TH work.

33

34 3.1 Introduction

35

36 C-SGTR accidents are of interest because of the potential for fission product releases to the 

37 environment. Reactor designs include containments that reduce releases in the event of an 

38 accident. A containment bypass refers to a situation in which fission products released during 

39 core degradation bypass the containment and thus do not benefit from these reductions. 

40 Fission products that enter the steam generator secondary sides are prevented from reaching 

41 the environment solely by a series of valves the failure of any of which will result in an open path 

42 from the core to the environment.

43

44 There are two general types of C-SGTR sequences: one is a thermally induced (TI) C-SGTR in 

45 which hot gases emanating from the cure during a severe accident cause creep-rupture of 

46 steam generator tubes. The second type of C-SGTR is pressure induced in which a shock from 

47 some event, typically a main steam line break, causes tubes to rupture. This section of the 

48 report deals exclusively with thermally induced consequential steam generator tube rupture.

49
3-2

1 In the TI-CSGTR heat transfer to the tubes by natural circulation results in tube rupture. Figure 

2 3-1 shows the two different forms of severe accident natural circulation flows. The left part of 

3 the diagram shows full-loop natural circulation conditions. Hot gases leaving the core flow 

4 through the HL and are cooled as they pass through the steam generator with the cooled gases 

5 returning to the core through the cold legs. The right part of the diagram shows closed-loop6 seal natural circulation flow. For this situation the water in the loop seal blocks the return flow to 

7 the core. The cooled gases can only return to the core through steam generator tubes and the 

8 HL. For this situation a counter current flow situation exists where hot gases from the core are 

9 flowing to the steam generators through the top of the HLs while cooled gases are returning 

10 through the bottom of the HL. The volumetric flow rate for counter current natural circulation is 

11 lower than that for full-loop natural circulation. Thus, closed loop natural circulation transfers 

12 heat less efficiently to the steam generator (SG) tubes and tube rupture is less likely to occur 

13 under these conditions.

14

15

16

17 Figure 3-1 Severe accident natural circulation flows

18

19 The TH work described in this section deals primarily with closed-loop-seal natural circulation 

20 behavior although open-loop natural circulation behavior is discussed.

21

22 Although SGTRs have previously been considered in risk analyses, TI-C-SGTR have typically 

23 not been considered. In the previous analyses the tube rupture was considered to be the 

24 initiating event. This rupture can lead to a severe accident if corrective actions are not taken in 

25 time. This type of SGTR is a design-basis event for which plants are designed to cope without 

26 progressing to a severe accident. Plants have coped with all SGTRs to date. A C-SGTR differs 

27 from this sequence in that the severe accident causes the tube rupture.

28

29 C-SGTR thermal hydraulic behavior has been studied extensively for Westinghouse plants in 

30 NUREG/CR-6995 (Ref. 2). Some work was performed on CE plants with SCDAP/RELAP but, 

31 having predated the final Westinghouse analysis; it did not incorporate all the modeling 
3-3

1 improvements made for the Westinghouse designs. The Electric Power Research Institute

2 (EPRI) considered CE plants in its 2002 steam-generator-tube-related risk analysis (Ref. 4), 

3 where it was shown that CE plants were more vulnerable to C-SGTR than are Westinghouse 

4 plants during station blackout accidents.

5

6 Because of the capability to predict fission product releases in addition to thermal hydraulic 

7 behavior, the decision was made to switch from SCDAP/RELAP to the MELCOR code to 

8 perform the CE C-SGTR analysis, taking advantage of the lessons-learned during the previous 

9 Westinghouse analyses.

10

11 3.1.1 Summary of Results Obtained in NUREG/CR-6995

12

13 To put the analysis for CE plants in proper perspective, it is useful to include a summary of the 

14 TH results for Westinghouse plants. Below are some pertinent excerpts from the Executive 

15 Summary of NUREG/CR-6995.

16

17 For PWRs with U-tube SGs, the natural circulation of superheated steam in the 

18 loop piping during specific low probability severe accident conditions could result 

19 in sufficient heating of the SG tubes to induce creep rupture failure under certain 

20 scenarios. To support an overall examination of the risk impacts of induced tube 

21 failure, thermal-hydraulic analyses have been performed. The analyses used the 

22 SCDAP/RELAP5 systems analysis computer code, aided by computational fluid 

23 dynamics (CFD) simulations, to examine the pressure and temperature 

24 conditions that challenge the integrity of the reactor coolant system pressure 

25 boundary and to estimate the timing of specific reactor coolant system 

26 component failures.

27

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

29 scenarios in Westinghouse four-loop PWRs. The scenarios that challenge the 

30 tubes primarily involve a counter-current natural circulation flow pattern during 

31 conditions referred to as high-dry-low. The high-dry-low scenario refers to a set 

32 of conditions that includes a high pressure in the reactor coolant system (RCS), a 

33 loss of SG water inventory and a failure to provide a source of feedwater (dry), 

34 and a significant leak from the SG secondary side boundary that results in a low 

35 pressure on the secondary side of the SG tubes. Another condition posing a 

36 challenge to steam generator tubes is associated with full-loop natural circulation 

37 flows that are possible if the water in the loop seal is cleared and the reactor 

38 vessel downcomer is cleared. Based on our recent SCDAP/RELAP5 analysis, 

39 this condition is considered to be much less likely than the condition of counter40 current natural circulation flow.

41

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

43 RCS into the SG secondary coolant system from where it may escape to the 

44 environment through the pressure relief valves. An environmental release in this 

45 manner is called “containment bypass,” which contrasts with releases into the 

46 containment that result from failures of [HL] HL piping, pressurizer surge-line 

47 piping, or the lower head of the RV [reactor vessel]. The potential for steam 

48 generator tube failure by creep rupture and containment bypass under the high49 dry-low conditions is effectively eliminated if (1) the RCS pressure is reduced 

50 because of operator actions to intentionally depressurize the RCS or primary 

51 system leakage (eliminating the high-pressure condition), (2) feedwater flow is 
3-4

1 maintained (eliminating the dry condition and reducing RCS pressure), or (3) the 

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

3 the secondary side).

4

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

6 above and creates a challenging environment for SG tubes. Loop seal clearing 

7 (along with a clearing of the fluid in the RV lower downcomer region) results in a 

8 direct natural circulation path around the coolant loop (RV, HL, SG, cold leg). 

9 Loop seals are more likely to clear when the water in the loop seals is heated 

10 and a rapid depressurization occurs. If loop seals are cleared and full loop 

11 natural circulation is established, the hot steam from the RV challenges the 

12 integrity of the SG tubes.

13

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

15 tubes are predicted to fail prior to the HL or other RCS components, steam and 

16 radioactive fission products (released during core degradation) pass into the SG 

17 secondary system and provide a potential for containment bypass. Predictions 

18 indicate that a HL or other RCS component will fail shortly after a SG tube fails 

19 because the SG tube failures do not immediately depressurize the system. The 

20 subsequent failure of the RCS boundary significantly reduces the rate of mass 

21 flow from the primary system into the SG secondary system. Alternatively, if a 

22 HL or other RCS component of significant size fails prior to an SG tube, the 

23 release of contaminated steam would be completely into the containment 

24 because the resulting rapid RCS depressurization prevents subsequent failures 

25 of SG tubes and the associated containment bypass.

26

27 This report documents the current predictions for system behavior during 

28 extended SBO scenarios. The objective of this report is to combine the four-loop 

29 PWR extended SBO severe accident event sequences that fall into the following 

30 three categories:

31

32 1. sequences resulting in containment bypass.

33

34 2. sequences providing a potential for containment bypass for which an 

35 outcome may be determined by initially comparing the degradation of 

36 tube strengths in a prototype SG against the SCDAP/RELAP5-predicted 

37 tube-failure margins.

38

39 3. sequences not resulting in containment bypass.

40

41 This categorization of event sequences provides information that—when 

42 combined with results from RCS component analyses, probabilistic risk 

43 assessments, and environmental release evaluations—will permit an evaluation 

44 of risks because of containment bypass for Westinghouse four-loop plants.

45

46 A model of a Westinghouse four-loop plant is developed for use with the 

47 SCDAP/RELAP5 thermal-hydraulic system code and employed to perform 

48 simulations of accident-event sequences pertinent for the containment bypass 

49 issue. The SCDAP/RELAP5 code calculates fluid and structure conditions, such 

50 as pressures and temperatures, throughout the regions of a plant model. In 

51 addition, the code includes models for calculating the progression of core 
3-5

1 damage behavior during severe accidents and simplified models for creep 

2 rupture behavior of RCS components. In the Westinghouse four-loop plant 

3 model, creep-rupture behavior is evaluated with SCDAP/RELAP5 to predict 

4 failure times for the HLs, pressurizer surge line, and SG tubes. The creep5 rupture model allows one to specify a “stress multiplier.” A multiplier of 1.0 

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

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

8 degraded structural strengths associated with preexisting tube flaws or 

9 degradation that may exist. A stress multiplier of 2.0, for example, represents a 

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

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

12 undegraded structure. The term “SG tube failure margin” as used in this report 

13 refers to the tube-stress multiplier in the model that results in prediction of SG 

14 tube creep-rupture failure coincident with the earliest failure of another RCS 

15 pressure boundary component, typically a HL. Therefore, tubes with higher 

16 stress multipliers are predicted to be the first RCS pressure-boundary 

17 components to fail, in which case containment bypass occurs. Two SG tube 

18 failure margins—one for the average tube and another for a tube in the hottest 

19 region of the SG—represent the key output from the SCDAP/RELAP5 event 

20 sequence simulations.

21

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

23 using the following criteria based on the SCDAP/RELAP5-predicted hottest SG 

24 tube failure margin:

25

26 • Containment bypass is assumed if the 1.0-stress multiplier (i.e., 

27 undegraded) hottest SG tube is predicted to fail prior to the HL, 

28 pressurizer surge line, or RV.

29

30 • A potential for containment bypass is assumed if the hottest SG tube 

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

32 tube strengths and their distribution resident in a prototype SG are 

33 needed to determine the outcome.

34

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

36 is 3.0 or higher.

37

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

39 Westinghouse four-loop PWRs are summarized as follows.

40

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

42

43 • Event sequences that do not involve secondary side depressurization 

44 (i.e., leakage from the secondary system of 0.64 cm2/SG [0.1 in2/SG] and 

45 smaller) generally do not result in containment bypass. The reduced SG 

46 tube stresses resulting from the SG secondary pressures remaining 

47 elevated prevent SG tubes from failing prior to the HL, surge line, or RV.

48

49 • Event sequences that assume reactor coolant pump (RCP) shaft seal 

50 leakage rates lower than 11.36 L/s [180 gpm] per pump generally provide 
3-6

1 a potential for containment bypass. Event sequences that assume RCP 

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

3 generally do not result in containment bypass. A high leak rate leads to 

4 lower RCS pressures, and the reduced SG tube stresses prevent SG 

5 tubes from failing prior to the HL, surge line, or RV. However, exceptions 

6 exist related to the time when RCP shaft seal failures are assumed to 

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

8 loop seal clearing and, therefore, containment bypass can occur for 

9 leakage rates above 25.23 L/s [400 gpm] per pump.

10

11 • Event sequences in which the TDAFW system operates and continues 

12 operating (or alternate feedwater is available) do not result in containment 

13 bypass. The outer surfaces of the SG tubes remain wet, and the RCS 

14 heat removal provided prevents system heatup.

15

16 For event sequences in which the TDAFW system is assumed to initially operate 

17 and later fail, the likelihood of tube rupture is predicted to be very similar to 

18 scenarios where the TDAFW does not operate at all because eventually, without 

19 other mitigation, the system may reach the high-dry-low condition. However, the 

20 timing of potential tube failures is significantly delayed by the initial operation of 

21 the TDAFW system. Challenges to continued TDAFW operation are a result of 

22 depletion of the station batteries or the depletion of the condensate storage tank 

23 inventory. Probabilistically, additional mitigation should be considered as well as 

24 the likelihood that auxiliary feedwater may not be maintained.

25

26 For situations where the operators take mitigative action:

27

28 • An evaluation was performed for a strategy in which operators implement 

29 SG feed-and-bleed cooling at 30 minutes into the event sequence (using 

30 the TDAFW system and opening the SG PORVs). The evaluation shows 

31 that this strategy is effective in the short term for preventing containment 

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

33 delayed, thereby providing additional time for other plant recovery 

34 opportunities to be considered and implemented. In the long term, the 

35 SG PORVs fail closed when the batteries are depleted, and continued 

36 success of this strategy requires that a TDAFW water source remains 

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

38 For sequences in which the TDAFW system initially operates but later 

39 fails, no large changes in SG tube failure margins (relative to the no40 intervention case) were predicted.

41

42 • An evaluation was also performed for a post-core damage strategy in 

43 which the operators depressurize the RCS by opening one or two 

44 pressurizer PORVs after plant instrumentation indicates that core cooling 

45 is inadequate. PORVs are opened at the time when the core exit 

46 temperature reaches 922 K (1,200 °F) or 12 minutes later. The 

47 evaluation shows that opening only one PORV limits the cooling afforded

48 to the RCS, the core fails early (prior to battery depletion), and 

49 containment bypass is avoided for both operator action times. The 

50 evaluations also show that the greater RCS cooling afforded by opening 

51 two PORVs prevents early core damage and also prevents early failure of 
3-7

1 the HL and SG tube structures. When the PORVs fail closed after battery 

2 depletion, the RCS begins repressurizing and reheating, and this

3 subsequently leads to HL and SG tube failures. The SG tube failure 

4 margins seen for the operator intervention cases are significantly 

5 improved (relative to the no intervention cases), and containment bypass 

6 is seen to be avoided for both of the post-core damage operator action 

7 times.

8

9 3.1.2 CE Plant Considerations

10

11 The increased vulnerability for CE plants with replacement steam generators is primarily 

12 because of a shorter HL length-to-diameter ratio and to shallower SG inlet plena than in 

13 Westinghouse steam generators, resulting in higher temperature gas reaching the steam 

14 generator tubes during closed-loop-seal natural circulation conditions. Consequently, the steam 

15 generator tubes would reach creep-rupture conditions sooner in CE plants, thus increasing the

16 likelihood of containment bypass.

17

18 Several aspects are of interest for the purpose of determining fission product (FP) releases to 

19 the environment: (1) whether a steam generator tube or some other part of the RCS pressure 

20 boundary fails first, (2) whether tube failure results in sufficient and rapid enough RCS 

21 depressurization to prevent rupture of some other part of the RCS boundary, and (3) whether 

22 the containment pressure is higher than the steam generator pressure in the long term, thus 

23 allowing release of revaporized fission products. This last aspect cannot be addressed in an

24 SCDAP/RELAP analysis, but can when using MELCOR. In the Westinghouse analysis the 

25 presence of a flaw was required for the prediction of tube failure before other RCS component 

26 failure. This condition leads to the prediction of failure of a single tube, and a primary system 

27 depressurization rate that is not sufficient to prevent subsequent failure of other RCS 

28 components. For CE designs, however, unflawed tubes exposed to the relatively unmixed hot 

29 gases that reach the SG tubes can also fail. Moreover, more than one tube could fail, 

30 potentially depressurizing the RCS sufficiently to prevent the creep rupture failure of other 

31 components, leaving the containment bypass pathway as the sole release path of FPs from the 

32 reactor.

33

34 The relatively shallow inlet plenum design of the replacement steam generator under 

35 consideration for the CE plant has an effect on the results of the CFD predictions, as shown in 

36 Section 3.3.2 below. The shallow design limits the mixing of the hot gases which enter the 

37 steam generator and creates a higher thermal load on the tubes. The steam generator 

38 considered for the CE plant was a replacement steam generator. One concern is that the 

39 design of replacement steam generators for Westinghouse plants may incorporate a more40 shallow inlet plenum design that would change the predictions made for Westinghouse type 

41 plants. The earlier work on Westinghouse plants focused on the Zion Nuclear Power Plant 

42 (ZNPP) with the associated Westinghouse Model 51 steam generators. To qualify, the 

43 applicability of these Westinghouse predictions for Westinghouse plants with replacement 

44 steam generators, the NRC’s Office of Nuclear Regulatory Research (RES) has worked with the 

45 NRC’s Office of Nuclear Reactor Regulation (NRR) to acquire plant specific inlet plenum design 

46 information from a few plants. Although it was not practical to get design information for as 

47 many plants as desired, three sets of drawings were obtained. These included steam generator 

48 drawings from the Donald C. Cook Nuclear Plant, the Diablo Canyon Power Plant, and Prairie 

49 Island Nuclear Generating Plant. RES staff studied the dimensions for the inlet plenum region 

50 and found what are considered small differences between the new designs and the previously 
3-8

1 studied Model 51 design. No shallow inlet plenum designs were found in the Westinghouse 

2 samples. The expectation is that thermal mixing in the inlet plenums would not be significantly 

3 impacted by the new steam generator designs for the sample plants considered.

4

5 3.2 Initial Deck and Analyses for the CE Plant

6

7 Sandia National Laboratories developed the MELCOR 1.8.6 initial deck used for the C-SGTR 

8 analyses. They exercised the deck on SBO calculations, compared results against those of 

9 previous SCDAP/RELAP analyses, and performed an uncertainty analysis to estimate the 

10 expected contribution to variability in component failure timing resulting from uncertainty or 

11 variability in thermal hydraulic parameters. This work is documented in an SNL report (Ref. 3).

12

13 SNL generated the Calvert Cliffs Nuclear Power Plant deck based upon an earlier less-complex 

14 MELCOR 1.85 demonstration deck and the 2006 SCDAP/RELAP Calvert Cliffs deck used for 

15 prior C-SGTR analyses (Ref. 1). During development SNL exercised the deck on short-term 

16 station blackout (stsbo) analyses using mixing parameters provided from initial CFD analyses. 

17 The SNL deck and analyses did not account for the temperature variability in the hot plume 

18 entering the steam generator tubes so it cannot be used to test the failure of unflawed hottest 

19 tubes. SNL documented the updated deck and the results of the stsbo analysis.

20

21 Sandia compared results from the new deck against those generated using SCDAP/RELAP 

22 (Ref. 1). This comparison required some modifications from the base version to more closely 

23 match the SCDAP/RELAP deck. They found that both codes predicted a similar sequence 

24 behavior and timing although some later events occurred at somewhat different times. The 

25 analysts also found that component failure was not similarly predicted which is not surprising 

26 considering that the hottest tube calculation was not included in the MELCOR analysis.

27

28 SNL performed an uncertainty analysis to estimate the expected contribution to variability in 

29 component failure timing resulting from uncertainty or variability in thermal hydraulic 

30 parameters. The RCS-component-to-tube relative failure timing variation because of expected 

31 variations in TH parameters approximately followed a normal distribution with about a 600 s 

32 standard deviation. Although some aspects of the deck used to generate the failure timing 

33 distributions differ somewhat from the final version the overall system response is not expected 

34 to change significantly. The variability in relative failure timing for the hottest tubes is likewise 

35 expected to be similar to that of the hot average tubes in the plume.

36

37 3.3 Computational Fluid Dynamics

38

39 CFD is used to study the details of the three-dimensional mixing behavior in the primary side of 

40 a CE steam generator. The results are used to inform the system level code of the expected 

41 flow rates and mixing parameters in this region of the reactor system during specific severe 

42 accident sequences. This work builds upon previous NRC studies. Test data are available from 

43 a one-seventh scale facility that provide valuable information on steam generator inlet plenum 

44 mixing and the natural circulation flows during severe accident conditions. These data, 

45 however, are limited to a single Westinghouse type inlet plenum design and there are concerns 

46 related to specific inlet plenum geometry and the scaling of the tube bundle secondary-side heat 

47 transfer. Analyses by the NRC staff, documented in NUREG-1781, “CFD Analysis of 1/7th

48 Scale Steam Generator Inlet Plenum Mixing during a PWR Severe Accident,” demonstrate that 

49 CFD predictions can adequately predict the inlet plenum mixing observed in the one-seventh

50 scale tests. A set of follow-on analyses, documented in NUREG-1788, “CFD Analysis of Full51 Scale Steam Generator Inlet Plenum Mixing during a PWR Severe Accident,” applied the same 
3-9

1 methods to study full-scale steam generators under severe accident conditions. This study 

2 extends the experimental results at one-seventh scale to prototypical conditions and provides 

3 insights into the effect of the steam generator inlet plenum geometry and the potential effect of 

4 the secondary-side heat transfer conditions. After a review of these predictions, the Advisory 

5 Committee on Reactor Safeguards (ACRS) recommended extending the modeling to include a 

6 prediction of the full natural circulation flow path between the vessel upper plenum and the 

7 steam generator. A follow-on study, documented in NUREG-1922, “Computational Fluid 

8 Dynamics Analysis of Natural Circulation Flows in a Pressurized-Water Reactor Loop under 

9 Severe Accident Conditions,” (Ref. 6), addressed this concern and incorporated other modeling 

10 improvements for Westinghouse type steam generators. The current study applies the methods 

11 outlined in NUREG-1922 to a Combustion Engineering type steam generator.

12

13 3.3.1 Summary of NUREG-1922 Results for Westinghouse Plants

14

15 The analysis in NUREG-1922 used an improved CFD model to determine mixing parameters 

16 and coefficients for tuning a system-code model applied to severe accident simulations with 

17 three-dimensional (3D) natural circulation flows. The CFD model used in this study 

18 encompasses a series of lessons learned from several years of analyses including a benchmark 

19 study at one-seventh scale (Ref. 7) and a follow-on study of full-scale steam generators (Ref. 8). 

20 The updated modeling also addresses ACRS comments on those earlier studies (Ref. 9).

21

22 The natural circulation flows between the reactor vessel upper plenum and the steam generator 

23 were predicted under specific severe accident conditions that were obtained from prior 

24 system-code model predictions. A vessel model established the conditions in the upper 

25 plenum, which feeds the natural circulation flows in the HL, pressurizer surge line, and the 

26 primary side of a steam generator. A countercurrent flow pattern is established that carries heat 

27 from the upper plenum to the steam generator tube bundle. An unsteady buoyant plume is 

28 predicted in the inlet plenum as the hot-steam-and-hydrogen mixture rises up and into the tube 

29 bundle. Time-averaged mass flows and temperatures are obtained throughout the system, and 

30 these predictions are used as a numerical experiment to define flow and mixing parameters for 

31 use in tuning a system-code model.

32

33 A modified mixing formulation is established to account for the HL and inlet plenum mixing as 

34 well as the pressurizer surge line flows. This updated formulation is considered to be an 

35 improvement over earlier models that focused solely on the inlet plenum mixing. In addition, a 

36 discharge coefficient is defined that can be used to predict the HL mass flow rates based on the 

37 densities in the vessel upper plenum and the steam generator inlet plenum. The predictions 

38 provide a means of tuning a system code to obtain the mass flows and temperature distribution 

39 in the HL, surge line, and steam generator tube bundle. These predictions can be used to 

40 extend the existing experimental data into the specific steam generator geometry and severe

41 accident conditions studied.

42

43 The recommended system-code modeling parameters for a Westinghouse plant (assumed to 

44 have a Model 51 steam generator) or plant with similar steam generator designs are 

45 summarized below.

46

47 f = 0.96 Mixing fraction

48 r = 2.4 Recirculation ratio

49 41% Hot tube fraction

50 Cd = 0.12 Discharge coefficient

51 Tm = 0.5 Bounding normalized temperature of hottest tube
3-10

1 50 : 50 Hot : Cold flow split ratio into side mounted pressurizer surge line

2

3 Sensitivity studies were completed to provide an estimate of the variation in these parameters 

4 under a variety of conditions and assumptions. In all cases, the discharge coefficient remained 

5 relatively constant with maximum variations of less than 8 percent. This demonstrates the 

6 benefits of using this approach to establish the HL flows in a system-code model. Similarly, the 

7 mixing fraction is found to vary by only a few percent over the range of conditions considered. 

8 The recirculation ratio is found to be sensitive to the secondary-side temperature. Although not 

9 considered in this study, the tube bundle heat-transfer rate was found to affect the recirculation 

10 ratio in previous work (Ref. 8). The temperature and heat-transfer rates in the tube bundle 

11 affect the buoyancy driving forces. These parameters are found to have the largest effect on 

12 the recirculation ratio. The value suggested above, 2.4, is obtained using conditions pulled 

13 directly from a realistic system-code prediction of severe accident conditions in a Westinghouse 

14 pressurized-water reactor (PWR).

15

16 The hot tube fraction is used for sizing the hot and cold steam generator tube sections in a 

17 system-code model. This parameter is difficult to predict with confidence because some of the 

18 tubes at the margin (i.e., tubes at the edge of the hot and cold regions) seem to occasionally 

19 change direction and the hot tube fraction can change by 10 percent or more in a given 

20 analysis. The predictions were not carried out long enough to obtain a consistent long-term 

21 average value. One important finding is that the hottest tube region does not appear to be 

22 significantly affected by changes in the overall size and shape of the hot tube region. In other 

23 words, the core of the hot tube region is somewhat consistent. Changes to the tube flow 

24 patterns occur at the edges of the hot tube region where the temperatures are more moderate. 

25 The base-case prediction had a longtime average hot tube fraction of 0.41. This value is in the 

26 middle of the range of all of the predictions. When the tube bundle flow is significantly 

27 increased, the hot tube fraction apparently tends to approach 0.5. At the lowest tube bundle 

28 flow rates predicted, the hot tube fraction is found to be as low as 0.26.

29

30 The normalized temperature of the hottest tube is a significant parameter because it refers to 

31 the portion of the tube bundle where the thermal loading is most severe. This parameter has 

32 been used in recent NRC studies (Ref. 4) for the purposes of determining whether a tube will fail 

33 before the HL or some other RCS component. In the base-case prediction, the mass-averaged 

34 normalized temperature entering the hottest tube is found to be 0.43. The data sets were 

35 broken down into 40-second intervals, and the study found that the normalized temperature 

36 reached 0.5 over some of these intervals. For this reason, a value of 0.5 is recommended as a 

37 bounding value for system-code models. The sensitivity of this parameter to changes in the 

38 modeling parameters was significant. Average values ranging from 0.36 to 0.47 were obtained. 

39 The most significant variation came from changes in the secondary-side temperatures. A 

40 separate sensitivity study that moved the surge line to the top of the pipe also showed a 

41 significant impact on the hottest tube temperature. The top-mounted surge line removes some 

42 of the hottest flow, and the average normalized temperature of the hottest tube drops to 0.34.

43

44 The flow (hot:cold) split ratio into the surge line pipe is predicted for simulations that included a 

45 pressurizer surge line. This variable remained generally within 5 percent of a 50:50 split ratio 

46 over the range of sensitivity studies, and a 50:50 split ratio is recommended for system-code 

47 models with a side-mounted surge line. The temporal variations in this parameter were very 

48 large and indicated significant turbulent fluctuations at the surge line to HL connection. The 

49 50:50 value represents a long-term average value. The one sensitivity that did significantly 

50 affect this result involved moving the surge line to the top of the HL. In this case, approximately 

51 75 percent of the flow into the surge line came from the hot flow in the upper pipe section. The 
3-11

1 top-mounted surge line therefore is subjected to a larger thermal challenge than a side-mounted 

2 surge line. This could be important in cases where the surge line is predicted to fail before the 

3 HL.

4

5 The series of predictions completed with a range of tube leakages from the primary to 

6 secondary-side help to quantify the significance of tube leakage on the overall natural circulation 

7 flows. A leakage rate of 1.5 kg/s resulted in no significant variation. The countercurrent natural 

8 circulation between the vessel upper plenum and the steam generator is maintained for leakage 

9 rates up to 6 kg/s but, as the leakage rates increase, the average temperature of the flow 

10 entering the tube bundle increases. For a leakage rate of 12 kg/s, the countercurrent flow 

11 pattern is essentially broken and the steam temperatures entering the tube bundle begin to 

12 approach the HL (hot flow) temperatures.

13

14 Some prior qualitative CFD results highlighted that some system-code models will underpredict 

15 the convective heat-transfer rates to critical regions of the HL and surge line. In the regions 

16 where the thermal boundary layer is still developing, the fully developed heat-transfer 

17 correlations used in system codes underpredict the heat-transfer rates. To account for this 

18 underprediction of convective heat transfer, a set of factors are provided that can be used to 

19 adjust the fully developed heat-transfer correlation to account for the local entrance region 

20 effect. These factors, or other data if more appropriate, should be applied in the determination 

21 of the HL and surge line convective heat-transfer rates. In addition to the thermal entrance 

22 effects, it is expected that much of the upper HL also will experience mixed convection that 

23 would further increase the convective heat transfer to the HL. This topic is suggested for future 

24 research if a more detailed analysis of the HL becomes necessary.

25

26 3.3.2 CFD Results for a CE Plant

27

28 A simplified vessel upper plenum and an improved tube bundle are added to the CE steam 

29 generator geometry used in NUREG-1788. The CFD model domain includes the upper plenum 

30 of the reactor vessel, a HL with the surge line junction, the steam generator inlet plenum, and a 

31 simplified tube bundle. Symmetry is assumed at the vertical plane of the HL and steam 

32 generator. The tubes are modeled in a manner similar to that used for the Westinghouse 

33 modeling documented in NUREG-1922. Groups of nine tubes are combined into a single tube 

34 which maintains the appropriate flow area. Loss coefficients and heat transfer enhancements 

35 are added to the tube models to ensure that the tube bundle has the same pressure drop and 

36 heat transfer characteristics as a prototypical steam generator. This method is outlined in 

37 NUREG-1922 for the Westinghouse steam generator. The ANSYS/FLUENT v14.0 CFD code is 

38 used for the analysis. The predictions qualitatively show all of the flow features observed 

39 experimentally in the HL and steam generator regions. Steady boundary conditions are used 

40 that represent a snapshot in time of the severe accident conditions from system-code 

41 predictions of representative severe accident sequences. Average mass flows, temperatures, 

42 and mixing are predicted throughout the flow domain and used to define key parameters that 

43 are used in the one-dimensional system level codes to ensure consistency with the 3D CFD 

44 predictions.

45

46 A discharge coefficient related to a density-based Froude number is used to define the HL flow 

47 rates as a function of the densities in the vessel upper plenum and steam generator inlet 

48 plenum. The approach is outlined in NUREG-1922. The discharge coefficient is predicted to be 

49 in the range from 0.13 to 0.14 for the combustion engineering reactor geometry considered.

50
3-12

1 This study expands the inlet plenum mixing model to include the HL mixing and entrainment as 

2 outlined in NUREG-1922. This updated approach is more consistent with the CFD predictions 

3 and results in a higher mixing fraction and a more realistic estimate of the recirculation ratio. 

4 The mixing fraction is found to be within the range from 0.65 to 0.85 and the recirculation ratio is 

5 found in the range from 1.05 to 1.2.

6

7 Because system-code predictions have shown that the reactor loop with the pressurizer can 

8 have the earliest tube failures under some conditions, it is important to consider the effect of the 

9 flows into the pressurizer surge line. The mass flow into the surge line is accounted for in the 

10 updated mixing model. In addition, the CFD predictions are used to define the mixture of flows 

11 that enter the surge line during periods of countercurrent flow. For top mounted surge lines, the 

12 flow entering the surge line enters mainly from the upper (hot) HL flows and the temperature of 

13 the gas entering the surge line is consistent with these hotter temperatures.

14

15 A key aspect of these predictions is the determination of the tube bundle flows. System-code 

16 models typically use a single representative tube for the hot tube flows and the temperature is a 

17 mass-averaged value for the entire group of tubes carrying the hot flow. With over 1,000 tubes 

18 expected to carry hot flow in a prototypical steam generator during this sequence, a significant 

19 variation in temperature can exist between the highest and lowest temperature tubes. A 

20 normalized temperature is defined to make the results easy to apply under a variety of 

21 conditions. A value of 1.0 represents the temperature of the flow from the vessel upper plenum, 

22 and a value of 0.0 represents the temperature of the flow returning to the inlet plenum through 

23 the cold flow tubes. Tube entrance temperatures fall between 0 and 1 on this scale. The 

24 average normalized temperature of the hottest tube in the bundle is found to be in the range 

25 from 0.9 to 0.99. The total number of tubes that carry the upward hot average flow is found to 

26 be in the range from 20 to 25 percent of the total number of tubes.

27

28 3.3.3 Conclusions from the CFD Analyses

29

30 The ranges of the parameters found are not a measure of the true uncertainty because only a 

31 modest number of cases are considered. The range is provided to give some idea of the 

32 variations observed in the limited number of predictions completed. A summary of the 

33 parameters found is outlined below for Westinghouse and CE steam generators.

34

Parameter Average from 

NUREG-1922 

Westinghouse SG

Predicted range

Combustion Engineering SG

Cd, discharge coefficient 0.12 0.13–0.14

f, mixing fraction 0.96 0.65–0.85

r, recirculation ratio 2.4 1.05–1.20

hot tube fraction 41% 20–25%

Tn, normalized (hottest tube) 0.43 0.9–0.99

35

36 The updated predictions outlined above build upon previous studies and provide an updated set 

37 of parameters for use in one-dimensional system codes to predict three-dimensional natural 

38 circulation flows in pressurized-water reactor loops under severe accident conditions. The 

39 results are specific to the geometry and conditions used in this study and in NUREG-1922, 

40 should not be applied universally. They are used in, and apply to the geometries for, 

41 NUREG/CR-6995 (Ref. 2) and in the CE analysis documented in this report.

42
3-13

1 3.4 Deck Modifications and Modeling Assumptions for the CE Analysis

2

3 The SNL deck was modified to account for the spatial variation in tube temperatures to more 

4 accurately determine tube failure and to apply other lessons-learned from the Westinghouse 

5 analyses during the Steam Generator Action Plan (SGAP) work which included 

6 NUREG/CR-6995. The changes include modifications to tubesheet heat transfer, generation of 

7 alternate methods to calculate the hottest steam generator tube temperatures, modifications to 

8 RCS-to-containment heat transfer, a modification to the HL creep rupture calculation, and 

9 modification of the HL natural circulation modeling to match updated CFD generated mixing 

10 parameters. Minor changes that were required to merge different versions of the decks were 

11 also made.

12

13 The primary modification was the determination of the temperature of the hottest tube and the 

14 inclusion of a method to calculate this temperature within the MELCOR simulations. To reliably 

15 estimate the time of tube failure the nonuniformity of tube temperatures must be considered. 

16 System codes such as MELCOR only provide an average temperature in the hot plume but not 

17 the hottest temperature. Characterizing the effect of the temperature distribution is of particular 

18 concern for CE plants with shallow-inlet-plenum replacement steam generators as even 

19 unflawed tubes in the hottest section of the steam generator are susceptible to failure.

20

21 Some modifications were made to model heat transfer from flowing gases to RCS components. 

22 Because the relative failure timing of SG tubes and other RCS components affects the 

23 occurrence of containment bypass accounting for significant heat transfer mechanisms to RCS 

24 components improves the prediction of containment bypass. Some of the aspects that should 

25 be considered are accounting for radiative heat exchange between the HL wall and the gases 

26 flowing through it and ensuring that significant aspects of heat exchange in the RCS are 

27 accounted for.

28

29 One of the RCS heat transfer modifications made was the restructuring of SG tubesheet heat 

30 structures. These heat structures were originally generated to be in contact with the secondary 

31 side of SGs and with the SG inlet and outlet plena but not with the tubes themselves. Because 

32 the SG tubesheets have far more surface area in contact with, and thus far more heat transfer 

33 with, the outside of tubes than with the secondary side and inlet plena these heat structures 

34 were modified to be in contact with the SG tube fluid rather than the secondary-side and inlet35 plena fluid.

36

37 An attempt was made to determine the relative contributions of radiative and convective heat 

38 transfer, but it was only partially successful. An alternate radiative heat transfer model was 

39 applied to the MELCOR plotfile output to check if it would match that in the output file. The 

40 alternate model was used because details of the MELCOR model were not readily available. 

41 The heat transfer coefficient (HTC) contribution estimates did not match the output file results 

42 very well. The combined HTC was provided for use in the FE analyses. If the increase relative 

43 to fully developed conditions in the hot-leg heat transfer coefficient because of a thinner 

44 boundary layer affects both the convective and radiative heat transfer coefficients equally, then 

45 the distinction between the two need not be made.

46

47 Previous NRC analyses only adjusted the convective HTC for boundary layer effects in the 

48 entrance region (Ref. 2) whereas other analyses adjusted both the convective and radiative 

49 HTCs. If it cannot be established with sufficient confidence that the boundary-layer entrance 

50 effects affect both the radiative and convective heat transfer coefficients equally these boundary 
3-14

1 layer effects (and the separation of radiative and convective HTCs) should be revisited to apply 

2 separate factors to the convective and radiative heat transfer coefficients.

3

4 The modeling of thermal radiation exchange between HL surfaces and gas flowing through the 

5 HL was reviewed and considered to be acceptable for screening purposes. Because the 

6 convective heat transfer modeling in system codes such as MELCOR typically use correlations 

7 applicable for fully developed flow the enhanced heat transfer in entrance regions where 

8 boundary layers are developing, such as at the entrance to the HL—the very location where the 

9 HLs are susceptible to failure, are likely underpredicted. It is for this reason that, if RCS and SG 

10 tube failure timings are similar, a FE calculation should be used to account for this nonuniform 

11 heat transfer.

12

13 No secondary-side relief-valve fail open model was initially considered for the original cases. 

14 However for appreciable fission product releases to occur some secondary-side relief valves 

15 must stay open. Otherwise no pathway (other than potential system leakage) exists for 

16 releases to the environment. Failure models were therefore added to the deck. Two modes of 

17 main steam safety valve (MSSV) failure were originally assumed: that valves may stick open 

18 when they open fully following heatup and thermal expansion; and that valves may fail open 

19 after a fixed amount of cycles. Only the first of the two models was implemented. These failure 

20 modes did not result in predictions of MSSVs sticking open.

21

22 Two additional MSSV failure modes were added after the initial calculations. One is that 

23 MSSVs can fail open after the first opening in the event of a common-cause maintenance 

24 failure. The second is not a failure mode but rather accounts for procedures in which the 

25 secondary relief valves are intentionally opened to reduce pressure so that water can be 

26 pumped in if available.

27

28 The creep rupture modeling for the HLs was also modified for a sensitivity calculation. The 

29 standard creep rupture model for a single-material tube consists of calculating the stress history 

30 in the tube and calculating from this stress history and the material creep properties the 

31 accumulated damage from creep as a function of time. When this accumulated damage history, 

32 referred to as either the creep or damage index, reaches a value of 1 the component is 

33 considered to have failed. The HLs are made up of two layers of material, carbon steel and 

34 stainless steel. The original deck modeled the creep rupture failure of the two-layered HLs as 

35 follows: determine the stress for both whole HL layers together as though it was made of a 

36 single substance. The stresses are expected to be somewhat different in both materials. A 

37 creep rupture index was then calculated for each layer as though the entire wall thickness was 

38 made of that material. The maximum of the two creep rupture indices was then used to 

39 calculate HL failure. This model effectively assumes that the entire HL is made up of the 

40 weaker HL material. If the thicker layer is not made up of this material the HL failure would be 

41 predicted earlier than it should be. Because HL failure before SG tube rupture prevents the 

42 tubes from rupturing the effective assumption of the entire HL being made of the weaker 

43 material (maximum index) could make the difference between containment bypass and no 

44 containment bypass. It could be that the decision to use the minimum-creep-strength material 

45 was made with the knowledge that the thick layer in the HL was made of this weaker material. 

46 Unfortunately a detailed justification for the use of the maximum was also not described in 

47 detail. The potentially nonconservative model was therefore changed to instead use the 

48 minimum of the two materials’ creep rupture indices to assess the potential impact. This 

49 change results in an effective assumption that the entire HL is made of the stronger material. 

50 While this is not ideal it avoids a potential major nonconservatism in containment bypass 

51 calculations. This change delayed the HL failure time by nearly 21⁄2 hours. It would be 
3-15

1 preferable to find or develop a model that accounts for the different stresses in the materials 

2 perhaps even accounting for the different thermal expansions of the materials, find a justification 

3 for omitting the thin-layered material, or to use FE analyses.

4

5 A choice had to be made for the number of unflawed tubes that fail because the creep failure 

6 model does not predict this and a model has not been developed to estimate this parameter. 

7 The failure of a flawed tube is assumed to result in the failure of the single tube. Multiple tubes 

8 can fail near-simultaneously, however, if unflawed tubes reach failure conditions. The number 

9 of tubes that fail depend on the shape of the spatial temperature distribution in the hottest part 

10 of the SG tube, the variability in strength because of manufacturing or flaws, and the 

11 depressurization of the system that occurs as the initial tubes start failing. Expert elicitation of 

12 NRC staff members previously involved in the issue resulted in a range from 10 to 100 tubes 

13 failing. For the MELCOR simulations a value of 20 unflawed tubes were assumed to fail upon 

14 prediction of creep rupture. A single tube failure was assumed for the average--hot (flawed) 

15 tube. The MELCOR analysis assumptions and conclusions regarding the tube failure are not 

16 used in the PRA analysis of Section 7.

17

18 The number of tubes that fail does not directly affect RCS component failure beyond the point at 

19 which depressurization time becomes much shorter than the tube-to-other-RCS-component 

20 creep rupture time for a situation where SG tubes fail first. Although this number was not 

21 identified it can vary depending on conditions the failure of 20 tubes is generally sufficient under 

22 the conditions modeled.

23

24 It should be noted that this is a simplified model that does not account for the factors considered 

25 by the PRA analysis described in Chapter 7. The MELCOR conclusions regarding tube failure 

26 are not used in the PRA analysis. Only the TH (pressure and temperature profiles as a function 

27 of time) in the progression of an accident sequence studied in MELCOR are used in Section 7. 

28 Using TH for failure modeling in the PRA is further discussed in Section 7.2.1.

29

30 These modifications were originally made to an earlier version of the SNL Calvert Cliffs 

31 MELCOR deck. These modifications were later merged with the final version of the SNL deck.

32

33 An early set of runs was made using these selected TH results for use as initial and boundary 

34 conditions for the finite-element and SG-calculator calculations of RCS component failure. 

35 These calculations are discussed in Chapter 4.

36

37 Other changes to the plant model were made after further review of results. These changes 

38 consist of modifications to HL natural circulation modeling during reconciliation of differences 

39 RCS flows between MELCOR and the previous SCDAP/RELAP simulations. The changes 

40 consist of modifications to HL natural circulation modeling to be consistent with the CFD results, 

41 and further changes to the MSSV fail-open model.

42

43 Two separate modifications were made to HL natural circulation models, one that consisted of 

44 stabilizing an existing active control method and a second, new, method that consists of a 

45 reformulation of the Froude based relationship to a standard friction form and determining an 

46 effective loss coefficient that represent counter-current flow losses. Both methods produced 

47 stable velocities consistent with those determined from the CFD and Froude number based 

48 velocities and those of the previous SCDAP/RELAP runs. After testing the new friction-based 

49 formulation was chosen for continued use.

50
3-16

1 3.5 Loop Seal Clearing

2

3 One of the issues not fully addressed in the analyses is loop seal clearing. Although limitations 

4 in the deck did not allow this topic to be addressed within the simulation, a conceptual model 

5 was developed to aid in understanding the phenomena. It is based on a consideration of the 

6 loop seal bubble behavior to determine the loop seal clearing behavior.

7

8 Loop seal clearing was covered during the work for NUREG/CR-6995 (Ref. 2). The issue had 

9 also been covered previously.

10

11 Loop seal clearing can result in significant consequences compared to those of closed-loop-seal 

12 natural circulation. Loop seal clearing results in the development of full-loop natural circulation. 

13 This reduces the mixing of hot gases before it enters the tubesheet. For sequences where 

14 closed-loop-seal natural circulation would already result in tube failure a cleared loop seal 

15 condition would advance the predicted tube failure time. For sequences in which tubes would 

16 not be predicted to rupture under closed-loop-seal natural circulation conditions, clearing of a 

17 loop seal may result in steam generator tube rupture. Previous analyses have concluded that 

18 unflawed, and therefore multiple tubes are susceptible to rupture under open-loop-seal natural 

19 circulation.

20

21 The conceptual model for loop seal clearing is depicted in Figure 3-2. The system is considered 

22 as two different sized manometers at different elevations coupled on both ends. The bubble 

23 regions are considered to consist of vapor and potentially noncondensables. A heat source at 

24 one end represents the reactor core. The bubble at the other end represents the gas in the 

25 steam generator outlet plenum. The core bubble and steam-generator bubble are considered to 

26 be connected. The center bubble between the two manometers represents the cold leg bubble. 

27 Some limited flow area between the core region and the center cold leg bubble represents core 

28 bypass leakage. Heat transfer is considered to be possible from the core to the cold leg bubble 

29 across the downcomer. Heat losses are also considered from the cold leg to the environment. 

30 The term HT in the figure refers to heat transfer with net heat flow either into or out of the cold 

31 leg bubble.

32

33 The term “loop seal” in this section without a further description is used to describe the 

34 steam-generator-to-cold-leg loop seal.

35

36 The loop seal behavior is considered by focusing on the behavior of the lower (cold-leg) bubble 

37 between the two loop seals. The primary considered mechanism of clearing occurs when this 

38 bubble size decreases to the point that the loop seal water level rises to the bottom of the cold 

39 leg. At this point the cold leg behaves like a siphon, even if only partially liquid-filled, allowing 

40 water to flow from the loop seal to the downcomer until gases can pass the loop seal. At this 

41 point, the loop seal is considered to be cleared. If the net bubble growth rate is negative the 

42 water level will eventually rise to the point that it crosses over the HL to the downcomer if the 

43 downcomer seal does not somehow clear first.

44

45 Side-to-side liquid motion or bubble compression and expansion that can occur during 

46 perturbations, such as power-operated relief valve (PORV) openings, are considered to affect 

47 the clearing timing somewhat but that overall loop seal clearing behavior, including whether the 

48 seal clears or not, should be largely determined by the net bubble growth behavior.

49
3-17

1

2

3 Figure 3-2 Conceptual model of loop seal clearing

4

5 The following bubble mass sources and sinks are considered to contribute to the bubble growth 

6 rate and thus the loop seal clearing behavior:

7

8 • leakage from the system through pump seal leaks

9 • leakage into the system by core bypass leakage

10 • condensation of bubble vapors by heat transfer to the containment through RCS piping

11 • evaporation of downcomer-to-core loop seal water by heat transfer from the hot core 

12 barrel

13

14 An equation that describes the bubble growth rate is:

15

16 Dm_bubble/dt = leak in – leak out + evaporation rate – condensation rate

17

18 Relevant mass flow rates that affect loop seal clearing are shown in Figure 3-3. This figure 

19 shows the cumulative downcomer-to-upper-vessel flows, each of the pump seal flows, and the 

20 net mass flow rate of the two combined. The remainder (i.e., the difference of the plotted net 

21 from 0) is expected to be made up of phase change in the bubble region, rate of change of 

22 bubble size, flow across cleared upper (standard) or lower (downcomer-to-core) loop seals, or 

23 some combination of the three.

24

25 In the absence of bypass leakage a nonheated vapor bubble would collapse because of heat 

26 transfer through the RCS to the containment. Heat transfer from the core barrel to the 

27 downcomer may result in evaporation countering bubble collapse.

28
3-18

1

2

3 Figure 3-3 Pertinent flows for loop seal clearing

4

5 A downcomer-to-core seal clearing event involves a sufficient level change that the seal is 

6 expected to allow gases to bubble through the downcomer-to-core loop seal before the water 

7 level rises to the cold leg. These gases transferring from the core region can replenish the loop 

8 seal bubble. This would be a transient and not a permanent clearing. Gas reaching the loop 

9 seal bubble through the downcomer could possibly result in a drop of downcomer water level 

10 and resealing the downcomer-to-core loop seal.

11

12 Such transient clearing, if loop seal water inventory is insufficient to rise to cold leg without 

13 gases passing through, can also occur for the loop seal depending on geometry.

14

15 If sufficient leakage exists between both manometer bubbles (i.e., bypass leakage in the 

16 reactor) vapor can flow through the leak path to preserve the loop seal bubble or create a loop 

17 seal bubble if it does not already exist.

18

19 Loop seal water level changes alter the pressure drop between the two gas regions. If the 

20 pressure drop is less than the head of water required to reach the cold leg, the water level will

21 not reach the cold leg, will stabilize at a lower level, and the loop seal will not clear.

22

23 Previous SCDAP/RELAP results show significant cooling of the loop seal water after about 

24 8,000 seconds into the transient. Because of this it is likely that, instead of forming a bubble, 

25 the steam will rapidly collapse and heat the water in the cold leg. Noncondensables could get 

26 trapped in the void region if this occurs before the seal is cleared. Despite the fact that that the 

27 loop seal liquid appears to be cooling the liquid level in the loop seal continues to decrease.

28

29 To summarize, in the absence of noncondensables and leaks, the bubble is expected to:

30

31 • Collapse (clear loop seal) if heat transfer out is greater than heat transfer in.

32 • Not collapse if heat transfer out is less than heat transfer in.

33
3-19

1 Other expected behavior includes:

2

3 • Bubble will not collapse without net out leakage if sufficient noncondensables present.

4

5 • Leak out (pump seal leakage) accelerates bubble collapse.

6

7 • Leak in from upper vessel through core bypass counters bubble collapse.

8

9 • If the bubble shrinks (i.e., dm/dt < 0), then one of three things will happen depending on 

10 system geometry and liquid inventory in both loop seals:

11

12 – Either the cold leg loop seal will clear, or

13

14 – The core-to-downcomer loop seal will clear, or

15

16 – The pressure difference will sufficiently change parameters (leaks and 

17 evaporation) such that a steady state is reached (i.e., dm/dt = 0).

18

19 Both loop seals shown in Figure 3-2 for an individual RCS loop must clear for open-loop-seal 

20 natural circulation to occur.

21

22 If the lower downcomer-to-core loop seal is cleared it is not expected that perturbations such as 

23 PORV openings would be sufficient to clear the loop seal as similar pressure drops will occur on 

24 both sides of the loop seal.

25

26 If the loop seal clears first the downcomer-to-core loop seal may subsequently clear by 

27 reduction in water level through evaporation.

28

29 3.6 Analysis results

30

31 3.6.1 Discussion of MELCOR Analyses

32

33 Two sets of simulations were conducted, one in October 2012 and another conducted in 2013. 

34 The 2013 set of simulations was run because HL flow rates in MELCOR under natural 

35 circulation for the October runs were found to be higher than those of the FLUENT and 

36 SCDAP/RELAP simulations. Higher hot-leg velocities prefer tube over HL failure. To properly 

37 characterize component failure timing it is essential that the HL flow rates be representative. 

38 Additional review indicated that the HL natural circulation modeling in the MELCOR deck 

39 needed to be modified to match updated FLUENT results.

40

41 The 2013 runs used the updated HL natural circulation modeling. The primary difference 

42 between the 2013 and 2012 runs is this modeling change. A second difference is that no 

43 secondary SG leakage to containment was assumed for most of the 2013 runs. Instead 

44 updated MSSV stick-open modeling, the third difference, was relied upon to establish 

45 secondary-side pressure. The change to no secondary leakage and updated MSSV stick-open 

46 modeling was made because of the finding that even 20 tubes assuming to rupture occurred at 

47 low pressure was not sufficient to fully open the MSSVs, which was the original simulated 

48 criterion for sticking to occur. Some of the MSSVs did partially open.

49

50 Plots and tabulations of select results are provided in Section 3.6.3.
3-20

1

2 Although a single case was desired, other cases had to be run to address behavior that had not 

3 previously been considered. A notable parameter that led to the requirement of more runs was 

4 the effect of sticking assumptions for secondary-side relief valves. Assumptions about 

5 secondary-side relief valves failing open, which was not a parameter originally focused on, was 

6 found to be a major parameter in system behavior. This was the case because previous 

7 analyses did not model secondary relief valve behavior but assumed that a bypass would occur 

8 if SG tubes failed or some fraction of the time that the tubes failed. It was found that if valve 

9 failure was not explicitly modeled as an assumption no appreciable releases would occur even if 

10 SG tubes had ruptured. The simulations had to be run repeatedly to come up with relief valve 

11 behavior that resulted in releases to the environment:

12

13 • assuming failure upon full valve opening following a tube rupture did not change 

14 releases as the valves did not fully open and thus did not stick

15

16 • assuming a stick-open-failure upon full valve opening at any time also did not result in 

17 appreciable releases because, even for those cases, the valves did not stick open

18

19 • assuming that secondary-side relief valves stick as far as they have opened or assuming 

20 that they are opened by operators did result in releases

21

22 It appears that the secondary-side valves are not as pressure stressed when the tubes rupture 

23 several hours into the accident so they do not leak. They may be thermally stressed, which is 

24 not considered for the valve-opening model.

25

26 The valve failure criteria were varied, not based on failure data, but rather to evaluate the 

27 possible failure criteria that would possibly result in fission product releases to the environment. 

28 During the analyses for the SGAP tube failure was the criterion used to consider that 

29 containment had been bypassed. The initial CE simulations indicated that, if tubes failed while 

30 the steam generator secondary side was depressurized, the secondary-side relief valve opened 

31 for a short period before closing (if they opened at all) resulting in a small amount of fission 

32 product releases to the environment. This behavior may be scenario dependent.

33

34 The base sequence consisted of a long term station blackout with the turbine-driven auxiliary 

35 feed water system (TDAFW) and batteries assumed to be operating for 4 hours. The initial 

36 cases assumed a secondary-side-to-containment leakage to ensure that the SG secondary 

37 sides were at low pressure. This approach for reducing SG secondary pressure has not been 

38 universally accepted. Cases with no SG-secondary-to-containment leakage were run using an 

39 MSSV stick-open model in which the valves were assumed to stick to the extent they had been 

40 predicted to open by the code. A situation in which operators open the secondary-side-relief 

41 valves soon after the accident to reduce SG secondary pressure to allow water to be pumped in 

42 was also simulated.

43

44 Case run times were set based on the primary need to evaluate the thermal hydraulic system 

45 behavior. Because of this some of the cases terminated before parts of the release occurred. 

46 Therefore the release fractions listed in this table do not represent the total release fraction but 

47 the release fraction at the time of problem termination. On the other hand, the SG 

48 secondary-side decontamination determined from the Aerosol Trapping in Steam Generator 

49 (ARTIST) project was not included which would reduce predicted releases. This 

50 decontamination would be expected to reduce release potentially by about a factor of 5. This 

51 decontamination factor cannot be directly applied to the result because the decontamination is 
3-21

1 particle size dependent and because the decontamination would replace and not add to the 

2 steam generator decontamination already calculated by MELCOR during the run.

3

4 Two of the 2013 cases are considered representative although results are very different. Both 

5 cases use the updated natural circulation modeling. The difference between the -a case is 

6 otherwise identical to the base case. For the -as, case the secondary-side-to-containment 

7 leakage shut off and the MSSVs are assumed to stick open as far as they have been predicted 

8 to open by the code.

9

10 Whether the MSSV was assumed to stick open and whether SG secondary was assumed to 

11 leak to containment resulted in very different behavior. MELCOR predicted HL failure first and 

12 no environmental releases for the case with SG secondary-to-containment leakage and no 

13 MSSV sticking model. For the case with the SG secondary-to-containment leakage and no 

14 MSSV sticking model the tubes were predicted to fail first with calculations predicting FP 

15 releases to the environment.

16

17 The long-term SBO (ltsbo) case with no secondary-side-to-containment leakage and sticking 

18 MSSVs had a Cs release of about 5 percent at the time the run terminated. This was the 

19 highest release of all run cases by far. For this sequence FPs were being released at a 

20 significant rate at the end of the simulation so the actual predicted release fraction (RF) will be 

21 higher if the simulation is extended. To obtain the code-calculated RFs for the cases in 

22 question the simulations would have to be run until the RFs reached their asymptotic values or 

23 to at least beyond the longest time before which mitigative actions could be estimated to occur 

24 in risk analyses.

25

26 Some of the sequences stopped upon reflood when a smaller time step would be required for 

27 stability. Because the primary purpose of the runs was to obtain the TH histories the cases 

28 were not rerun if sufficient data was output to characterize TH behavior.

29

30 Other cases were run as needed to characterize unexpected behavior. These included cases to 

31 establish a suitable secondary-side-relief-valve failure model, to assess the importance of 

32 parameters, and for somewhat different sequences which address additional issues that were 

33 raised.

34

35 One of these was the high-dry-high sequence (high primary pressure, dry secondary side, high 

36 secondary pressure). This involved no SG-secondary-to containment leakage. Although an 

37 MSSV stick-open model was used that would predict sticking if valves fully opened they did not 

38 do so. Even for higher-than-CFD-calculated HL flows, little damage occurred to tubes by the 

39 time the HLs failed.

40

41 A discussion of melting temperatures and steel oxidation is added as an appendix (Appendix I) 

42 to this report.

43

44 A discussion of loop seal clearing considerations is provided in Appendix J, both from a 

45 MELCOR modeling and from a PRA modeling point of view.

46

47 3.6.2 Summary of Accident Sequences Studied and Nomenclature

48

49 This section summarizes the accident sequences modeled and analyzed by MELCOR. It also 

50 provides the nomenclature that is later used in the PRA Section 7.2. The TH results from 

51 selected cases are used as input for the for the PRA analysis.
3-22

1

2 Inventory of CE MELCOR Runs considered for the PRA are given in Table 3-3. Twelve cases 

3 were considered for the PRA. The base sequence being modeled (stsbo) is a high-pressure 

4 station blackout with the following conditions:

5

6 • All emergency core cooling systems fail.

7

8 • TDAFW fails.

9

10 • Accumulators are operable.

11

12 • DC power functions for 4 hours.

13

• 3.23 square centimeters (cm2

) (0.5 square inches [in.

2 14 ]) leak in SG secondary side.

15

• 0.085505 cm2 (0.01325 in.

2 16 ) leak in loop seals (results in a 79.5 liters per minute

17 [21 gallons per minute] leak of water at high (SRV-setpoint) P).

18

19 • Creep failure of AvgHot tube, which represents failure of a single flawed tube, is 

20 assumed to result in the opening of a flow area equal to a DEGB of 1 tube (i.e., 2 tube 

21 flow areas).

22

23 • Creep failure of the hottest tube, which represents failure of unflawed tubes, results in 

24 the opening of a flow area equal to a DEGB of 20 tubes (40 tube flow areas).

25

26 For the equivalent ltsbo case, the TDAFW system functions for 4 hours.

27

28 Figure 3-4 shows the cases that were run. They are separated into two groups: the top group 

29 represents the original October 2012 cases and the bottom group represents the July 2013 

cases that included modifications to the HL natural circulation modeling.1 30 The arrows from each 

31 deck point to its derivative decks. The smaller text indicates the deck files that were altered 

32 from the source deck.

33

 1 The stsbo-mssvstick model was run in 2013 and incorporated the alternate natural circulation modeling with a low 

effective counter-current-flow loss coefficient (which then results in a higher flow rate during closed-loop-seal 

natural circulation.)
3-23

1

2

3 Figure 3-4 Organization of CSGTR decks

4

5 October 2012 cases:

6

7 • stsbo base deck

8 • ltsbo the stsbo deck with TDAFW functioning for 4 hours and a longer run time. 

9 • Modified versions of the stsbo and ltsbo cases:

10

11 – –SCF runs have creep failure suppressed.

12

13 – –MSSV1F runs modify the corresponding case with failure of MSSV assumed if 

14 they open fully following an SGTR event.

15

16 – –noSGleak runs modify the corresponding case by removing secondary leakage. 

17 This modification provides the high-dry-high scenario (high secondary pressure 

18 in addition to high primary pressure and dry secondary) if secondary-side relief 

19 valves are assumed to not stick open.

20

21 – –noSGleak-MSSV1F runs modify the corresponding case by applying both no 

22 secondary-side leakage and stick open valve after full opening of secondary 

23 valve.

24

25 – –noSGleak-MSSV1F-minHLC same as -noSGleak-MSSV1F but using the 

26 minimum rather than the maximum of the two HL creep rupture indices to predict 

27 failure. No ltsbo case was run.

28
3-24

1 – -sidecalcbc Original hottest tube calculation method. This method was replaced 

2 and results for it are not included in this document.

3

4 2013 cases: The second set of cases consisted of additional modifications to the original input 

5 decks:

6

7 • -fixnc - Multiple stsbo decks with modified natural circulation modeling methods

8

9 • -altnc - Multiple stsbo decks with an alternate natural circulation model. The only 

10 difference between the different versions of this deck is that the effective counter-current 

11 loss coefficient is being numerically solved for. Versions 1–9 represent different stages 

12 in the iteration

13

14 • -MSSVstick Addition of MSSV sticking model for which valves open along with using a 

15 low-resistance counter-current-flow loss coefficient using the alternative HL natural 

16 circulation modeling. No ltsbo case was run

17

18 • -a This is the base deck with altered hot-leg natural circulation modeling. It is the -altnc 

19 deck which uses the “converged” counter-current-flow loss coefficient model so that HL

20 flow matches that predicted by the FLUENT CFD code (-altnc3)

21

22 • -as This is the -a alternate natural circulation deck with the secondary-to-containment 

23 leakage area closed and MSSVs sticking open as far as the code has predicted that they 

24 open. This MSSV sticking model can represent either a common-mode maintenance 

25 failure where the valves stick or operator action to open the valves

26

27 • -ao This is the -a alternate natural circulation deck with the secondary-to-containment 

28 leakage area closed and full opening of secondary PORVs and MSSVs soon after the 

29 station blackout. This simulates operator action to reduce secondary pressure. No ltsbo

30 case was run

31

32 • -as-SCF This is the -as case with component failure suppressed

33

34 An additional –a-SCF (the –a case with component failure suppressed) was run upon request 

35 following the other analyses solely for the purpose of providing input for the C-SGTR calculator. 

36 The results for this case were not processed other than providing data for the calculator.

37

38 3.6.3 Select CE Sequence Results

39

40 Code results have been plotted for select cases. The output parameters presented include 

41 system pressures; structure temperatures, select RCS component creep rupture indices, liquid 

42 levels, and gas concentrations. Select events are listed. Creep rupture indices for the average 

43 tubes were also plotted for each case for stress multipliers ranging from 1 to 2.5.

44

45 The timings of some of the major events are shown for select sequences in Table 3-1. The 

46 cases are ordered by time of initial gap release. Major features of the accident progression are 

47 discussed below.

48
3-25

1 Table 3-1 Timing of Selected Events

2

Time (hr)

Event stsbo-as stsbo-ao stsbo-a stsbo ltsbo-a ltsbo ltsbo-as

Station Black Out 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Loss of TDAFW 0.0 0.0 0.0 0.0 4.0 4.0 4.0

ST Rupture Disk 1.8 1.6 2.1 2.1 9.1 9.0 14.1

Initial Gap Release 4.1 4.3 5.1 6.0 12.7 13.6 19.4

SG Tube Rupture 4.4 4.7 - 6.3 - 13.7 19.8

HL Rupture - - 5.9 7.2 13.2 14.7 -

Accumulator 

injection 4.7 0.1 5.9 7.3 13.2 14.7 1.7

3

4 The original stsbo base case will be used as the reference case since all subsequent runs were 

5 compared against it. Some notable differences in other cases are also shown. The figures are 

6 listed first as the chronological walkthrough below covers all cases simultaneously.

7

8 Several figures for the base case are provided: Figure 3-5 shows the main system pressures 

9 for the stsbo calculation. These pressures include primary system pressure, steam generator A 

10 and B secondary-side pressures, and containment pressure. Figure 3-6 shows the SG 

11 secondary collapsed liquid level for the stsbo calculation. Figure 3-7 shows the main structure 

12 temperatures for the stsbo calculation. Figure 3-8 shows the creep rupture indices for the stsbo

13 calculation. Failures calculated with these components affected the accident sequence and 

14 subsequent TH behavior. Figure 3-9 shows the creep rupture indices for various stress 

15 multipliers on the hot-average tubes for the stsbo calculation. These indices were only 

16 evaluated to obtain an indication of the flaw size that would be necessary to cause a failure and 

17 did not otherwise affect results. That is to say that these failure predictions did not influence 

18 subsequent thermal hydraulic behavior. Figure 3-10 shows the hydrogen concentrations in 

19 different location in the steam generator A tubes for the stsbo calculation. Figure 3-11 shows 

20 the volatile fission product release fractions for the stsbo calculation.

21

22 A smaller set of figures are provided for the original ltsbo case. This set of figures includes 

23 pressures, SG water levels, and structure temperatures, along with direct comparisons of these 

24 pressures and structure temperatures to those of the stsbo calculation. These calculations 

25 demonstrate that the ltsbo calculation can be reasonably approximated by a time-shifted stsbo

26 calculation.

27

28 Figure 3-12 shows the main pressures for the ltsbo calculation. Figure 3-13 shows the SG 

29 secondary collapsed liquid level for the ltsbo calculation. Figure 3-14 shows the main structure 

30 temperatures for the ltsbo calculation. Figure 3-15 compares the main pressures in the ltsbo

31 calculation to those of the stsbo calculation. Figure 3-16 compares the ltsbo calculation SG 

32 secondary-side collapsed liquid levels to those of the stsbo calculation. Figure 3-17 compares 

33 the ltsbo calculation loop A structure temperatures to those of the stsbo calculation. Figure 3-18

34 compares the ltsbo calculation loop B structure temperatures to those of the stsbo calculation.

35
3-26

1

2

3 Figure 3-5 Main pressures for the stsbo calculation

4

5

6

7 Figure 3-6 SG secondary collapsed liquid level for the stsbo calculation

8
3-27

1

2

3 Figure 3-7 Main structure temperatures for the stsbo calculation

4

5

6

7 Figure 3-8 Creep rupture indices for the stsbo calculation

8
3-28

1

2

3 Figure 3-9 HotAve tube creep rupture indices for the stsbo calculation

4

5

6

7 Figure 3-10 Hydrogen concentrations in SGA tubes for the stsbo calculation

8
3-29

1

2

3 Figure 3-11 Volatile fission product release fractions for the stsbo calculation

4

5

6

7 Figure 3-12 Main pressures for the ltsbo calculation

8
3-30

1

2

3 Figure 3-13 SG secondary collapsed liquid level for the ltsbo calculation

4

5

6

7 Figure 3-14 Main structure temperatures for the ltsbo calculation

8
3-31

1

2

3 Figure 3-15 Comparison of ltsbo pressures to those of stsbo

4

5

6

7 Figure 3-16 Comparison of ltsbo SG boiler collapsed liquid levels to those of stsbo

8
3-32

1

2

3 Figure 3-17 Comparison of ltsbo loop A structure temperatures to those of stsbo

4

5

6

7 Figure 3-18 Comparison of ltsbo loop B structure temperatures to those of stsbo

8
3-33

1 A full set of figures are provided for the ltsbo-a case because this is the case that experienced 

2 the highest releases before the calculation terminated. Figure 3-19 shows the main system 

3 pressures for the ltsbo-a calculation. Figure 3-20 shows the SG secondary collapsed liquid 

4 level for the ltsbo-a calculation. Figure 3-21 shows the main structure temperatures for the 

5 ltsbo-a calculation. Figure 3-22 shows the creep rupture indices for the ltsbo-a calculation. 

6 Figure 3-23 shows the creep rupture indices for various stress multipliers on the hot-average 

7 tubes for the ltsbo-a calculation. These were only evaluated to obtain an indication of the flaw 

8 size that would be necessary to cause a failure. That is to say that these failure predictions 

9 were not made to influence subsequent thermal hydraulic behavior. Figure 3-24 shows the 

10 hydrogen concentrations in different location in the steam generator A tubes for the ltsbo-a

11 calculation. Figure 3-25 shows the volatile fission product release fractions for the ltsbo-a

12 calculation.

13

14

15

16 Figure 3-19 Main pressures for the ltsbo-as calculation

17

18 For other cases in the newer set of calculations only the system pressures and volatile fission 

19 product releases are provided. Figure 3-26 shows the main pressures for the stsbo-a

20 calculation. Figure 3-27 shows the volatile fission product release fractions for the stsbo-a

21 calculation. Figure 3-28 shows the main pressures for the ltsbo-a calculation. Figure 3-29

22 shows the volatile fission product release fractions for the ltsbo-a calculation. Figure 3-30

23 shows the main pressures for the stsbo-as calculation. Figure 3-31 shows the volatile fission 

24 product release fractions for the stsbo-as calculation. Figure 3-32 shows the main pressures for 

25 the stsbo-ao calculation. Figure 3-33 shows the volatile fission product release fractions for the 

26 stsbo-ao calculation.

27

28 This set of figures provides a fairly complete indication of results for the second set of 

29 simulations when considering the similarities in system behavior from case to case.

30
3-34

1

2

3 Figure 3-20 SG secondary collapsed liquid level for the ltsbo-as calculation

4

5

6

7 Figure 3-21 Main structure temperatures for the ltsbo-as calculation

8
3-35

1

2

3 Figure 3-22 Creep rupture indices for the ltsbo-as calculation

4

5

6

7 Figure 3-23 HotAve tube creep rupture indices for the ltsbo-as calculation

8
3-36

1

2

3 Figure 3-24 Hydrogen concentrations in SGA tubes for the ltsbo-as calculation

4

5

6

7 Figure 3-25 Volatile fission product release fractions for the ltsbo-as calculation

8
3-37

1

2

3 Figure 3-26 Main pressures for the stsbo-a calculation

4

5

6

7 Figure 3-27 Volatile fission product release fractions for the stsbo-a calculation

8
3-38

1

2

3 Figure 3-28 Main pressures for the ltsbo-a calculation

4

5

6

7 Figure 3-29 Volatile fission product release fractions for the ltsbo-a calculation

8
3-39

1

2

3 Figure 3-30 Main pressures for the stsbo-as calculation

4

5

6

7 Figure 3-31 Volatile fission product release fractions for the stsbo-as calculation

8
3-40

1

2 Figure 3-32 Main pressures for the stsbo-ao calculation

3

4

5

6

7

8 Figure 3-33 Volatile fission product release fractions for the stsbo-ao calculation

9

10

11

12
3-41

1 All simulated accident sequences start with a station blackout, which includes a loss of offsite 

2 power and a failure of emergency generators to start. The reactor and equipment is assumed to 

3 successfully trip. Valves including main steam isolation valves (MSIVs) are assumed to close 

4 as planned. For some scenarios the TDAFW was assumed to fail to start. Batteries are 

5 assumed to deplete at 4 hours. For others the TDAFW was assumed to continue operating until 

6 assumed battery depletion at 4 hours. Scenarios for which the TDAFW was assumed to fail to 

7 start are referred to as short-term station blackout (stsbo). Scenarios for which the TDAFW was 

8 assumed to remain functional until batter depletion are referred to as long-term station blackout 

9 (ltsbo).

10

11 The loss of reactor power coupled with the continued removal of heat by the steam generator 

12 cools the system which results in the condensation of steam and a reduction in system 

13 pressure. This can be seen in any of the main pressure figures (e.g., Figure 3-5).

14

15 As long as substantial water remains in the SG secondary-side pressure is governed by the 

16 setpoint of the governing safety valves. This pressure is governed at first by the secondary 

17 PORVs, (e.g., Figure 3-5), unless for some reason valves open at this time either by sticking or 

18 by operator action.

19

20 If secondary relief valves are open this reduces not only the secondary pressures and 

21 temperatures down but it also reduces primary pressures. This occurs for both sticking (-as) 

22 cases (e.g., Figure 3-19) and by valve opening by operator action (-ao) case, Figure 3-32. 

23 MELCOR predicted the pressure drop to be sufficient to drop pressures below the accumulator 

24 activation setpoint.

25

26 If the TDAFW remains operational (ltsbo cases) water remains in the secondary side when the 

27 batteries deplete and TDAFW fails. In this case the secondary-side pressure is governed by the 

28 MSSVs. This can be seen as a jump in secondary pressure at 4 hours (14,400 s) for the ltsbo

29 cases in which secondary valves are not open early on (i.e., ltsbo and ltsbo-a), (e.g., Figure 

30 3-12 and 3-28, respectively).

31

32 When the TDAFW stops replenishing water to the steam generators, water in the SG secondary 

33 sides boils off. The boil-off begins soon after accident initiation for stsbo cases (e.g., Figure 3-6)

34 and after the batteries deplete for ltsbo cases (e.g., Figure 3-13). Except for some RCS-to35 containment heat losses, nearly all core decay power contributes to this boil-off as long as 

36 sufficient water is available in the SG secondary sides to reject the decay heat.

37

38 The SG water eventually boils off to a level at which the SGs can no longer remove all the 

39 decay heat. The primary pressure then begins to rise until the governing primary relief valve 

40 setpoint is reached. Before battery depletion the PORVs govern the primary pressure. The 

41 SRVs govern the primary pressure following battery depletion.

42

43 During this time decay, heat boils off the primary inventory. When the core is liquid-covered 

44 temperatures stay at saturation. The saturation temperature can be seen to increase with 

45 increase primary pressure (e.g., Figure 3-7). Eventually the core uncovers and structure 

46 temperatures begin to rise. This rise is nearly linear in time.

47

48 This temperature rise occurs a little slower for the ltsbo cases because of the lower decay heat. 

49 This can be seen in Figure 3-17. Other than that this minor effect the ltsbo behavior is very 

50 similar to that for the equivalent stsbo case (Figures 3-15 through 3-17).

51
3-42

1 What differentiates one case from another is the timing of boil-off of both secondary and primary 

2 inventories and of the time those temperatures start to rise. Otherwise, scenario progression is 

3 rather similar. Cases where secondary valves are open lose heat sink faster than those that do 

4 not. If the valve opening cools system and drops primary system pressure below to the 

5 accumulator setpoint pressure this additional water inventory delays the heatup time.

6

7 When the core is uncovered the hot gases coming from the core establish a closed-loop-seal 

8 natural convection pattern as described above. These hot gases heat up RCS structures 

9 including the HLs and the steam generator tubes. The calculations predict the surge line to 

10 remain relatively cool from the presence of liquid water.

11

12 As mentioned earlier, a failure of an RCS component releases fission products to the 

13 containment whereas failure of tubes could result in fission products bypassing the containment 

14 and being released to the environment. The failure of another RCS component before steam 

15 generator tubes is preferred because the containment is not bypassed.

16

17 The steam generator tubes more closely track the adjacent gas temperature because they are 

18 thin and therefore have a short thermal response time. Thicker structures such as HLs respond 

19 more slowly to the adjacent gas temperature. The gas temperature adjacent to the tubes is 

20 somewhat cooler because of mixing with cooler gases between the HLs and the tubes.

21

22 When the structure temperatures increase sufficiently, the pressure differential across them can 

23 result in creep. The accumulated damage for vulnerable structures is tracked using creep 

24 rupture indices. When a given creep rupture index reaches a value of 1, that structure is 

25 considered to have failed. The creep rupture indices, assuming no flaws in structures, are used 

26 to predict thermal and hydraulic system response (e.g., Figure 3-8).

27

28 For some scenarios the hottest steam generator tubes in loop B, the loop without the 

29 pressurizer, failed first, but the pressure remained high enough for other RCS components 

30 (i.e., HL) to subsequently fail (e.g., stsbo, ltsbo). For other cases, RCS components other than 

31 the SG tubes failed first, thereby depressurizing the primary system preventing tube failure 

32 (e.g., stsbo-a, ltsbo-a). For others cases still the hottest steam generator tubes failed first but 

33 depressurized the system sufficiently to prevent failure of other RCS components (e.g., stsbo34 as, ltsbo-as, stsbo-ao).

35

36 Although they did not otherwise influence the calculation, creep rupture indices for hot average 

37 tubes for stress multipliers ranging from 1 to 2.5 were evaluated to give an indication of the tube 

38 failure timing for different sized flaws (e.g., Figure 3-9).

39

40 Components fail near the time of rapid Zr oxidation. A sharp rise in hydrogen concentrations 

41 provides an indication of when this occurs (e.g., Figure 3-10).

42

43 Cases for which the HLs fail first no bypass releases to the environment occur.

44

45 For scenarios which included SG-secondary leakage to containment and no assumed valve 

46 failure or operator opening of these valves, either minimal release occurred because one of two 

47 things happened: (1) the secondary relief valves opened very briefly before fission products 

48 were leaked to the containment through the assumed leakage (stsbo, Figure 3-11, and ltsbo) or 

49 (2) the leakage kept the SG secondary pressure low enough that the secondary relief valves 

50 remained seated an no bypass fission product released at all (e.g., stsbo-a, Figure 3-27, and 

51 ltsbo-a, Figure 3-29).
3-43

1

2 Cases which involved intentional opening or failed open secondary relief valves resulted in 

3 releases to the environment (stsbo-as (Figure 3-31), ltsbo-as (Figure 3-25), and stsbo-ao 

4 (Figure 3-33)). Note that releases are not terminated for these cases. These cases were run to 

5 evaluate the thermal hydraulic behavior. They would have to be rerun to fully evaluate fission 

6 product bypass releases.

7

8 Table 3-2 shows the RCS failure times and release fractions to the environment. Because the 

9 primary purpose of the runs was to obtain the TH histories, cases were not rerun if sufficient 

10 data were output to characterize TH behavior. Because of this, some of the cases terminated 

11 before some of the release occurred. Therefore the release fractions listed in this table do not 

12 represent the total release fraction but the release fraction at the time of problem termination. It 

13 instead represents the releases when the more stringent time step restrictions upon material 

14 relocation or reflood caused the calculation to terminate. On the other hand, the SG 

15 secondary-side decontamination determined from the ARTIST project was not included which 

16 would reduce predicted releases. This decontamination would be expected to reduce release 

17 potentially by about a factor of 5. This decontamination factor cannot be directly applied to the 

18 result because the decontamination is particle size dependent and because the 

19 decontamination would replace and not add to the steam generator decontamination already 

20 calculated by MELCOR during the run.

21

22 Table 3-2 Failure Times and Release Fractions to Environment

23

stsbo ltsbo

Fail t(hr) RF** Fail t(hr) RF**

SG HL SG HL

-a - 5.9 - - 13.2 -

-as 4.4 - *

0.006 19.8 - *0.048

-as-SCF 4.4 4.9 N/A 19.8 19.9 N/A

“base” 6.3 7.2 0.003 13.7 14.7 0.001

-SCF 6.3 6.5 N/A 13.7 13.9 N/A

-ao 4.7 - *

0.007 N/A N/A N/A

-MSSVstick 4.5 - *

0.009 N/A N/A N/A

-noSGleak - 8.1 - - 16.1 -

-MSSV1F 6.3 7.2 0.003 13.7 14.5 -

-noSGleak

-MSSV1F - 8.1 - - 16.1 -

-noSGleak

-MSSV1F

-minHLC

N/A*** - 18.5 -

* RF at the time of calculation termination. Releases are ongoing.

** Maximum of volatile (Cs, I, and Te) release fractions.

*** Case did not run to failure time.

24

25 3.6.4 Data Output Fields Provided for Use by External Failure Calculator and 

26 FE Analyses

27

28 Data files are transmitted to perform independent assessments of component failure. The data 

29 channels in these files are generally labeled by parameter (e.g., P for pressure, T for 

30 temperature), location, and material.

31
3-44

1 The following data channels are provided in the main datafile for each loop. Loop A labels are 

2 shown here. Data in items 1 through 7 are used as the TH input for the C-SGTR calculator in

3 Section 7.2 PRA analysis.

4

5 (1) Time

6 (2) PpPrimary system pressure

7 (3) TSL−s Inside surface temperature of the surge line

8 (4) TH LAt−s Inside surface temperature of the top of the HL 1

9 (5) TSGAhu−s Inside surface temperature of the hot-up 2 steam generator tubes

10 (6) TSGAcd−s Inside surface temperature of the cold-down steam generator tubes

11 (7) PsA Secondary-side pressure for Steam Generator

12 (8) TH LAt−g Gas temperature in the top of the HL

13 (9) TH LAb−s Inside surface temperature in the bottom of the HL

14 (10) TH LAb−g Gas temperature in the bottom of HL

15 (11) TSGAhu−g Gas temperature in the hot-up steam generator tubes

16 (12) TSGAhd−g Gas temperature in the hot-down steam generator tubes

17 (13) TSGAhd−s Inside surface temperature of the hot-down steam generator tubes

18 (14) TSGAcd−g Gas temperature of the cold-down steam generator tubes

19 (15) TSL−g Gas temperature in the Surge Line

20 (16) hH LAt Heat transfer coefficient for the top of the HL

21 (17) hH Lab Heat transfer coefficient for the bottom of the HL

22 (18) hSGAhu−in Heat transfer coefficient on the inside of the hot-up steam generator tubes

23 (19) hSGAhu−outHeat transfer coefficient on the outside of the hot-up steam generator tubes

24 (20) ThA Thot used to scale the CFD hottest tube results. This is the gas 

25 temperature entering the SG inlet plenum from the HL.

26 (21) TSGA−boil Gas temperature in the steam generator secondary side

27 (22) Pc1 Containment Pressure

28 (23) TSGAhot−s The hottest tube temperature calculated with the side calculation.

29 (24) TH LAt−smidHL temperature at middle.

30 (25) TH LAt−sout HL outer surface temperature.

31

32 Notes:

33

34 1) HL temperatures are provided for the control volumes and heat structures that are 

35 adjacent to the reactor vessel. Tube temperatures are provided for the control volumes 

36 and heat structures adjacent to the tubesheet. Surge line temperatures are provided for 

37 the control volumes and heat structures adjacent to the HL.

38

39 2) Up and down refer to the direction of flow during closed-loop-seal natural circulation.

40 For example Hot up and cold down both represent tube sections adjacent to the SG inlet 

41 plenum. The surge line temperatures were also provided in the data for loop B to 

42 preserve the data channel numbering.

43

44 3) The steam-generator-tube heat transfer coefficients were used to estimate the hottest 

45 tube temperature using the CFD and the AvgHot tube results which are provided in the 

46 datafiles.

47

48 The supplemental datafile provides the hottest SG tube gas and surface temperatures 

49 calculated from the output data along with the parameters used to determine these values.

50

51
3-45

1 The following data channels are provided in the supplemental datafile (-addl) for each loop.

2

3 (1) Time

4

5 (2) TSGA−g−peak Hottest tube inlet gas temperature calculated using the CFD 

6 normalized temperature, Thot, and Tcold.

7

8 (3) ThA Thot used to scale the CFD hottest tube results. This is the same 

9 data as ThA in the main datafile.

10

11 (4) TcA Tcold used to scale the CFD hottest tube results. This is the 

12 same as the cold-down SG gas temperature the main datafile.

13

14 (5) TSGA−g−mean Hot-up tube gas temperature to compare to the calculated gas 

15 temperature

16

17 (6) TSGA−s−peak Hottest tube temperature determined by a heat transfer calculation 

18 using secondary and calculated hottest-tube-primary gas 

19 temperatures along with the inside and outside heat transfer 

20 coefficients

21

22 (7) TSGA−s−mean Hot-up tube surface temperature to compare to the calculated 

23 tube temperature. This is the same curve as in the hot-up SG 

24 tube temperature in the main datafile.

25

26 (8) TSGA−boil Steam generator secondary-side gas temperature. This is the 

27 same curve as in the main datafile.

28

29 3.6.5 MELCOR Cases To Support the C-SGTR Calculator

30

31 The usage of the temperature and pressure profiles of the selected accident sequences for the 

32 C-SGTR calculator is summarized in Section 7.2. These profiles are used as input files to the 

33 C-SGTR calculator to study the SG tube leak generation and HL/surge line failure for given 

34 flaws and materials.

35

36 Other examples of T&H files created from an MELCOR output files as input files for the C-SGTR 

37 calculator can be found in the Appendices: see Appendix D for such an example.
3-46

1 Table 3-3 MELCOR Cases to Support C-SGTR Calculator

2

AFW 

Fails 

at 

T=0

AFW 

Fails 

at 

T=4 

hr

RCS 

Loop 

A (with 

PRZR)

RCS 

Loop 

B 

Secondary- Side 

Leak at 0.5 in2

Secondary-Side 

Relief Valve 

Sticks Open

Creep 

Rupture 

Suppressed

1 stsboa-SCFa√ √ √ Yes

2 stsboa-SCFb√ √ √ Yes

3 ltsbo-aSCF-a√ √ √ Yes

4 ltsbo-aSCF-b√ √ √ Yes

stsboasSCF-a√ √ √ Yes

stsboasSCF-b√ √ √ Yes

ltsboasSCF-a√ √ √ Yes

ltsboasSCF-b√ √ √ Yes

stsboa-a√ √ √ No

stsboa-b√ √ √ No

ltsbo-aa√ √ √ No

ltsbo-ab√ √ √ No

3

4 Cases 1 through 4 are used in the base case analyses in Section 7.2.
3-47

1 3.7 Potential Future Analyses

2

3 Several aspects of the modeling and analyses were not pursued at this time in the interest of 

4 reducing the number of cases run and the level of effort involved with the idea to find a 

5 representative “limiting” analysis. Additional analyses can be performed to explore pertinent 

6 aspects of system behavior and regions of the event tree, and to look into different sensitivities 

7 in more detail.

8

9 Additional modeling may include:

10

11 • updating the deck to handle loop seal clearing which involves switching SG tube natural 

12 circulation modeling from an active control to a friction-based method and a 

13 renodalization of the SG tubes and cold legs

14

15 • review of surge line draining behavior and reconciliation of modeling

16

17 • performing a detailed review of HL creep rupture modeling and materials

18

19 • updating some nodalization connectivity issues, double checking parameters found to 

20 significantly affect system behavior

21

22 • application of ARTIST steam generator decontamination factors (DFs) in calculating 

23 environmental FP releases

24

25 • accounting for likelihood of specific flaws coinciding with sections of SG tubes at specific 

26 locations in the SG tube spatial temperature distribution

27

28 It is also possible to eliminate the artificial natural-circulation-related pipe-switching logic as the 

29 coupling between the upper and lower HL volumes should be applicable throughout the entire 

30 accident sequence.

31

32 Additional analyses may include:

33

34 • a detailed analysis of loop seal clearing

35 • reconciliation of surge-line discrepancies with previous analyses

36 • comparison and reconciliation of results with those of previous industry analyses

37 • looking into HL creep rupture behavior in more detail

38 • performing detailed sensitivities to better characterize the effect of parameters

39 • analyzing additional relevant sequences in the event tree or similar sequences for 

40 somewhat different designs

41

42 Application of the developed multi-parameter variable-input scripts allowing for multiple input 

43 parameters to be varied so that the different sequences can easily be run with the same deck—

44 specifically using the scripts to perform MELCOR analyses for all relevant permutations of the 

45 C-SGTR event tree with probabilistic sampling of non-discretely defined events or other 

46 parameters if needed.

47

48
3-48

1 Additional information on a few of these items is provided below.

2

3 A change that could have the most significant effect on predicted consequences is updating the 

4 deck to address loop seal clearing. Should the loop seals clear for any of these cases the 

5 enhanced heat transfer to the tubes would greatly accelerate tube failure thus increasing the 

6 potential for FP releases. The deck was not generated with the specific intent to resolve loop 

7 seal clearing. The active SG natural circulation control may significantly affect loop seal 

8 clearing behavior. Furthermore, some inconsistencies exist between the flow-path and control9 volume nodalization for the cold legs in that they do not represent quite the same diameter.

10

11 As mentioned above the SG decontamination factors determined from the ARTIST project 

12 which were not included in the determination of FP releases to the environment would be 

expected to reduce fission product releases potentially by about a factor of 5.

2 13 This was not 

14 updated.

15

16 The accuracy of the SG tube failure calculation can be improved by linking the SG temperature 

17 and flaw distributions to determine the likelihood of a flaw occurring at a hot location on a tube. 

18 Judging by the TH results this improvement would result in a more accurate prediction of tube 

19 failure timing and would likely alter the expected tube failure time by several minutes. The flaw 

20 and temperature distributions within the steam generator can be combined to improve these 

21 estimates. This improvement is only worth implementing if the improved results would be used 

22 in the risk determination.

23

24 Significant conclusions were drawn about plant behavior that relates to the operation of the 

25 secondary-side relief valves. It would be prudent to check and document relief valve opening 

26 criteria comparing against that described in plant documentation. Doing so is critical if safety 

27 decisions will be made from the analysis conclusions. If the modeled relief valve behavior is 

28 different than that for the plant incorrect conclusions will be drawn.

29

30 Recommendations

31

32 Given the inherent uncertainties that cannot be reduced and the level of effort involved, it may 

33 not be worth the effort to further pursue some of the potential future work. However, several of 

34 the potential deck modifications should be made eventually as they will likely affect other 

35 non-C-SGTR analyses. These include:

36

37 • addressing differences between current pressurizer draining behavior and that of 

38 previous analyses

39

40 • switching from active control to a friction-based method to model SG natural circulation 

41 along with preforming the associated renodalization

42

43 • analyzing loop seal clearing in more detail

44

45 Significant conclusions were drawn about plant behavior that relates to the operation of the 

46 secondary-side relief valves. It would be prudent to check and document relief valve opening 

47 criteria comparing against that of plant documentation. Doing so is critical if safety decisions will 

 2 For example, NUREG/CR-7110, “State of the Art Reactor Consequence Analyses Project, Volume 2: Surry 

 Integrated Analyses,” provides an estimate for SG aerosol decontamination between 4.7 and 9.
3-49

1 be made from the analysis conclusions. If the modeled relief valve behavior is different than 

2 that for the plant incorrect conclusions could be drawn.

3

4 The results release fraction calculation should be checked once against methods by running it 

5 on a problem for which releases have been extracted. A match in RFs for a simple case would 

6 confirm proper functionality.

7

8 3.8 Conclusions

9

10 3.8.1 Analysis-Based Conclusions

11

12 Combustion Engineering CFD and MELCOR models were developed. These models were 

13 exercised on selected risk-significant sequences to evaluate expected TH behavior. Datafiles 

14 were generated from the system-code output and provided to DSA and DE for use as initial and 

15 boundary conditions in their detailed component failure analysis. Fission product release data 

16 were generated from these analyses for use in updating the risk contribution from these events.

17

18 The initial planned single bounding case did not result in releases. Because of this additional 

19 cases had to be run to address behavior that had not previously been considered.

20

21 Most of the additional run requirements resulted, unlike in previous analyses, from the different 

22 aspects of the problem were analyzed together. The coupling of phenomena was explicitly 

23 modeled rather than assumed or modeled separately as in previous analyses. Unlike in 

24 previous analyses RCS ruptures were modeled to alter thermal-hydraulic behavior and affect 

25 subsequent failures.

26

27 The initial approach did not sufficiently capture the interactions between the different aspects of 

28 the sequence.

29

30 Unlike in previous TH analyses FP releases were calculated in addition to the TH feedback. As 

31 part of this analysis secondary-side relief valve behavior was explicitly modeled.

32

33 Accounting for these coupled phenomena led to feedback that had not been considered. To 

34 obtain reasonable results further analyses had to be performed. A notable parameter that led to 

35 the requirement of additional runs was the effect of sticking assumptions for secondary-side 

36 relief valves. Addressing the valve behavior was not a consideration in the initial project 

37 planning but proved to have a major impact. This is apparent only upon analysis of results.

38

39 The assumption of MSSVs-failing-open, which was not originally focused on, was found to 

40 significantly affect system behavior. This was the case because previous analyses did not 

41 model secondary relief valve behavior but assumed that a bypass would occur if SG tubes failed 

42 some time before other RCS components. It was found that, with the whole system being 

43 modeled, if valve failure was not explicitly modeled, no appreciable releases would result, even 

44 if a substantial number of SG tubes had ruptured. The simulations had to be run repeatedly to 

45 establish with relief valve behavior that resulted in releases to the environment. Assuming 

46 failure upon full valve opening following a tube rupture did not change releases as the valves did 

47 not fully open and thus did not stick. Assuming a stick-open-failure upon full valve opening at 

48 any time also did not result in appreciable releases because, even for those cases, the valves 

49 did not stick open. Assuming that secondary-side relief valves stick as far as they have opened 

50 or assuming that they are opened by operators did result in releases. It seems that the 

51 secondary-side valves are not as pressure stressed when the tubes rupture several hours into 
3-50

1 the accident so they do not leak. They may be thermally stressed which is not considered for 

2 the valve-opening model.

3

4 Note that if an SG-secondary-to-containment leakage is assumed as in the original model, and 

5 secondary-side valves are open, that this constitutes a leak path from the containment to the 

6 environment. Perhaps it would be more appropriate, when assuming leakage, to assume that it 

7 occurs through secondary-side isolation valves.

8

9 The analyses results indicate:

10

11 • that even if an SGTR occurs first that, without an assumption of secondary relief valves 

12 tick-open-failure or opening by operator action, no or minimal releases will occur

13

14 • that, for a high pressure secondary side (high-dry-high situation), a HL will fail before an 

15 unflawed tube thus preventing tube rupture in the absence of tube flaws

16

17 The prediction of minimal releases without an assumption of secondary-side relief valve failure 

18 is rather insensitive to uncertainties in component failure timing. The amount of fission products 

19 released in a temporary partial valve opening immediately following tube rupture may be 

20 somewhat dependent on the assumption of the number of SG tubes that rupture. Twenty tubes 

21 are assumed to fail if unflawed tubes fail. Rupture of a flawed tube is considered to result in the 

22 full rupture of a single tube.

23

24 For the high-dry-high situation by the time the HL was predicted to fail (damage index = 1) the 

25 tube damage index was very low indicating a significant flaw would be required for tubes to fail 

26 first for this condition. Previous analyses, and earlier single-tube-failure analyses within this 

27 project, have shown that a single tube failure will not reduce pressure at a sufficient rate to 

28 prevent HL failure that limits the amount of FPs that can be released.

29

30 Considerable uncertainties exist in component failure timing.

31

32 A Sandia uncertainty analysis using an earlier version of the Calvert Cliffs Nuclear Power Plant 

33 deck indicated that the RCS-component-to-tube relative failure timing variation because of

34 expected variations in TH parameters approximately followed a normal distribution with about a 

35 600 s standard deviation (Ref. 3).

36

37 A change of a few percent in HL countercurrent flow rate alone was found in analyses to make 

38 the difference between HLs or steam generator tubes failing first. This parameter was 

39 addressed in the Sandia uncertainty analysis by variation of the discharge coefficient and is 

40 factored into the relative-failure-timing uncertainty distribution.

41

42 Results from a sensitivity analysis indicate that the impact of creep-rupture-related material 

43 properties not considered in the uncertainty analysis can also greatly impact HL failure timing.

44

45 The difference in the prediction HL failure timing was found to vary greatly simply by the 

46 assumption of material (stainless or carbon steel)—approximately 2.5 hours. Because the SG 

47 calculator and FE calculations are providing more precise estimates of component failure timing, 

48 updating the HL creep modeling within MELCOR was not prioritized over other modeling 

49 aspects that provide information not available from other sources.

50
3-51

1 Although this difference in failure timing is not directly applicable as an additional uncertainty in 

2 failure timing for this analysis it does underscore the importance of using the correct creep3 rupture-related material properties. It indicates that this material property can make the 

4 difference of whether an SG tube or an HL fails first.

5

6 The highest volatile-FP release was 5 percent at the time the run terminated for the ltsbo case 

7 with no secondary-side-to-containment leakage and sticking MSSVs. This was the highest 

8 release of all cases considered.

9

10 These release fractions should be taken with caution. Some of the release fractions reflect the 

11 releases at the time the problem terminated, not the overall release. For this sequence FPs 

12 were being released at a significant rate at the end of the simulation so the actual predicted RF 

13 will be higher if the simulation is extended. To obtain the code-calculated RFs for the cases in 

14 question the simulations would have to be run until the RFs reached their asymptotic values or 

15 to at least beyond the longest time beyond which mitigative actions would be estimated to occur 

16 in risk analyses. If precise output RFs are needed this can be done.

17

18 3.8.2 Deck-generation-based Conclusions

19

20 Because the heat transfer and flow models are based on accepted practice and because natural 

21 circulation flow was set based on CFD analyses of a sequence for which the code has been 

22 validated the MELCOR results are considered suitable for screening for component failure 

23 timing under closed-loop-seal natural circulation. The CFD modeling approach was validated 

24 against experiments representing a somewhat different steam generator geometry.

25

26 MELCOR can therefore be used as a screening tool to establish which cases need further 

27 scrutiny by more detailed component failure calculation methods conducted using the SG tube 

28 failure calculator and FE analyses.

29

30 Primarily because of active SG natural circulation control, which can alter closed loop flows, 

31 loop seal clearing likely cannot be accurately predicted with the current deck. Even if this would 

32 be updated large uncertainties would remain in the prediction of loop seal clearing. Because 

33 natural circulation flows are consistent with those provided by CFD active control is not 

34 expected to significantly impact tube failure timing.

35

36 A potential change that could have the most significant effect on predicted consequences is 

37 updating the deck to address loop seal clearing. Should the loop seals clear for any of these 

38 cases the enhanced heat transfer to the tubes would greatly accelerate tube failure thus 

39 increasing the potential for FP releases.

40

41 A conceptual model of loop seal clearing behavior was developed. It is based on considering 

42 the loop seal bubble behavior to determine what happens with the loop seal.

43

44 Another potential modification that may have a significant effect is resolving the difference in 

45 pressurizer draining time between current and previous analyses. The matter should be looked 

46 into further.

47

48 An attempt was made to determine the relative contributions of radiative and convective heat 

49 transfer as only the combined heat transfer coefficient was available in the plot file to provide 

50 phenomena-specific HTCs for use in the FE calculation. It was not completely successful. The 

51 impact of this change should be assessed.
3-52

1

2 Previous NRC analyses only adjusted the convective HTC for developing-boundary-layer effects 

3 whereas other analyses have adjusted both the convective and radiative HTCs. Because the 

4 two HTCs could not be distinguished in the MELCOR plotfile both HTCs were adjusted for 

5 developing-boundary-layer layer effects for the FE analyses. This change would tend toward 

6 accelerating the prediction of HL failure.

7

8 The accuracy of the SG tube failure calculation can be improved by linking the SG temperature 

9 and flaw distributions to determine the likelihood of a flaw occurring at a hot location on a tube. 

10 This improvement would result in a more accurate screening-level prediction of tube failure 

11 timing and would likely alter the expected tube failure time by several minutes. This statement 

12 applies to predictions using MELCOR analyses; it does not apply to the PRA analyses in 

13 Section 7 of this report.

14

15 3.9 References

16

17 1. Fletcher, C.D. and R.M. Beaton, “SCDAP/RELAP5 Station Blackout Analyses for the 

18 Calvert Cliffs Plant,” Information System Laboratories, May 2006.

19 2. U.S. Nuclear Regulatory Commission, “SCDAP/RELAP5 Thermal-Hydraulic Evaluations 

20 of the Potential for Containment Bypass during Extended Station Blackout Severe 

21 Accident Sequences in a Westinghouse Four-Loop PWR” NUREG/CR-6995, March 

22 2010, Agencywide Documents Access and Management System (ADAMS) Accession 

23 No. ML101130544.

24 3. Louie, D.L., et al., “A MELCOR Model of the Calvert Cliffs Two-Loop Pressurized Water 

25 Reactor and Containment for the Steam Generator Tube Rupture Scenarios,” Sandia 

26 National Laboratories, October 2012.

27 4. Fuller, E.L., et al., “Steam Generator Tube Integrity Risk Assessment: Volume 1: 

28 General Methodology, Revision 1,” Electric Power Research Institute (EPRI) Technical 

29 Report 1006593, Palo Alto, CA, 2002.

30 5. U.S. Nuclear Regulatory Commission, “Risk Assessment of Severe Accident-Induced 

31 Steam Generator Tube Rupture,” NUREG-1570, March 1998, ADAMS 

32 No. ML070570094.

33 6. U.S. Nuclear Regulatory Commission, “Computational Fluid Dynamics Analysis of 

34 Natural Circulation Flows in a Pressurized-Water Reactor Loop under Severe Accident 

35 Conditions,” NUREG-1922, October 2010, ADAMS Accession No. ML110110152.

36 7. U.S. Nuclear Regulatory Commission, “CFD Analysis of 1/7th Scale Steam Generator 

37 Inlet Plenum Mixing during a PWR Severe Accident,” NUREG-1781, October 2003,

38 ADAMS Accession No. ML033140399.

39 8. U.S. Nuclear Regulatory Commission, “CFD Analysis of Full Scale Steam Generator 

40 Inlet Plenum Mixing during a PWR Severe Accident,” NUREG-1788, May 2004, ADAMS 

41 Accession No. ML041380224.

42 9. U.S. Nuclear Regulatory Commission, Advisory Committee on Reactor Safeguards, 

43 letter to Travers, William D., May 21, 2004, ADAMS Accession No. ML041420237.
4-1

1 4. BEHAVIOR OF RCS COMPONENTS OTHER THAN SG TUBES

2

3

4 4.1 Introduction

5

6 During postulated pressurized water reactor severe accidents, there is a concern that degraded 

7 core effluents could be allowed to bypass the containment if structural failures are experienced 

8 in the steam generator tubes (SGTs). However, if other components of the reactor coolant 

9 system (RCS) (i.e., non-SGTs) fail before the SGTs, containment bypass could be averted if 

10 those failures prevent fission product (FP) releases outside of containment. Prediction of RCS 

11 component failure will help determine the related RCS thermal hydraulic response and the 

12 relative sequence of the RCS failure, the risk importance, and associated uncertainties.

13

14 The risk of containment bypass will be significantly reduced if it can be demonstrated that the 

15 primary system is depressurized or that the primary-side pressure is significantly reduced before 

16 SGT rupture. Such mitigating events may come about because of a breach in the passive 

17 components, because of rupture of the hot-leg piping, pressurizer (PZR) surge line, steam 

18 generator (SG) manways, etc., or a failure of one or more of the active components such as the 

19 RCS coolant pump, power-operated relief valves (PORVs), and safety relief valves (SRVs). 

20 Prediction of the behavior of the RCS coolant pump, PORVs, and SRVs during severe 

21 accidents is more difficult than breach of passive components because the former are 

22 manufactured from complicated parts that fit together with tight tolerances and no experimental 

23 data relevant to their reaction to severe accidents are available.

24

25 4.2 Analyses of RCS Components for a Typical Westinghouse Plant

26

27 RCS drawings from Zion Nuclear Power Plant (ZNPP) were studied (except drawings of the 

28 reactor vessel (RV), the SG, and the PZR internals). It was determined that the following 

29 components qualify as potential failure sites:

30

31 • HL and surge line

32

33 • primary manway in the SG

34

35 • PZR PORV, and safety valve (PSV)

36

37 • three resistance temperature detector (RTDs) that penetrate the HL to monitor reactor 

38 coolant temperature

39

40 • socket weld connection of the instrument lines to the RTD flanges

41

42 • a small-diameter drain line that is attached to the bottom of the hot-leg-pipe elbow at the 

43 hot-leg connection to the SG

44

45 • a small-diameter sample line that is connected to the HL to monitor reactor coolant water 

46 chemistry before the coolant enters the SG

47

48 Failure or excessive creep deformation of the SG primary manway cover bolts, together with 

49 gasket creep, could lead to significant leakage of primary coolant and depressurization of the 

50 primary side. Of the two safety valves, the PORV is challenged more because it cycles more 
4-2

1 often than the PSV during a severe accident and is therefore hotter. Of the other remaining 

2 three items listed above, the welds, which join the RTD at the top of the HL to the HL, are the 

3 most vulnerable and have the highest potential to depressurize the primary side because they 

4 are located on the hot side of the HL during the severe accident transient; also, their failure 

5 would create the largest diameter hole in the HL. Therefore, this particular RTD to the HL

6 junction was analyzed in detail. Failure of the socket weld that attaches the instrument line to 

7 the RTD flange could open up a 25-mm (0.98-in.) diameter channel through which steam from 

8 the HL can vent and potentially reduce the primary-side pressure significantly. Because this 

9 instrument line is of the same diameter as the sample line and the drain line, but will be at a 

10 higher temperature than the sample line and the drain line, its weld connection to the RTD 

11 flange was analyzed in detail.

12

13 4.2.1 HL and Surge Line

14

15 The straight 0.86-m (34-in.) outer diameter, 6.4-centimeter (cm) (2.5-inch [in.]) wall thickness 

Type 316 stainless steel HL extends 2.64 m (8 ft 730 16 /32 in.) from the end of the RV nozzle (A 508 

17 Class 2) to the end of the loop isolation valve which is a massive 11,364-kg (25,000-lb) dry 

18 weight motor-operated gate valve with a projected horizontal length of 1.68 m (5 ft 6 in.). At the 

19 other end of the loop isolation valve is a 1.2-m (47.5-in.) mean radius, 50 degrees reducing 

20 elbow (CF8M A351) whose inner diameter increases from 0.74 m (29 in.) to 0.79 m (31 in.) at 

21 the SG nozzle (SA 216 WCC) end over a projected horizontal length of 1.05 m (3 ft, 53⁄8 in.). 

22 The full weight of the HL and the loop isolation valve is supported by the RV and SG nozzles. 

The surge line intersects the HL at a distance of 2.19 m (7 ft, 21 23 /32 in.) from the end of the RV 

24 nozzle. The 36-cm (14-in.) outside diameter, 3.6-cm (1.4-in.) wall thickness surge line is a long 

25 sinuous Type 316 stainless steel pipe whose center line coordinates were obtained from 

26 Reference 1. The HL and surge line are insulated with Type 304 stainless steel.

27

28 The RV support system permits the reactor to expand radially but resists translational and 

29 rotational movements. It was assumed that the reactor end of the RV nozzle was fixed against 

30 translations and rotations but free to expand radially during a severe accident transient. The HL

31 in the model extended from the reactor end of the RV nozzle to the lower head of the SG 

32 (including the inlet nozzle) and the supports for the SG. The surge line model extended from 

33 the junction with HL to the junction of the PZR nozzle and the PZR, which was assumed to be 

34 fixed against translations and rotations but free to expand radially during the severe accident 

35 transient. Nine surge line supports are present: three flailing restraints, one-variable support 

36 spring hanger, one threaded-rod support, one constant-support hanger, one sway-strut 

37 assembly, and two hydraulic-snubber restraints. The model included all of the surge line 

38 supports except the hydraulic snubbers, which are not expected to be active during a slow 

39 severe accident transient.

40

41 In addition to pressure-induced stresses, significant thermal membrane and bending stresses 

42 are expected to occur in the HL and surge line because of external constraints. Therefore, 

43 failure can occur either by creep rupture or, if the stresses are not relaxed rapidly enough by 

44 creep, by tensile rupture.

45

46 4.2.2 Steam Generator Primary Manway

47

48 Each ZNPP SG contains two primary manways; the one that is in the inlet plenum was selected 

49 because it is hotter. This manway is on the lower head, in an area where, during a severe 

50 accident, the relatively cool recirculating steam flows down through the SG tubes on its way to 

51 the HL and back to the RV. The manway consists of a 67.9-cm (26.73-in.) outside diameter 
4-3

1 (OD), 10.2-cm (4-in.) thick cover plate made of SA533 Grade A Class I, a 52-cm (20.5-in.) OD, 

2 13-mm (0.5-in.) thick insert made of SA-240 Type 304 stainless steel, and a 40.8-cm (16.06-in.)

3 inside diameter (ID), 45.9-cm (18.06-in.) OD, 4.4-mm (0.17-in.) thick spiral-wound gasket made 

4 of Inconel with asbestos filler. These components are secured to the lower head by 16 4.8-cm 

5 (1.88-in.) diameter, 19-cm (7.5-in.) long threaded bolts made of SA-193 Grade B7 on a 58.4-cm 

6 (23-in.) diameter bolt circle. The opening diameter of the manway is 40.6 cm (16 in.). The bolts 

7 are tightened in a crisscross pattern by using three torque passes with an initial torque of 

8 540±20 N-m (400±15 ft-lb), an intermediate torque of 1,490±54 N-m (1,100±40 ft-lb), and a final 

9 torque of 2,170±80 N-m (1,600±60 ft-lb). The final nominal bolt stress is 207 megapascals 

10 (MPa) (30,000 pounds per square inch [psi]). During high temperature exposure, the bolts will 

11 lose most of their prestress, after which the cover plate will lift off from the mating flange of the 

12 lower head. Depending on the gasket springback (which may be minimal at high temperature 

13 because of creep), the liftoff could lead to significant leakage of steam and reduction of primary 

14 pressure.

15

16 4.2.3 Resistance Temperature Detector

17

18 Three RTDs, 120 degrees apart, penetrate the HL and monitor the coolant temperature during 

normal operation. The 7-cm (2.75-in.) OD, 30-cm (1113 19 /16-in.) long RTDs are made of forged 

A-182 F316 stainless steel and project 19.5-cm (711 20 /16-in.) into the interior of the HL. The RTD 

21 scoops are welded to the HL elbow by full-penetration welds with A308 filler material. Failure of 

22 the welds at high temperature could potentially blow the RTD scoop out of the HL and open a 

23 7-cm (2.75-in.) diameter hole in it, leading to rapid depressurization of the primary side. 

24 Because of the postulated recirculating flow of the hot steam during a severe accident 

25 (assuming maintenance of the loop seal), the RTD at the top of the HL is the most vulnerable of 

26 the three that are present, because it is exposed to the hottest steam temperature.

27

28 4.2.4 Socket Weld Connection of Instrument Line to the RTD Flange

29

30 Failure of the socket weld that attaches the 25-mm (1-in.) diameter instrument line to the RTD 

31 flange could reduce the primary side pressure significantly. During a severe accident, hot 

32 steam flowing through the internal drilled channel of the RTD scoop, RTD flange, and then to 

33 the instrument line through the socket weld connection could heat the socket weld to high 

34 temperatures. The pressure forces acting on the instrument line could create shear stresses 

35 that are sufficiently high to cause creep failure of the socket weld and the possible expulsion of 

36 the instrument line, an event that could open up a 25-mm (1-in.) diameter channel through 

37 which steam could escape and depressurize the primary side or at least reduce the system 

38 pressure significantly.

39

40 The dimensions of the socket weld of the Zion plant were not available. For the 25-mm (1-in.)

41 ID and 34-mm (1.33-in.) OD instrument line, the minimum socket weld dimensions were 

42 obtained from Fig. NB-4427-1 of the ASME Code, Section III, which stipulates that the minimum 

43 dimension of the socket weld is 1.09 times the nominal pipe wall thickness, which, for the 

44 current case reduces to 4.5 mm (0.18 in.). In this analysis, the socket weld dimension of 5 mm 

45 (0.2 in.) was used as a reference, and analyzed the effect of a larger weld size on the failure as 

46 part of the sensitivity analysis.

47

48 4.2.5 Power-Operated Relief Valve

49

50 Drawings of a typical PORV were obtained from a valve manufacturer. The PORV contains a 

51 50-mm (2-in.) diameter plug that is connected by a stem to the actuator that drives the plug up 
4-4

1 and down inside the cage. During normal operation, a 45.7-cm (18-in.) long AISI 6150 low alloy 

2 steel spring (spring constant = 814 N/mm (4,700 lbf/in.) holds the plug pressed against the cage 

3 with a force of 43 kN (9,760 lbf). The contact surfaces between the plug and the cage are both 

4 tapered, with slightly different (2.5-degree) taper angles. Hence, when the valve is closed, the 

5 plug makes a line contact with the cage. A solenoid valve controls the air pressure (maximum 

6 0.7 MPa [105 psi]) across a diaphragm that drives the actuator. When activated, the air 

7 pressure is sufficient to overcome the closing force of the spring and opens the passage for the 

8 subcooled water to flow through. When closed, the diaphragm chamber is vented and the 

9 spring forces the plug against the cage. The impact velocity has been estimated by the valve 

10 manufacturer to be 32 mm/s (1.25 in/s). The plug material is Type 316 stainless steel with a 

11 Stellite overlay, and the cage material is ASME SA-564 (17-4 PH steel). The plug and cage are 

12 contained inside the valve body, which is sealed off at the top by a bonnet. The bonnet is 

13 secured to the valve body by a bolted joint.

14

15 The PZR PORV, which is subjected to many opening and closing cycles during a severe 

16 accident transient, can fail by several complex mechanisms. The frequent discharge of 

17 subcooled water through the PORV during the initial phase of a severe accident can lead to 

18 cavitation/erosion damage of the PORV internals by flashing of water to steam and subsequent 

19 two-phase flow. Chattering, which is also a potential problem during this phase of the accident 

20 (see Appendix B), can lead to high cycle fatigue failure caused by repeated plug-to-cage impact. 

21 PORVs are susceptible to surface galling of the valve stem mainly because of differential 

22 thermal growth during a severe accident transient. The cage material of PORVs (17-4 PH steel, 

23 condition H1100) is heat treated and tempered at 593 degrees C (1,100 degrees F). Therefore, 

24 if the temperature of the cage exceeds 593 degrees C (1,100 degrees F), the cage will lose all 

25 of the mechanical properties that were obtained from heat treating. The high temperature, 

26 combined with the loss of some of the mechanical properties can increase the galling potential 

27 between the plug and cage. Should galling occur, the valve would not be operational. Thermal 

28 binding of the plug and the cage is also possible. The body-to-bonnet gasket joint is held by 

29 SA-193 (B7) bolts, which are rated in the ASME Code to permit their use to less than or equal to 

30 427 degrees C (800 degrees F) and which are susceptible to loss of prestress (with consequent 

31 leakage) and creep rupture at higher temperatures. The PORV actuator diaphragm is made of 

32 buna-N rubber, which could be damaged at temperatures that exceed 93 degrees C 

33 (200 degrees F). Although the diaphragm stays relatively cool during normal operation, 

34 repeated cycling of the PORV during severe accidents could increase its temperature by heat 

35 conduction to greater than 93 degrees C (200 degrees F). The proper functioning of the 

36 diaphragm is necessary to open the valve but is not necessary for the PORV to go to the 

37 fail-safe position, which is closed. However, the spring that keeps the PORV closed under 

38 normal operation may lose strength and stiffness at high temperatures, and the steam pressure 

39 may overcome the spring closing force and make the PORV behave like a PSV.

40

41 Each of the above failure mechanisms is a complex problem in its own right and the 

42 development of methods for predicting its failure would require analyses as well as extensive 

43 test programs. As a starting point, the problem of plug-to-cage impact was considered because 

44 it is amenable to front-end analysis (FEA), the results from which could be used to evaluate the 

45 potential for fatigue damage of the plug or the cage contact areas. Because the impacts occur 

46 over very short time intervals, tensile properties are sufficient to carry out the stress analyses, 

47 and creep properties are not needed.

48
4-5

1 4.3 Thermal Mechanical Analyses of Selected RCS Components

2

3 All of the thermal conduction and stress analyses were conducted with the commercially 

4 available finite-element program ABAQUS®. ABAQUS® is used widely in the nuclear and 

5 aerospace industry for conducting high-temperature nonlinear analyses and has been validated 

6 with a number of solutions for which analytical solutions are available. The thermal hydraulic 

7 analysis results from the SCDAP/RELAP5 code were used as the starting point for all analyses 

8 under the current program. The thermal mechanical analyses were performed in two steps. 

9 First, a thermal transient analysis was conducted to obtain the temperature distribution 

10 throughout the model based on the heat transfer analysis by the SCDAP/RELAP5 code. 

11 Second, the nodal-temperature data, together with the pressure and structural-support and 

12 boundary condition data, were entered into the structural-analysis model. In the following 

13 subsections, the analyses for the selected RCS components, other than HL and surge line are 

14 presented. Detailed analyses of hot-leg and surge line failure will be described later in this

15 chapter.

16

17 4.3.1 SG Primary Manway

18

19 Various parts (SG lower head, insert, cover plate, gasket and bolts) for the structure that were 

20 analyzed are shown in Figure 4-1.

21

22

23

24 Figure 4-1 Parts for the Zion hot-leg primary manway

25

26 The gasket was not included in the structural model, because high-temperature properties for it 

27 were not available. Because the stiffness of the gasket is small relative to the other parts, the 

28 stresses should not be affected significantly by its neglect. Once bolt preloads are relaxed by 

29 thermal creep, the area available for leakage will depend on the gasket springback, which is 

30 expected to be small because of gasket creep. However, gasket creep data at high 

31 temperatures are not available.

32
4-6

1 Finite-element model (FEM) of the full assembly is shown in Figure 4-2. A total of 

2 45,383 elements and 67,809 nodes were used. The manway assembly was structurally 

3 supported vertically at the top edge, which was allowed to deform radially in an unconstrained 

4 manner. A uniform and constant pressure of 16 MPa (2.35 kilopound per square inch [ksi]) was 

5 applied during the full transient.

6

7

8

9 Figure 4-2 Finite-element model of manway assembly

10

11 The RELAP5 analysis did not report the temperature of the manway because the model did not 

12 include a cell at the location of the primary manway. The lower head region at the inlet plenum 

13 contained only three cells. The temperature of Cell 105 represented the hot inlet plenum wall 

14 and Cell 106 represented the mixed mean temperature of the inlet plenum wall (Figure 4-3a). 

15 Because the primary manway was at the bottom of the SG tubes that contained the cooler 

16 steam of the return flow, the temperature history reported for Cell 106 should be closer to that of 

17 the manway than to the history reported for Cell 105. A more detailed computational fluid 

18 dynamics (CFD) calculation of the inlet plenum region has shown that the steam adjacent to the 

manway is even cooler than the mixed mean plenum steam temperature (Figure 4-3b).b 19

20 However, the heat transfer coefficients or the surface heat fluxes that correspond to the CFD 

21 calculations were not available. Using the surface heat flux history from RELAP5 on the ID 

22 surface of the lower head plenum wall and on the interior surface of the insert, and assuming 

23 zero resistance to heat flow across all the interfaces, a transient heat conduction analysis of the 

24 manway was performed. The analysis gave an OD temperature for the lower head of 

25 885 degrees C away from the manway and 760 degrees C near the manway, both much higher 

26 than that calculated by RELAP5. Because of the uncertainties in the heat transfer coefficients 

27 or surface heat fluxes and thermal resistances across various interfaces in the manway, results 

28 from transient thermal conduction analysis were not used in the stress analysis. Instead, a 

29 transient thermal conduction analysis was carried out using the transient temperature history at 

30 the outside surface of the plenum wall as calculated by RELAP5 (Figure 4-3a) as boundary 

31 conditions and considered it the reference case. It was decided to address the temperature 

32 effects on stress and deformation of the manway components by temperature uncertainty 

33 analyses.

34
4-7

(a) (b)

1

2 Figure 4-3 Time-temperature histories of inlet plenum

3

4 (a) Time-temperature histories of inlet plenum wall for RELAP5 Cells 105 and 106

5 (b) RELAP5 and CFD-calculated steam temperatures near manway in inlet plenum

6

7 A critical input in the structural analysis of the manway is the initial bolt stress or prestress. 

8 Westinghouse specifications for the Zion plant call for the torque on the SG primary manway 

9 bolts during the final pass to be 2,170±80 N-m (1,600±60 ft-lb) and their design manual 

10 assumes a nominal value for the initial bolt stress as 207 MPa (30,000 psi). The relationship 

11 between the applied torque and the resultant tensile stress in the bolts is highly complex. 

J. Shigley 1 12 has reported the following simple relationship between the torque and the bolt 

13 preload:

14

15 T = KFd (4.1)

16

17 where T is torque, K the is torque coefficient, F is the bolt preload, and d is the fastener 

18 diameter. For typical values of friction coefficients (μ = 0.15), K = 0.2, which is found to be 

19 relatively insensitive to changes in the bolt diameter and the thread characteristics. For the 

20 ZNPP manway bolts, application of Equation 4.1 gives F = 51,200 lbf (225 kN), which 

21 corresponds to a bolt stress of 130 MPa (18,540 psi). A bolt prestress of 207 MPa (30,000 psi)

22 was used as recommended in the Westinghouse manual.

23

24 The structural analysis was carried out in three steps:

25

26 (1) Apply bolt preload at room temperature (elastic analysis).

27

28 (2) Increase temperature of manway assembly uniformly from room temperature to 

29 350 degrees C and apply coolant pressure (elastic analysis).

30

31 (3) Apply severe-accident-transient temperature history (elastic-creep analysis).

32

 1 J. Shigley, Mechanical Engineering Design, McGraw Hill, New York, NY, 1963.
4-8

1 The bolt preloads were applied simultaneously to all 16 bolts with the bolt preload feature of 

2 ABAQUS. The bolts were stressed to a nominal tensile stress of 207 MPa (30 ksi).

3

4 Elastic-Creep Analysis

5

6 When creep deformation is taken into account, the bolt loads are relaxed rapidly, as shown in 

7 Figure 4-4a. Note that the bolt axial loads reach a lower plateau at 14,346 s, which corresponds 

8 to a temperature of 450 degrees C. A residual axial load is maintained in all of the bolts to 

9 balance the force because of the pressure loading on the insert. The exact relaxation history is 

10 dependent on the creep properties (both primary and secondary creep) of the material which, as 

11 mentioned earlier, were not available for this material at the time the analysis was carried out. 

12 Variation of the maximum and minimum principal stresses as well as the section average 

13 stresses across Bolt 1 is shown in Figure 4-4b, indicating that the bolts are subjected to 

14 significant bending. The stresses are below yield at the relevant temperatures.

15

(a) (b)

16

17 Figure 4-4 Elastic-creep analysis of manway bolts

18

19 (a) Relaxation of preloads with time and temperature because of creep in Bolts 1, 5, 9, and 13

20 (b) changes in maximum and minimum principal stresses and average stress in Bolt 1 with time 

21 and temperature

22

23 Figure 4-5a shows the distribution of the maximum principal creep strains in Bolt 1 at 

24 650 degrees C (1,202 degrees F) at 17,650 s; comparison with Figure 4-5b suggests a rapidly 

25 accumulating creep strain with time and temperature. A plot of the variation of maximum creep 

26 strain with time in Figure 4-5b confirms that, by the time the temperature reaches 

27 670 degrees C (1,238 degrees F) at 18,000 s, the maximum creep strain reaches 35 percent. If 

28 failure at 20 percent maximum creep strain is postulated, the failure time for the bolt is 17,770 s 

29 (Tests conducted subsequently by Argonne National Laboratory (ANL) have shown that this 

30 material has a tensile total elongation of 80 percent and creep ductility of 60–90 percent at 

31 650 degrees C [1,202 degrees F]). However, the failure time does not appear to be strongly 

32 dependent on creep ductility.

33
4-9

(a) (b)

1

2 Figure 4-5(a) Distribution of principal creep strain around circumference of bolt 1 at 650 °C

3 Figure 4-5(b) Variation of principal creep strains in bolt 1 with time and temperature

4

5 An important objective of the present analysis is to quantify the lifting of the cover plate from the 

6 flange, thus creating a leakage flow path for the steam during the accident. Figure 4-6a shows 

7 the variation of the maximum contact pressure around the outer periphery of the insert with 

8 temperature. It is evident that the contact pressures are reduced to zero by 450 degrees C 

9 (14,346 s). Beyond 450 degrees C, the contact between the insert/cover plate and the lower 

10 head flange is lost all around, the cover plate begins to lift off from the lower head flange, and 

11 leakage of steam becomes possible. The variation of the total opening area with time and 

12 temperature because of lifting of the cover plate is shown in Figure 4-6b. It is evident that even 

13 when 8 of the 16 bolts are preloaded to 85 percent of the design preload, the opening 

characteristics are the same as in the reference case. An area of 19 square centimeters (cm2 14 )

(3 square inches [in.2 15 ]), which is approximately equivalent to a 50-mm (2-in.) diameter hole, is 

16 created by 600 degrees C (1,112 degrees F) (16,726 s). The actual flow area will be less than 

19 cm2 (3 in.2 17 ) because of gasket spring-back, which should be minimal at these temperatures 

18 because of thermal creep. However, gasket creep data at high temperature are not currently 

19 available.

20
4-10

(a) (b)

1

2 Figure 4-6(a) Distribution of contact pressure between outer periphery of insert and 

3 lower head flange as function of temperature and position

4 Figure 4-6(b) Variation of opening area with time and temperature

5

6 To determine the effect of temperature on the opening area, an analysis was conducted with the 

7 temperature history of Cell 105 (average) (Figure 4-3a), which is considerably hotter than the 

8 reference case (Cell 106, OD). Figure 4-7a shows the variations of the opening area as a 

9 function of time and Figure 4-7b shows the same as a function of temperature for the two 

10 temperature loadings. Although the opening area histories differ widely when viewed as a 

11 function of time, they are much closer when viewed as a function of temperature, indicating that 

12 temperature is the predominant driving force for this problem.

13

(a) (b)

14

15 Figure 4-7 Variation of opening area with (a) time and (b) temperature for two temperature 

16 histories

17

18 Another situation where temperature variation may have an important effect on the opening 

19 area arises after lift-off of the cover plate from the lower head flange when leakage of hot steam 

20 through the opening area will cause local heating of the bolts. The coupled structural/thermal 

21 hydraulic analysis of this problem is complex and was not attempted. Instead, after lift-off of the 

22 cover plate, the temperature of the bolts was manually increased to that of the inlet plenum 
4-11

1 mixed mean steam temperature (Figure 4-3b), which is 200–500 degrees C

2 (392–932 degrees F) hotter than the RELAP5 OD temperature for Cell 106. This should be 

3 considered as an upper-bound effect and the result, plotted in Figure 4-8, indicates that a 

19-cm2 (3-in.2 4 ) opening area could be created in 15,200 s instead of the reference 16,726 s, a 

5 reduction in time of 1,500 s. In reality, the bolt temperatures will rise much less rapidly, 

6 particularly when the area of the opening is small. If a few hundred seconds in time can make a 

7 difference in the outcome of the accident, leakage must be considered in a more rigorous 

8 manner.

9

10

11

12 Figure 4-8 Effect of steam leakage on opening area

13

14 Discussion of Results

15

16 The results presented here are based on creep curves for SA193-B7 bolts that were estimated 

17 from available creep data for AISI 4140 steel. More recent data, based on tests conducted at 

18 ANL, on SA 193-B7 bolt material are presented in Appendix A. The test data indicated that that 

19 the creep equations used in this analysis overestimated the creep strains observed in the tests 

20 by a factor of 5-10, as shown in Figures 4-9a and 4-9b. Therefore, the calculated creep results 

21 for the bolts presented here overestimate the actual creep strains significantly, which would 

22 imply that the stresses in the bolts should relax significantly less rapidly during the severe

23 accident than calculated here.

24
4-12

(a) (b)

1

2 Figure 4-9 Predicted vs. observed creep curves of SA 193-B7 for duplicate tests at 20 and 

3 30 ksi at (a) 550 °C and (b) 450 °C

4

5 4.3.2 Resistance Temperature Detector Welds

6

7 Three RTD scoops are located 120 degrees apart in the elbow of the hot-leg; they are used to 

8 monitor the primary-side temperature during normal operation. The analysis was done for the 

9 one at the top, which is the hottest of the three RTDs because of the counter flow coolant circuit 

10 postulated to occur during a severe accident transient. Because creep failure of the welds that 

11 connect the RTD to the HL is of primary concern, it was assumed that the RTD was attached to 

12 a straight section of the HL, ignoring the curvature of the elbow.

13

14 The geometry information for the Zion SG RTD scoop was assembled from the drawings 

15 obtained from ZNPP. The RTD is attached to the HL by full–penetration welds, as shown in 

16 Figure 4-10. Failure of the A 308 welds could potentially lead to the expulsion of the RTD scoop 

17 and the creation of a 7-cm (2.75-in.) diameter hole in the HL.

18

19 The finite element meshes used to analyze a 30-cm (12-in.) long section of the HL, the RTD, 

20 and the welds are shown in Figure 4-11. A total of 5,144 elements were used to model the HL, 

21 1,110 elements to model the ID weld, 1,377 elements to model the OD weld, and 1,488 

22 elements to model the RTD. The total number of nodes was 6,329. The drilled channel inside 

23 the RTD was included in the FEM.

24
4-13

1

2

3 Figure 4-10 RTD scoop and welds connecting it to HL

4

5

6

7 Figure 4-11 Meshes used to analyze RTD scoop, welds, and HL

8

9 The heat transfer coefficients for the top half (hot side) and bottom half (cool side) of the HL and 

10 the respective steam temperatures were obtained from the RELAP5 analysis. The steam 

11 temperatures as functions of time are shown in Figure 4-12. The hot-side heat transfer 

12 coefficient and steam temperature were also applied to the outside surface of the portion of the 

13 RTD that projected into the HL. The heat transfer coefficients of the RTD should most likely be 

14 higher because the RTD is situated transverse to the flow direction. Heat should also flow into 

15 the RTD from the interior surface of the annular area through which the steam flows into the 

16 instrument line. However, because of the uncertainties in the heat transfer coefficients, in the 

17 reference case, heat transfer coefficients were applied only to the outside surface of the RTD. 
4-14

1 The potentially higher heat fluxes on the RTD outside surface, as well as heat fluxes on its 

2 internal surface, were treated as part of the sensitivity analyses.

3

4

5

6 Figure 4-12 Steam temperature histories for the hot side and the cold side of the RTD

7

8 A constant pressure of 16 MPa (2.35 ksi) was applied on all the pressure boundaries. No axial 

9 constraint was applied on the HL. Although the HL has significant axial stress, the behavior of 

10 the welds (which are of primary focus here) should be relatively insensitive to this stress. The 

11 stress analysis was conducted in two steps. First, the pressure loading was applied at 

12 343 degrees C (650 degrees F); then, the severe accident transient temperatures computed by 

13 the thermal conduction analysis were applied and the stress analysis was conducted by 

14 elastic-creep analysis.

15

16 Temperature distribution in the RTD, HL, and the welds at time t = 14,400 s is shown in 

17 Figure 4-13. Note that the lower half of the HL is significantly cooler than the upper half, as 

18 expected. Also, because of its smaller mass, the RTD heats up much more rapidly than the HL. 

19 The maximum temperature in the RTD is 1,254 degrees C (2,289 degrees F). The RTD 

20 temperature approaches that of the HL at the junction with the HL. The average temperatures 

21 in the ID and OD welds at their junctions with the RTD are shown in Figure 4-14. The average 

22 ID weld temperature is 50–80 degrees C (122–176 degrees F) hotter than the average OD weld 

23 temperature.

24

25 Distribution of von Mises effective stress at the ID weld/RTD interface at time t = 14,148 s is 

26 plotted in Figure 4-15; the same for the OD weld/RTD interface is plotted in Figure 4-16. The 

27 variations of the average von Mises effective stresses at these interfaces with time are plotted in 

28 Figure 4-17a. The time at the maximum and minimum points in this figure coincide with the time 

29 at which there is a step increase in temperature ramp rate (see Figure 4-3a). Although, initially, 

30 the average stress is higher at the ID weld interface than at the OD weld interface, because of 

31 the higher temperature at the ID than at the OD, the average stress at the ID weld interface is 

32 reduced and that in the OD weld interface is increased with time. Creep effects begin to 

33 dominate and stresses are relaxed rapidly at 14,000 s, when the average temperature reaches 

34 800 and 880 degrees C in the OD and ID weld interfaces, respectively. Some localized high35 stress areas are present that would undergo plastic yielding and accumulate plastic strain (i.e., 

36 high strain rate creep), which the current analysis ignores. However, plastic yielding effects 

37 were considered as part of the sensitivity analysis.

38
4-15

1

2

3 Figure 4-13 Close up view of temperature (in °F) in hot-leg RTD scoop at 14,400 s

4 To convert from °F to °C, subtract 32 and divide by 1.8.

5

6

7

8 Figure 4-14 Variation of average temperature in ID and OD welds with time

9
4-16

1

2

3 Figure 4-15 Von Mises effective stress (in psi) distribution at ID weld RTD interface at 

4 14,148 s

5 Note 1,000 psi = 6.895 MPa.

6

7 Time evolution of the average effective creep strain in the ID and OD weld interfaces is plotted 

8 in Figure 4-17b. Although the average stress in the ID weld interface is lower than in the OD 

9 weld interface, because of its higher temperature, the average creep strain in the ID weld is 

10 close to (actually slightly higher than) that in the OD weld interface. An average equivalent 

11 creep strain of 20 percent is reached in 13,890 and 14,000 s in the ID weld/RTD and OD 

12 weld/RTD interfaces, respectively.

13
4-17

1

2

3 Figure 4-16 Von Mises effective stress (in psi) distribution at OD weld RTD interface at 

4 14,148 s

5 Note 1,000 psi = 6.895 MPa.

6

(a) (b)

7

8 Figure 4-17 Time evolution of (a) average von Mises effective stress and (b) average 

9 effective creep strain at interfaces of ID and OD welds with RTD

10
4-18

1 Results from Sensitivity Analyses

2

3 Sensitivity analyses were conducted to address the uncertainty in the current analysis arising 

4 from uncertainties in the temperatures, creep rates of the weld material, and possible 

5 creep-plasticity-interaction effects.

6

7 Sensitivity analysis showed that, when the outside heat transfer coefficients on the RTD are 

8 increased by a factor of 2 from the reference values, still ignoring the internal surface heating on 

9 the RTD, an average equivalent creep strain of 20 percent is reached in, respectively, 13,706 

10 and 13,725 s in the ID weld/RTD interface and OD weld/RTD interface, a reduction of 184 and 

11 275 s, respectively, from the reference times to reach 20 percent creep strain. If the reference 

12 heat transfer coefficients are applied equally to both the outside and inside surfaces of the RTD, 

13 an average equivalent creep strain of 20 percent is reached in 13,790 and 13,890 s in the ID 

14 weld/RTD interface and OD weld/RTD interface, a reduction of 100 and 110 s, respectively, 

15 from the reference times. Creep rate has a significant effect on the failure time. A factor of 10

16 increase in creep rate reduces the time to accumulate 20 percent creep strain by 180 s in the ID 

17 weld interface and 90 s in the OD weld interface when compared with the reference times.

18

19 Inclusion of both creep and plasticity effects in the analysis showed that the time to accumulate 

20 20 percent creep strain is increased by 176 s (tr =14,066 s) in the ID weld/RTD interface and 

21 104 s (tr =14,104 s) in the OD weld/RTD interface, when compared with the reference case. 

22 The times to accumulate 20 percent total inelastic strain (plastic plus creep) in the two weld 

23 interfaces are virtually the same as the times to accumulate 20 percent creep strain. If a 

24 2-percent average effective plastic strain failure criterion is adopted for the welds, the failure 

25 times are 14,123 and 13,930 s for the ID and OD weld interfaces, which are, respectively, 57 s 

26 greater than and 74 s less than the corresponding times to accumulate 20 percent effective 

27 creep strains. Thus, inclusion of plasticity effects does not change the estimates of the failure 

28 times significantly.

29

30 4.3.3 Socket Weld that Connects Instrument Line to RTD Flange

31

32 The possible failure of the socket weld that attaches the 25-mm (1-in.) diameter instrument line 

33 to the RTD flange is considered. During a severe accident, pressure forces could create 

34 sufficiently high stresses to cause creep failure of the weld and the possible expulsion of the 

35 instrument line from the RTD flange. The resultant opening of a 25-mm (1-in.) diameter channel 

36 could potentially reduce the primary-side pressure significantly.

37

38 A simplified axisymmetric model for the instrument line connection to the RTD flange is shown 

39 in Figure 4-18. There is no direct tie connection between the RTD flange and the instrument 

40 line, although contact elements were used to prevent penetration of the instrument line into the 

41 RTD flange. Restraint of the instrument line to vertical movement is provided by the weld, which

42 is tied to both the RTD flange and the instrument line. The lower end of the RTD flange is 

43 supported in the vertical direction.

44

45 A constant internal pressure of 16 MPa (2.35 ksi) was applied to all of the pressure-retaining 

46 surfaces. The axial component of the internal pressure loading on the instrument line was 

47 applied as an axial pressure loading at the top end of the instrument line.

48

49 Internal heating of the RTD increases the temperature of the RTD at the top, near the 

50 connection with the instrument line. Therefore, a uniform temperature field was applied to the 

51 entire model (Figure 4-19).
4-19

1

2

3

4 Figure 4-18 Simplified axisymmetric model for connection of instrument-line-to-RTD-flange 

5 weld

6

7

8

9 Figure 4-19 Temperature loading applied as uniform temperature to model of connection of 

10 instrument-line-to-RTD flange weld

11

12 A combined creep-plasticity analysis was conducted. The time evolution of the average 

13 von Mises effective stress and the effective creep strains in the weld interfaces with the 

14 instrument line and the RTD flange are plotted in Figures 4-20a and 4-20b. Although, initially, 

15 (at low temperatures) the average stress at the weld/RTD flange interface is lower than that at 

16 the weld/instrument line interface, the two stresses tend to converge with time (at high 

17 temperatures). Therefore, creep strain was accumulated at both interfaces at the same rate. 

18 The average effective creep strain at the interfaces reaches 20 percent at time t = 14,230 s, 

19 which is about 440 s later than the failure of the RTD/hot-leg ID weld, discussed in the previous 

20 section.

21
4-20

(a) (b)

1

2 Figure 4-20 Time evolution of (a) average von Mises effective stress and 

3 (b) average effective creep strain at interfaces of weld with instrument line and RTD

4

5 Much larger creep strains than those in the weld are predicted to occur in the instrument line 

6 (assumed to be made of stainless steel) close to the weld, as shown in Figure 4-21. This is not 

7 surprising because the pressure-induced membrane stress in the instrument line is about 

8 65 MPa (9.5 ksi), which is larger than the maximum stress in the weld. Figure 4-22 shows that 

9 the average effective creep strain in the instrument line away from the weld reaches 20 percent

10 at 14,150 s, which is about 80 s before the failure time of the instrument line/RTD flange weld.

11

12

13

14 Figure 4-21 Effective creep strain distribution in instrument line at time t—14,230 s

15
4-21

1

2

3 Figure 4-22 Time evolution of average effective creep strain in instrument line away 

4 from welds

5

6 Sensitivity analysis showed that the average stresses are reduced significantly by doubling the 

7 weld dimensions. However, in contrast to the reference case, the average stress in the 

8 weld/RTD interface remains less than that in the weld/instrument line at all times. Therefore, 

9 the creep strain accumulates faster in the weld/instrument line interface than in the weld/RTD 

10 flange interface. The time to accumulate an average creep strain of 20 percent in the 

11 weld/instrument line interface is 14,330 s, which represents a 100-s delay in failure time of 

12 compared to the reference case.

13

14 Increasing the creep rate by a factor of 10 compared to the reference case causes the stresses 

15 at the weld/RTD flange interface, which are initially lower than those at the weld/instrument line 

16 interface, to increase more rapidly than the stresses in the reference case. With time (at high 

17 temperatures), these stresses converge with those at the weld/instrument line interface. The 

18 average effective creep strain at the interfaces reach 20 percent at time t = 14,110 s, which is 

19 about 120 s earlier than the reference case. The instrument line itself fails at 14,090 s, which is 

20 about 20 s before the failure time of the weld.

21

22 4.3.4 PORV Plug-to-Seat Impact Analysis

23

24 The PZR PORV, which is subjected to many opening and closing cycles during a severe 

25 accident transient, can fail by several complex mechanisms. The frequent discharge of 

26 subcooled water through the PORV during the initial phase of a severe accident can lead to 

27 cavitation/erosion damage of the PORV internals by flashing of water to steam and subsequent 

28 two-phase flow. Chattering, which is also a potential problem during this phase of the accident 

29 (see Appendix B), can lead to high cycle fatigue failure caused by repeated plug-to-cage impact. 

30 PORVs are susceptible to surface galling of the valve stem mainly because of differential 

31 thermal growth during a severe accident transient. The cage material of PORVs (17-4 PH steel, 

32 condition H1100) is heat treated and tempered at 593 degrees C (1,100 degrees F). Therefore, 

33 if the temperature of the cage exceeds 593 degrees C (1,100 degrees F), the cage will lose all 

34 of the mechanical properties that were obtained from heat treating. The high temperature, 

35 combined with the loss of some of the mechanical properties can increase the galling potential 
4-22

1 between the plug and cage. Should galling occur, the valve would not be operational. Thermal 

2 binding of the plug and the cage is also possible. The body-to-bonnet gasket joint is held by 

3 SA-193 (B7) bolts, which are rated in the ASME Code to permit their use to less than or equal to 

4 427 degrees C (800 degrees F) and which are susceptible to loss of prestress (with consequent 

5 leakage) and creep rupture at higher temperatures. The PORV actuator diaphragm is made of 

6 buna-N rubber, which could be damaged at temperatures that exceed 93 degrees C 

7 (200 degrees F). Although the diaphragm stays relatively cool during normal operation, 

8 repeated cycling of the PORV during severe accidents could increase its temperature by heat 

9 conduction to greater than 93 degrees C (200 degrees F). The proper functioning of the 

10 diaphragm is necessary to open the valve but is not necessary for the PORV to go to the 

11 fail-safe position, which is closed. However, the spring that keeps the PORV closed under 

12 normal operation may lose strength and stiffness at high temperatures, and the steam pressure 

13 may overcome the spring closing force and make the PORV behave like a PSV.

14

15 Each of the above failure mechanisms is a complex problem in its own right and the 

16 development of methods for predicting its failure would require analyses as well as extensive 

17 test programs. As a starting point, the problem of plug-to-cage impact was considered because 

18 it is amenable to FEA, the results from which could be used to evaluate the potential for fatigue 

19 damage of the plug or the cage contact areas. Because the impacts occur over very short time 

20 intervals, tensile properties are sufficient to carry out the stress analyses, and creep properties 

21 are not needed.

22

23 A literature search was carried out on impact wear models and mechanisms. Based on the 

24 search, the following recent publications were collected:

25

26 • R.W. Fricke and C. Allen, “Repetitive impact wear of steels,” Wear, Vol. 162–164, 

27 pp. 837–847, 1993;

28

29 • Y. Yang, H. Fang, Y. Zheng, Z. Wang, and Z. Jiang, “The failure models induced by 

30 white layers during impact wear,” Wear, Vol. 185, pp. 17–22, 1995;

31

32 • A.A. Voevodin, R. Bantle, A. Matthews, “Dynamic impact wear of TiCxNy and Ti–DLC 

33 composite coatings,” Wear, Vol. 185, pp. 151–157, 1995;

34

35 • B. Zhang, Y. Liu, W. Shen, Y. Wang, X. Tang, and X. Wang, “A study on the behavior of 

36 adiabatic shear bands in impact wear,” Wear, Vol. 198, pp. 287–292, 1996;

37

38 • B. Zhang, W. Shen, Y. Liu, X. Tang, and Y. Wang, “Microstructures of surface white 

39 layer and internal white adiabatic shear band,” Wear, Vol. 211, pp. 164–168, 1997;

40

41 • B. Zhang, W. Shen, and Y. Liu, “Adiabatic shear bands in impact wear,” J. Mater. Sci. 

42 Lett., Vol. 17, pp. 765–767, 1998; and

43

44 • G.Sheng, W. Hua, and J. Zhang, “Head-disk impact stresses in dynamic loading process 

45 and the extrapolation of parameters for sliding rounding and interface durability,”

46 J. Information Storage and Processing Systems, Vol. 3, pp. 203–206, 2001.

47

48 Most of the above publications deal with very high-speed near-normal repetitive impact, where 

49 adiabatic shear bands form in steels at room temperature and hence, are not directly relevant to 
4-23

1 the impact wear of PORVs during severe accidents. Only the first publication is somewhat 

2 relevant. It reports a study to determine the material, microstructural, design, and operating 

3 parameters of importance in minimizing the impact wear of valves operating in hydro-powered 

4 stopping mining equipment in South Africa. Tests were conducted to simulate the repetitive 

5 impact wear experienced by poppet valves. Wear damage occurred at the point of contact 

6 between the reciprocating valves and their seats. The tests were conducted with line-contact 

7 (which is also characteristic of PORV) specimens on various heat-treated alloys and stainless 

8 steels at frequencies between 5 and 50 Hz, impact velocities from 4 to 10 m/s, and impact 

9 energies from 2 to 5 J. The line contact during the tests was achieved by using a flat-ended 8

10 mm diameter cylindrical striker repetitively striking a conical seat (made of the same material as 

11 the striker) with a 30-degree taper. All of the tests were conducted in a room-temperature water 

12 environment. The wear rates followed an empirical power law for tests carried out on AISI 431 

13 steel:

14

15 W = KNEn (4.2)

16

17 where W = wear loss, N = number of impacts, E = impact energy, and K and n are empirical 

18 constants.

19

20 Under lubricated conditions, two wear mechanisms were observed; pitting and surface traction. 

21 Surface traction, which is a result of partial slip (i.e., slip occurs at the exit edge but not at the 

22 leading edge), was caused by metal-to-metal adhesion and produced most of the wear.

23

24 Initially, during impact testing with line contact, greater deformation occurred in the striker than 

25 in the seat. With each successive impact, the contact stresses were reduced. The greatest 

26 amount of deformation occurred during the first impact, and, in the absence of wear, the contact 

27 stresses were reduced with each successive impact until a steady state was reached when the 

28 material could support the impact load. An incubation period was observed preceding wear 

29 loss, a finding that indicated that wear proceeds only after surface material has been strained to 

30 capacity and stresses cycled a sufficient number of times for crack initiation and propagation to 

31 occur under the predominantly compressive stress conditions. Debris in the form of flakes or 

32 thin platelets was produced in this way. Following the incubation period, the wear rate was high 

33 and decreased toward zero as the contact area increased and the impact stress decreased. It 

34 was concluded that the rate of wear was a function of impact energy, material properties, 

35 contact areas, and wear mechanisms.

36

37 Although of much interest, the results from this study are not directly applicable to the impact 

38 wear of PORV during severe accidents for the following reasons:

39

40 The impact velocity of the plug in the PORV during closure is of the order of 0.5 cm/s (1.25 

41 in./s), which is much smaller than the impact velocities used in the tests (4–10 m/s).

42

43 Tests were conducted at room temperature in a water environment, whereas the PORV will 

44 operate at high temperature, first in subcooled water and then in a superheated steam 

45 environment during severe accidents.

46

47 The plug in the PORV is Type 316 stainless steel with a hard Stellite overlay and the cage is 

48 heat-treated and tempered steel. The tests were conducted with the striker and the seat made 

49 of the same material without any overlay.

50

51
4-24

1 Although line contact was used in the tests, the angle between the two contacting surfaces was

2 30 degrees, which is much greater than the 2.5 degrees for the PORV. Therefore, the PORV 

3 plug has a much greater parallel velocity component relative to the normal component than the 

4 tests. The frequency of impact in the tests was much greater than expected in the PORV during 

5 severe accidents.

6

7 Although the results from the tests are not directly applicable to the PORV during severe 

8 accidents, similar mechanisms should be operative and crack initiation and propagation will play 

9 important roles in the wear rates and failure of the plug and cage.

10

11 The stress-strain field created by the repeated impact of the plug on the cage because of PORV 

12 cycling was analyzed. The various parts selected for impact analysis are shown in Figure 4-23.

13

14

15

16 Figure 4-23 Various parts included in the plug-to-cage impact analysis

17

18 The taper of the contacting surfaces of the plug and the cage differs slightly (2.5°). 

19 Consequently, the initial contact between the plug and the cage is almost tangential in the axial 

20 direction and along a line in the circumferential direction. For simplicity, an axisymmetric model 

21 was used for the FEA. The Stellite overlay on the plug was not included in the reference case 

22 analysis but was included in the sensitivity analysis. During normal operation, a 46-cm (18-in.) 

23 long AISI 6150 low alloy steel spring (spring constant = 814 N/mm [4,700 lb/in.]) holds the plug 

24 pressed against the cage with a force of 43 kN (9,760 lb). The spring was included in the FEM 

25 as a linear-spring element. The cage was supported in the vertical direction at the shoulder 

26 region. In view of the large relative contact displacement between the plug and the cage, and to 

27 handle the dynamics of the problem, a full nonlinear (finite deformation) analysis was 

28 implemented with ABAQUS-explicit.

29

30 The entire model was assumed to be at a uniform and constant temperature during the impact. 

31 Because of the high strain rate involved during the impact, the analysis was carried out with an 
4-25

1 elastic-plastic constitutive relationship for both the plug (Type 316 stainless steel) and the cage 

2 (17-4 PH steel H1100). A rate effect on the constitutive relationship was not included in the 

3 analysis. The strength properties were obtained from the ASME Code, Section II, and the 

4 bilinear stress-strain curves that were used in the analysis are shown in Figure 4-24. Note the 

5 much higher strength of the cage when compared with that of the plug. At temperatures greater 

6 than 593 degrees C (1,100 degrees F), the cage material will lose strength rapidly. However, 

7 because of lack of data, analyses were conducted for 288 and 538 degrees C (550 and 

8 1,000 degrees F) only.

9

10

11

12 Figure 4-24 Stress-plastic strain curves at 288 and 538 °C (550 and 1,000 °F) used in analysis

13

14 In the reference case, the initial velocity of the plug was set at 32 mm/s (1.25 in./s), as 

15 recommended by the manufacturer, starting from a position just in contact with the cage. The 

16 analysis was continued until the elastic waves travelling back and forth were significantly 

17 reduced. The variation of the spring force with time for a single impact, plotted in Figure 4-25, 

18 shows that the time taken by the plug to come to complete rest is 0.01 s. After the first impact, 

19 the plug was retracted rapidly to the same position it occupied before the first impact and was 

20 held in place for 0.005 s. It was then given the same initial velocity as in the first impact, and 

21 the analysis continued as before. Finally, the plug was retracted and a third impact was 

22 analyzed.

23
4-26

1

2

3 Figure 4-25 Variation of spring force with time during single impact

4

5 The variations of the maximum equivalent plastic strain with von Mises effective stress and time 

6 are shown in Figures 4-26a and 4-26b, respectively. The additional stress cycles in 

7 Figure 4-26a are because of elastic wave propagation in the plug. Note that the maximum 

8 effective plastic strain increases with each impact, although at a diminishing rate. After three 

9 impacts, residual effective plastic strains of 8.4 and 9.4 percent are created at 288 and 

10 538 degrees C (550 and 1,000 degrees F), respectively. Although plastic strain ratcheting 

11 occurred with each loading cycle, Figure 4-26a shows no open hysteresis loop in the 

12 stress-plastic strain plot, which indicates that low-cycle fatigue should not be a problem for this 

13 type of cycling. In contrast to the plug, the cage does not experience any plastic strain at these 

14 temperatures because the maximum stresses are too low.

15

(a) (b)

16

17 Figure 4-26 Variation of equivalent plastic strain with (a) von Mises effective stress and 

18 (b) time for most highly strained element in plug at 288 and 538 °C (550 and 1,000 °F)

19
4-27

1 Stellite Overlay Effect

2

3 In practice, a hard Stellite overlay is present on the soft plug material; it will have a major 

4 influence on the stress-strain distribution in the plug. For the purpose of investigating the effect 

5 of the overlay, a simplified model of the plug-to-cage impact was adopted (Figure 4-27a). The 

6 impact analysis of the plug with a 2-mm (0.08-in.) thick Stellite overlay was conducted at 

7 538 degrees C (1,000 degrees F) with the stress-plastic strain curves shown in Figure 4-27b. At 

8 538 degrees C, the Stellite coating is stronger than the 17-4 PH steel and considerably harder 

9 than stainless steel. The FEA showed that no plastic strain was generated in the overlay, the 

10 plug, or the cage during the impact. A plot of the distribution of the von Mises effective stress, 

11 shown in Figure 4-28, shows that the maximum stresses in the overlay, the plug, and the cage 

12 are less than their respective yield stresses. The Stellite overlay effectively shields the 

13 underlying stainless steel plug from developing high contact stress and plastic strain.

14

(a) (b)

15

16 Figure 4-27 (a) Simplified axisymmetric model of plug-to-cage impact, where satellite overlay 

17 on plug is 2 mm thick and (b) stress-plastic-strain curves used in impact analysis of plug 

18 with 2-mm-thick Stellite overlay
4-28

1

2

3 Figure 4-28 Distribution of von Mises effective stress (in psi) near contact zone of cage and 

4 plug with 2-mm Stellite overlay

5 Note 1,000 psi = 6.895 MPa.

6

7 4.4 Thermal Mechanical Analyses of the HL and Surge Line

8

9 The thermal mechanical analyses were performed in two steps. First, a thermal transient 

10 analysis was conducted to obtain the temperature distribution throughout the model. Second, 

11 the nodal-temperature data, together with the pressure and structural-support and boundary 

12 condition data, were entered into the structural-analysis model. The basic nodal configuration 

13 and numbering of both models were the same.

14

15 4.4.1 FEM for Thermal Analysis and Boundary Conditions

16

17 Two slightly different versions of the same basic FEM were used in two analyses in sequence. 

18 The first version was used to analyze the thermal model, which included all the components 

19 shown in Figure 4-29. The second version of the FEM was used to analyze the structural 

20 model, which, in addition to the components shown in Figure 4-29, also included the supports 

21 and flailing restraints. The supports and flailing restraints were not included in the thermal FEM 

22 because they do not impact the thermal analysis of the HL or the surge line, and were not of 

23 interest from a thermal standpoint. All of the components of the thermal model were modeled 

24 with second order (8 nodes) thick quadrilateral shell elements with five integration points across 

25 the thickness.

26

27 The finite element mesh, shown in Figure 4-30, for the thermal analysis was highly refined in 

28 areas suspected of damage, namely the elbow, HL, and nozzles. The number of finite elements 

29 is close to 4,000, with close to 63,000 degrees of freedom.
4-29

1

2

3 Figure 4-29 Components of first version of FEM for thermal conduction analysis

4

5

6 Figure 4-30 FEM for thermal analysis

7

8 The initial temperature was assumed to be the operating temperature of 300 degrees C 

9 (572 degrees F). The outer surfaces of the system, including the tube support plate, were 

10 assumed perfectly insulated. The ends of the RV and pressurizer nozzles were assumed 

11 insulated as well. The system was brought to steady-state conditions, with a heat flux value that 

12 was equal to that given at time zero. After the system reached steady state, a transient thermal 

13 solution ensued, driven by the heat flux profiles. Although the profiles extend to 32,000 s, the 

14 thermal simulations were terminated when the component temperatures exceeded 

15 1,600 degrees K (2,421 degrees F), because the structural models reveal significant damage at 
4-30

1 temperatures well below 1,600 K. In fact, the structural data do not support temperatures higher 

2 than 1,400 K. Although the tensile and creep-rupture properties of the materials used in these 

3 simulations are restricted to temperatures below 1,400 K, it is expected that these materials 

4 significantly soften and will experience rapid high-temperature damage at temperatures above 

5 1,400 K. The implications of this will be discussed in Section 4.5.5.

6

7 4.4.2 FEM for Structural Analysis and Boundary Conditions

8

9 The second version of the FEM, which is used to conduct the structural analysis, is identical to 

10 that of the thermal model (Figure 4-31), except that the supports and flailing restraints were 

11 included in the structural model, as shown in Figure 4-31. The temperature history obtained 

12 from the thermal analysis was entered directly into the structural model for stress and damage 

13 analysis. Because the severe accident transient occurs at a relatively slow rate, the hydraulic 

14 snubbers were not included in the structural model. The surge line contains four supports, and 

15 three flailing restraints. The flailing restraints were included in the structural model because 

16 preliminary results indicated that the surge line was experiencing significant rigid body 

17 displacements that exceeded the 12.5-cm (5-in.) radial gaps in the flailing supports. Only the 

18 bottom head of the SG was modeled with sufficient detail to capture the damage around the SG 

19 nozzle. Because the SG weight and center of mass were significant factors, their effect was 

20 included by modeling the remainder of the SG (above the tube support plate) by a rigid body 

21 (coupled with the bottom head) with an SG effective center of mass at an elevation of 187.3 m 

22 (614.5 ft).
4-31

1

2

3 Figure 4-31 Components of second version of FEM for structural analysis with supports, 

4 flailing restraints, and hangers

5

6 Reactor Vessel Nozzle

7

8 The hot-leg/surge line model extends to the junction of the RV and the RV nozzle. It is 

9 assumed that the RV provides full restraint against all rigid-body translations and rotations of the 

10 RV nozzle end but allows free growth in the radial direction.

11

12 Steam Generator

13

14 The support arrangement of the SG allows it to move as a rigid body, radially away from the RV, 

15 as the temperature of the system is increased from room to operating temperature. The gaps 

16 and shims are designed so the SG bears against the top and bottom bumpers at full power. 

17 During a severe-accident transient, when the hot-leg temperature increases, the supporting 

18 structures restrain the SG from moving any further than allowed by the elastic deformation of 

19 the supports. These supports were modeled as nonlinear springs that can carry compressive 

20 but not tensile loads. Thus, the snubbers at the upper lateral support allow the SG to tip away 

21 from vertical toward the RV during a relatively slow severe-accident transient. The SG dead 

22 weight in such a scenario could potentially apply significant bending and twisting moments on 

23 the SG inlet nozzle.
4-32

1

2 The SG required six elastic supports in the direction of the six global rigid degrees of freedom, 

3 namely, three translations and three rotations. These supports were developed and are 

4 described according to the local coordinate system shown in Figure 4-31 and labeled as Radial, 

5 Tangential, Z, or 1, 2, 3. The SG rests on four gimbals that are modeled as simple beam 

6 members that provide axial elastic support in the vertical direction (Z) with an axial stiffness of 

7 KV2. Both ends of the beam members are pinned end boundaries.

8

9 The rotational stiffness of the SG in the Z direction is referred to as KR4. In the tangential 

10 direction, both axial and rotational elastic supports (KT3 and KR5) are at the bottom head, and 

11 the arrangement in the Radial direction along the HL (KT4 and KR5) is similar. Two elastic axial 

12 supports are at the top of the SG (close to the center of mass). The one in the tangential 

13 direction is KT5. The radial one (KT6) provides a nonlinear elastic support; if the top of the SG 

14 leans toward the HL, this support provides resistance only after a displacement of 210 mm ( 8.3 

15 in.). If the top moves backward, away from the HL, the support resists at a different rate, as 

16 shown in Table 4-1.

17

18 Table 4-1 Spring Rates of Steam Generator Supports

19

Support 

Name

Spring Rate

lb/ft N/mm Note

KT3 1.63E+08 2.38E+06 Linear

KT4 1.39E+08 2.03E+06 Linear

KT5 5.52E+08 8.06E+06 Linear

KT6 1.92E+08 2.80E+06 Moving toward HL after 210-mm (8.3-in.) 

displacement

KT6 1.24E+08 1.81E+06 Moving away from HL

KV2 2.24E+08 3.27E+06 Linear

KR4 1.51E+10* 2.05E+13** Linear

KR5 4.30E+09* 5.83E+12** Linear

20 * lb-ft/rad ** N-mm/rad

21

22 Surge Line Supports

23

24 The FEM for structural analysis contains nine surge line supports: three flailing restraints, one 

25 variable support spring hanger, one threaded-rod support, one constant-support hanger, one 

26 sway strut assembly, and two hydraulic snubber restraints. The stiffness values for the various 

27 supports were obtained from Reference 1.

28

29 The flailing restraints provide vertical and horizontal supports but a gap allows for thermal 

30 movement of up to 5 in. Therefore, effectively, these supports do not provide any restraint until 

31 the surge line moves significantly. The vertical stiffness is 9.475 × 107 lb/ft and the horizontal 

32 stiffness is 2.47 × 109 lb/ft in compression and 2.83 × 108 lb/ft in tension.

33

34 The stiffness of the hanger of the variable-support spring 12,960 lb/ft is much smaller than the 

35 stiffness of the other restraints. The threaded support spring hanger exhibits a stiffness of 

36 2.45 × 106 lb/ft, and carries a vertical dead weight of 8,373 lb during normal operation. The 

37 constant-support hanger supports a constant vertical dead weight of 30,000 N (6,800 lb). The 

38 stiffness of the sway strut assembly, which provides support in both the horizontal and vertical 

39 directions, is 9.3 × 106 lb/ft.

40
4-33

1 All of the supports, except the snubbers, were modeled in the FEM. Four supports (excluding 

2 the flailing restraints) are modeled for the surge line; and they are described in Figure 4-31, and 

3 their types are listed in Table 4-2. Three of the supports provide elastic support with a specified 

4 spring rate, the fourth (RCH1003), provides a constant load. The other three supports are 

5 oriented as shown in Figure 4-32.

6

7 Table 4-2 Surge Line Supports in FEM for Structural Analysis

8

9

10

11 Pressurizer Nozzle

12

13 The hot-leg/surge line model extends to the junction of the PZR shell and the PZR nozzle. The 

14 PZR is rigidly supported by the upper and lower lateral supports, which prevent translational and 

15 torsional movements but allow free radial and vertical thermal growth. The vertical load is 

16 carried by four columns, attached rigidly to the ring beam of the lower lateral support. 

17 Therefore, it was assumed that the PZR provides full restraint against all rigid-body translations 

18 and rotations of the PZR nozzle end but allows free radial growth.

19

20 4.4.3 Mechanical and Surface Heat Flux Loading

21

22 4.4.3.1 Gravity and Pressure Loading

23

24 The whole system was subjected to gravitational loading. The weight of the SG was applied at 

25 its center of mass. The weight of the hot-leg valve was distributed throughout its volume. The 

26 surge line and the hot-leg gravity loads were applied as body forces. Table 4-3 lists the weights 

27 and/or the mass densities used for gravity loading; it also shows that steam pressure used 

28 throughout the systems is 16.2 MPa (2,350 psi).

29

30 Table 4-3 Weights and Pressure Loading and Mass Densities Used in 

31 Thermal-Mechanical Analysis of the HL and Surge Line

32

Metric English

Valve weight 111 KN 25,000 lb

SG weight 3,720 KN 836,476 lb

Surge line mass density 7,500 kg/m3 0.28 lb/in3

HL mass density 7,500 kg/m3 0.28 lb/in3

Steam pressure 16.2 MPa 2,350 psi

33

34 4.4.3.2 Surface Heat Flux (Heat Transfer Coefficients)

35

36 The thermal model was driven by heat flux profiles as functions of time. Fourteen such profiles 

37 are assigned to 14 regions, as shown in Figure 4-32, and labeled according to heat flux 

38 information obtained from RELAP5 calculations.

39
4-34

1

2

3 Figure 4-32 Control volumes for thermal hydraulic analysis of the HL and surge line 

4 by RELAP5

5

6 RELAP5 divided the HL into two noninteracting independent halves. The top half carries the hot 

7 steam from the reactor to the SG and the bottom half returns the cool steam from the SG to the 

8 reactor. The top half of the HL was divided into five cells (1001001 through 1001005), each with 

9 constant heat flux. The bottom half of the HL was also divided into five cells (1011001 through 

10 1011005), each with constant heat flux. The outer surfaces of the HL and surge line were 

11 assumed to be perfectly insulated. The highest heat fluxes in the top and bottom halves are in 

12 cells 1001001 and 1011005, respectively. The lower head of the SG was assigned the SG inlet 

13 plenum heat flux. The surge line was divided into three cells, with the closest cell to the HL

14 designated as 1531003. For the present analysis, the heat transfer coefficient from the 

15 RELAP5 results was spatially adjusted in the hot-leg and surge line, based on the developing 

16 curve provided in NUREG-1922 (Ref. 2).

17

18 4.4.4 Results of Thermal Mechanical Analysis of HL and Surge Line

19

20 For the basic reference case considered, the thermal properties along with heat flux profiles 

21 discussed in the previous sections were used. The thermal transient analysis, after reaching 

22 the steady state, started at time = 9,222 s and terminated at ≈19,330 s. After completion of the 

23 thermal solution, the temperature time histories were input into the structural portion of the 

24 model. The components were assumed to respond to the structural, gravity, and thermal loads 

25 by an additive combination of elastic, rate-dependent plastic, and creep (visco-plastic) material 

26 behaviors. The material model consisted of using a simple thermal plasticity combined with a 

27 secondary creep law. The stress versus plastic strain curve used for the Type 316 stainless 
4-35

1 steel (SS) is shown in Figure 4-33. The properties used for the A508 carbon steel and the 

2 Alloy 182 weld metal can be found in Reference 1 and the properties for the Type 316 SS can 

3 be found in Appendix A. Because material data was not available for temperatures higher than 

4 1,373 K these same properties were used at higher temperatures. However, as will be seen, 

5 failure is predicted before the temperatures get much higher than this.

6

7

8

9 Figure 4-33 Temperature dependent stress strain curves for 316 stainless steel

10 (Appendix A)

11

12 An ABAQUS power-law model is chosen to model creep behavior, given by:

13 .

εε

cccc = AAqq�nnttmm 14 (4.3)

15

where .

εε

cccc 16 is the uniaxial equivalent creep strain rate, qq� is the uniaxial equivalent deviatoric 

17 stress, and t is the total analysis time, and A, n are temperature dependent constants and m=0. 

18 The creep properties given in Appendix A are used in the analysis.

19

20 Figures 4-34 and 4-35 show representative temperature contours of the whole system, captured 

21 at 9,222 s and 13,555 s, respectively. The model was based on metric units, with temperature 

22 expressed in Kelvin. The steady state temperature of 623K is reached at 9, 222 s in the entire 

23 region of consideration, as shown in Figure 4-34. The upper half of the HL experiences much 

24 higher temperatures during the transient, as shown in Figure 4-35.

25

26 The contours of effective creep strain and plastic strains are shown in Figures 4-36 and 4-37

27 respectively. Both the figures indicate that the upper half of the HL experiences higher creep 

28 and plastic strains. The plastic strains and creep strains are predicted to reach above 

29 30 percent and 7 percent in the upper half of the HL. These levels of strains are quite high and

30 indicate potential failure in the regions of interest.

31

0

100

200

300

400

500

600

700

800

0 0.5 1

Stress (MPa)

Plastic Strain (mm/mm)

T = 473 K

T = 573 K

T = 698 K

T = 823 K

T = 923 K

T = 973 K

T = 1023 K

T = 1173 K

T = 1373 K
4-36

1

2

3 Figure 4-34 Temperature contours at inner surface at 9,222 s indicate the steady state 

4 condition of 623 K in the entire region of consideration

5

6

7

8 Figure 4-35 Temperature contours at inner surface at 13,555 s indicate the higher 

9 temperature in the upper half of the HL region

10

11

12

13 Figure 4-36 Contours of accumulated creep strain at inner surface at 12,300 s indicate the 

14 significant creep strains in the upper half of the HL region
4-37

1

2

3

4 Figure 4-37 Contours of plastic strain at inner surface at 12,300 s indicate the 

5 concentration of plastic strains in the upper half of the HL region

6

7 4.4.5 Evaluation of Structural Damage

8

9 Creep failure can be predicted either by exhaustion of material creep ductility or by 

10 accumulation of creep damage. Failure by exhaustion of creep ductility occurs when

11

12 Effective Creep Strain = ε = εc = Creep Ductility (4.4)

13

14 Because creep ductility data for the materials used in the analyses is available for the entire 

15 temperature range of interest, the linear time fraction damage rule was used to calculate the 

16 creep damage as follows:

17

Creep Damage = ∆t

tr

(T,σ) ∑

18 (4.5)

19

20 where Δt is the time interval at temperature T, σ is von Mises effective stress, and tr is the time 

21 to creep rupture at temperature T. Failure is predicted to occur when the creep damage is 

22 equal to 1.

23

24 Given the state of stress and temperature, the Larson Miller parameter (PLM) was used to 

25 evaluate the time to rupture, tr:

26

tr = 10

PLM

T −C 











27 (4.6)

28

29 where T is the absolute temperature in Kelvin, PLM is the Larson Miller parameter, which can 

30 be obtained approximately as a function of effective stress σ as follows:

31

32 PLM = A*Log10(σ) + B (4.7)

33

34 and A, B, and C are material parameters given in Appendix A.

35
4-38

1 Creep damage was considered only if the in-plane principal stress was tensile, because 

2 compressive in-plane stress does not initiate cracking.

3

4 At elevated temperature, creep deformation tends to relax the stresses and keep them below 

5 the yield strength of the material. However, in the presence of a time-dependent driving force, 

6 such as thermal expansion, creep deformation may not be fast enough to relax the stresses to 

7 below the yield stress. In such cases, failure by tensile rupture is a possibility.

8

9 Uniaxial tension tests conducted at high temperatures indicate that stainless steels and the 

10 ferritic steels experience a uniform elongation of the order of few percent (2–5 percent), beyond 

11 which necking and plastic strain localization occurs and any additional plastic displacement is 

12 negligible. Based on this, it is possible to determine failure time and location when a material 

13 point reaches a through-thickness plastic strain of 2 percent. Because this failure criterion is 

14 quite arbitrary, it was not adopted it in this study. Nonetheless, it should be pointed out that the 

15 plastic strains reach values of above 10 percent in the upper half of the HL before the failure is 

16 predicted using the Larsen-Miller parameter approach described above.

17

18 The creep damage, calculated using Equation 4.5, in the section of HL experiencing higher 

19 creep and plastic strains are shown in Figures 4-38 and 4-39. The through-thickness damage 

20 shown in Figure 4-38 indicates that the maximum damage of 1 (indicated by red-color) occurs 

21 on the upper half of the HL away from the nozzle. The corresponding damage in the outer and 

22 inner surfaces shown in Figures 4-39a and 4-39b indicate that the damage is rather uniform 

23 through the thickness, although the maximum damage occurs in the inner surface earlier. This 

24 indicates that failure through the thickness is quite rapid, perhaps because of the steep increase 

25 in the temperature transient.

26

27

28

29 Figure 4-38 Contours of through-thickness damage at 12,300 s shown in the section of HL

30 experiencing higher strains

31 The red-colored regions reach the creep damage of unity.

32

33 The structural analysis of the system model considered here posed convergence issues beyond 

34 14,000 s. Although maximum damage is predicted much earlier, this model is not conducive to 

35 conducting additional analyses to examine the effect of weld-overlay and the effects of varying 

36 material response. In addition, the system model took considerable cpu hours to perform the 

37 needed calculations. Because the failure occurs in the HL region, further analyses were 

38 conducted using a finite element model of the HL region.

39
4-39

1

2 (a) Outer surface (b) Inner surface

3

4 Figure 4-39 Contours of creep damage at 12,300 s shown in the (a) outer surface and 

5 (b) inner surface of HL experiencing higher strains

6 The red-colored regions reach the creep damage of unity.

7

8 4.4.6 HL Model

9

10 The thermal mechanical analysis using the smaller hot-leg model was conducted using the 

11 same procedure described for the system model. The contours of effective creep strain and 

12 plastic strains are shown in Figure 4-40 and 4-41, respectively, at time equals 12,430 s. The 

13 strain distributions in the upper half of the HL are similar to those shown in Figures 4-36 and 

14 4-37 for the system model. Figures 4-40 and 4-41 indicate that the upper half of the HL

15 experiences higher creep and plastic strains. The plastic strains and creep strains are predicted 

16 to reach above 40 percent and 6 percent in the upper half of the HL. These levels of strains are 

17 similar to those predicted using the system model. Thus, the smaller HL model yields similar 

18 results to the larger system model. Because of slightly lower levels of strains predicted using 

19 the smaller HL model, the failure time may be longer. However because of the steep transient, 

20 the failure time using the HL model, shown in Figure 4-42, was only 126 s longer than the time 

21 predicted using the system model.

22

23

24

25 Figure 4-40 Contours of accumulated creep strain at inner surface at 12,430 s indicate the 

26 significant creep strains in the upper half of the HL region

27 The strain distribution and maximum strain level are similar but not identical to the 

28 system model.

29
4-40

1

2

3 Figure 4-41 Contours of accumulated plastic strain at inner surface at 12,430 s indicate 

4 the significant creep strains in the upper half of the HL region

5 The strain distribution and maximum strain level are similar but not identical to the 

6 system model.

7

8

9

10 Figure 4-42 Contours of through-thickness damage at 12,430 s shown in the section of 

11 HL experiencing higher strains

12 The red-colored regions reach the creep damage of unity.

13

14 Sensitivity Analyses

15

16 Several additional analyses were conducted to examine the effects of material response and the 

17 effect of not spatially adjusting the heat transfer coefficients obtained from RELAP results. To 

18 examine the effect of material behavior, analyses were conducted assuming only creep or 

19 plastic response. The earlier results were obtained using combined plasticity and creep 

20 response. Assuming only creep behavior accelerates the failure time to 12,140 s 

21 (Figure 4-43a), while assuming plasticity only delays the failure time to 13,205 s (Figure 4-43b). 

22 Assuming only plasticity behavior at the severe accident temperatures is not realistic. 

23 Additionally, the damage is predicted using creep rupture data. These two considerations 

24 coupled with the observation that the effective plastic strain in the HL region reaches values 

25 beyond 400 percent, invalidate the use of plasticity only model.
4-41

1

2

3 (a) Creep Response (b) Plasticity Response

4

5 Figure 4-43 Contours of through-thickness damage assuming (a) creep only 

6 behavior at 12,140 s and (b) plasticity only behavior at 13,025 s

7

8 The red-colored regions reach the creep damage of unity. Note that damage is predicted in 

9 different sections of the upper half of the HL.

10

11 The earlier analyses accounted for spatial adjustment of heat transfer coefficient obtained from 

12 RELAP, based on the developing curve given in NUREG-1922 (Ref. 2). The spatial adjustment 

13 increases the surface temperature inside the HL, which may accelerate failure. Thus, one 

14 would expect the failure time to be longer without the spatial adjustment. Figure 4-44 shows 

15 contours of through-thickness damage assuming no spatial adjustment of heat transfer 

16 coefficient obtained from RELAP. Failure is predicted at 12,610 s, which is 180 s longer than 

17 the result predicted with spatial adjustment of heat transfer.

18

19

20

21 Figure 4-44 Contours of through-thickness damage assuming no spatial adjustment of 

22 heat transfer coefficient obtained from RELAP

23 The red-colored regions reach the creep damage of unity.

24

25 4.4.6.1 Effect of Weld Overlay

26

27 The welded region between the HL nozzle and pipe could be prone to pressurized water stress28 corrosion cracking. One of the preventive methods to mitigate potential failure of the pipe 

29 during normal operation involves application of a weld overlay, in which additional material is 

30 welded over the pipe. This results in increasing thickness of pipe over the welded region. To 

31 examine the effect of the weld overlay in increasing the failure time during the severe accident 
4-42

1 sequence considered in the previous analyses, a HL model with an overlay was analyzed. The 

2 boundary conditions and thermal transient were identical to the previous analyses. Contours of 

3 through-thickness damage for the HL pipe with weld overlay, shown in Figure 4-45, indicate 

4 failure at 12,500 s. Note that the failure location is similar and the failure time is increased by 

5 72 s relative to the pipe with no weld overlay.

6

7

8

9 Figure 4-45 Contours of through-thickness damage for the HL pipe with weld overlay at 

10 12.500 s

11

12 Note that the failure location is similar to the pipe without a weld overlay. The failure time 

13 increases by 70 s relative to the pipe with no weld overlay.

14

15 4.5 Conclusions

16

17 4.5.1 SG Primary Manway

18

19 The bolt loads are fully relaxed by thermal creep, and the contact pressure in the joint was 

20 reduced to zero by the time the bolt temperature reached 450 degrees C (842 degrees F), 

21 which corresponds to 14,346 s. If 8 of the 16 bolts were initially loose (85-percent design 

22 preload), their loads would be relaxed out at 440 degrees C, or 824 degrees F (14,156 s). If the 

23 bolts were uniformly preloaded but if the creep rate were 10 times greater than the assumed 

24 reference creep rate, bolt loads would be relaxed out by 430 degrees C, or 806 degrees F

25 (13,975 s). These calculations are based on estimated creep rate data of alloys similar to SA 

26 193 (B7).

27

28 Rather than bolt rupture, a more likely sequence for the depressurization of the primary side is 

29 the lifting off of the cover plate after the bolt loads have relaxed out and created a leakage path 

for the steam. Considering a 5-cm (2-in.) diameter hole with an area 20 cm2 (3 in.2 30 ) to be 

31 sufficient to rapidly depressurize the primary side, a leakage area equivalent to such a hole is 

32 created in the reference case by 600 degrees C, or 1,112 degrees F (16,726 s). The actual flow 

33 area will be less because of gasket springback, which should be minimal at these temperatures 

34 because of thermal creep. However, gasket creep data at high temperature are needed to 

35 verify this.

36
4-43

1 Sensitivity analyses showed that the time to open a sufficiently large leakage area is virtually 

2 unchanged even if 8 of the 16 bolts were initially tightened to only 85 percent of the design 

3 preload. The opening time was also found to be strongly dependent on the bolt temperature. A 

4 simplified model of the effect of steam leakage on local heating of the bolts showed that the 

5 opening time could be reduced by more than 1,500 s relative to the reference case, which does 

6 not account for leakage effects. A more rigorous treatment of this problem must be obtained by 

7 a coupled thermal hydraulics and stress analysis in the future.

8

9 Finally, subsequent creep tests on SA 193-B7 have shown that the creep strains in the analysis 

10 were overestimated by a factor of 5 to 10. This would imply that the bolt load relaxation should 

11 be significantly less rapid than calculated here and the failure times calculated may be highly 

12 conservative (i.e., overestimated).

13

14 4.5.2 RTD Welds

15

16 A heat conduction FEA of the RTD, the ID and OD attachment welds to the HL, and an axial 

17 segment of the HL showed that the average ID weld temperature is 50–80 degrees C (122–

18 176 degrees F) hotter than the average OD weld temperature. The tip of the RTD scoop also is 

19 heated very rapidly to a high temperature.

20

21 Stress analysis showed that significant load is transferred between the ID and the OD welds 

22 because of creep effects. Inclusion of both creep and plasticity effects in the analysis showed 

23 that the initiation of tensile rupture failure is predicted to occur at the OD weld/RTD interface at 

24 13,930 s. On the other hand, if plastic yielding is suppressed, initiation of creep failure is 

25 predicted to occur at the ID weld/RTD interface at 13,890 s. Thus, regardless of which failure 

26 criterion is applied, the failure time is close to 13,900 s.

27

28 Sensitivity analysis showed that, when the outside heat transfer coefficients on the RTD are 

29 increased by a factor of 2 from the reference values, ignoring the internal surface heating on the

30 RTD, failure time is reduced by 184 s from the reference failure time. If the reference heat 

31 transfer coefficients are applied equally to both the outside and inside surfaces of the RTD, 

32 failure time is reduced by 100 s from the reference failure time. A factor of 10 increase in creep 

33 rate reduces the creep failure time by 180 s when compared with the reference failure time.

34

35 4.5.3 Instrument Line

36

37 The stress analysis showed that stresses at the weld interfaces with the instrument line and the 

38 RTD flange are at all times less than the yield strength. The reference creep failure time at both 

39 interfaces of the weld is 14,230 s. Because the maximum stress in the instrument line away from 

40 the weld is greater than the maximum stress in the weld, the instrument line itself fails at 14,150 s, 

41 which is 80 s earlier than failure at the interfaces.

42

43 Sensitivity analysis showed that, by doubling the weld dimensions, the average stresses are 

44 reduced significantly and the creep failure time is increased to 14,330 s. Increasing the creep 

45 rate by a factor of 10, when compared with the reference case reduces the failure times of the 

46 instrument line and the instrument line weld to 14,090 and 14,110 s, respectively.

47

48 4.5.4 PORV Plug-to-Cage Impact

49

50 Analysis of multiple impacts with 32-mm/s (1.25-in./s) impact velocity at 288 degrees C 

51 (550 degrees F) showed that, in the absence of the Stellite overlay on the plug, the maximum 
4-44

1 effective plastic strain in the plug increased from 3.8 percent in the first impact, to 6.4 percent in 

2 the second impact, and to 8.4 percent in the third impact. At 538 degrees C (1,000 degrees F),

3 the corresponding plastic strains were 4.1, 7.6, and 9.4 percent, respectively. The stress-plastic 

4 strain response showed no open hysteresis loop. The cage did not experience any plastic 

5 yielding. The plastic strains did not change if the plug impact velocity was doubled.

6

7 Inclusion of a 2-mm thick hard Stellite overlay on the plug suppressed plastic strain in the plug 

8 and in the overlay at 538 degrees C (1,000 degrees F). The cage did not suffer any plastic 

9 strain either.

10

11 Plastic strains will develop during impacts at higher temperature because both the cage material 

12 (17-4 PH steel) and the Stellite overlay will lose strength at temperatures greater than 

13 593 degrees C (1,100 degrees F). Stress-strain properties of the cage material and the Stellite 

14 overlay are needed at higher temperature so similar impact analyses may be conducted.

15

16 4.5.5 HL and Surge Line

17

18 The analyses presented in Section 4.4 indicate that the upper half of the HL will fail much earlier 

19 than the other RCS regions. The failure times predicted by the various analyses considered in 

20 Section 4.4 are summarized in Table 4-4. The predicted failure times for all the cases 

21 considered are below the 5th percentile failure time of 12,800 estimated by C-SGTR Calculator, 

22 assuming one HL. In addition, the fifth percentile failure time predicted by the C-SGTR 

23 calculator, assuming four HLs and a surge line, is 12,700 s. It is important to examine these 

24 results in the context of the assumptions. Firstly, the predicted values indicate the relative 

25 influence of various assumptions with respect to material behavior, such as creep and plasticity, 

26 spatial adjustment of heat-transfer coefficient, and weld overlay. Secondly, the predicted values 

27 fall within a narrow band of 500 s of predicted failure time. This is not surprising because after 

28 an initial slow rise, the temperatures rise sharply beyond 12,000 s, imparting significant damage 

29 to the hot-leg portion closer to the reactor pressure vessel nozzle. Hence, the various 

30 assumptions do not yield significantly different predicted failure times. It was pointed out earlier 

31 that the materials properties used in these simulations were restricted to temperatures below 

32 1,400 degrees K (1,126 degrees C or 2,060 degrees F), and that these materials will experience 

33 rapid high-temperature damage at temperatures above 1,400 K. This consideration implies that 

34 the actual failure times could be less than the predicted failure times. Nonetheless, this 

35 difference is not likely to be large because of the sharp rise in temperatures beyond 12,000 s.

36
4-45

1 Table 4-4 Summary of Predicted HL Failure Times for the Various Analyses

2

3

4

5 4.6 References

6

7 1. Brust, F.W., et al., “Summary of Weld Residual Stress Analyses for Dissimilar Metal 

8 Weld Nozzles,” Proceedings of ASME PVP conference, July 2010, paper PVP2010-

9 26106.

10 2. U.S. Nuclear Regulatory Commission, “Computational Fluid Dynamics Analysis of 

11 Natural Circulation Flows in a Pressurized-Water Reactor Loop under Severe Accident 

12 Conditions,” NUREG-1922, March 2010, Agencywide Documents Access and 

13 Management System (ADAMS) Accession No. ML110110152.

Finite Element Model Features Weld Overlay Failure Time (seconds)

Creep and Plasticity:

 HTC not adjusted spatially No 12560

Hot Leg Model

Creep and Plasticity:

Spatially Adjustment of HTC Yes 12500

Creep only:

Spatially Adjustment of HTC No 12140

System Creep and Plasticity:

Spatially Adjustment of HTC No 12300

Creep and Plasticity:

Spatially Adjustment of HTC No 12430

5-1

1 5. TECHNICAL BASIS FOR PREDICTING BEHAVIOR OF FLAWED SG 

2 TUBES IN SEVERE ACCIDENTS

3

4

5 5.1 Introduction

6

7 This report summarizes the technical basis for predicting ligament rupture pressure, crack 

8 opening area and unstable burst pressure of steam generator tubes with flaws under severe 

9 accident transients. The content of this report is based on research carried out by Argonne 

10 National Laboratory (ANL), Nuclear Engineering Division, under U.S. Nuclear Regulatory 

11 Commission (NRC) sponsorship and the results reported in NUREG/CR-6575, “Behavior of 

12 PWR Reactor Coolant System Components, Other than Steam Generator Tubes, under Severe 

13 Accident Conditions - Phase I Final Report,” and NUREG/CR-6756, “Analysis of Potential for 

14 Jet-Impingement Erosion from Leaking Steam Generator Tubes during Severe Accidents,” (Ref.

15 11 and 14).

16

17 To develop an understanding of the risks associated with steam generator (SG) tube rupture, 

18 the NRC contracted Argonne National Laboratory in 1995 to develop rupture pressure and leak 

19 rate correlations for tubes with flaws and validate them by conducting tests on tubes by 

20 subjecting them to pressures and temperatures associated with severe accident transients. The 

21 results from the ANL study were subsequently published in NUREG/CR-6575 and 

22 NUREG/CR-6756.

23

24 Operating experience with pressurized-water reactors (PWR) steam generators in both the 

25 United States and abroad has shown that cracks of various morphologies can and do occur in 

26 steam generator tubes, starting early in life. These may be single cracks that are axial or 

27 circumferential, inside diameter (ID) or outside diameter (OD) initiated, part-through-wall or 

28 through-wall, or the cracks could be multiple cracks that are parallel or form a network. Tests 

29 have shown that, depending on the location and morphology of these cracks, the SG tubes can 

30 be weakened to various extents.

31

32 Under normal operating conditions, the temperature in a steam generator is about

33 300 degrees C (572 degrees F) and the pressure across the tube wall, ∆pno, is about

34 9 megapascals (MPa) (1,300 pounds per square inch [psi]). Under design basis accidents such 

35 as a main steamline break in which the secondary side has dropped to atmospheric pressure, 

36 the pressure across the tube wall, ∆pMSLB, is 18 MPa (2,560 psi) and the temperature of the 

37 steam generator tubing is less than 350 degrees C (662 degrees F). In this temperature range, 

38 creep effects are negligible in Alloy 600. Degraded tubes must actually be capable of 

39 withstanding 3⋅∆pno ≈27 MPa (3,900 psi) and 1.4⋅∆pMSLB ≈25 MPa (3,660 psi) to meet 

40 requirements for continued operation. For typical unflawed steam generator tubes made of 

41 Alloy 600, the failure pressure, pb, at these temperatures is about 65 MPa (9,400 psi).

42

43 Severe accidents involving significant core damage are unlikely events in nuclear reactors. 

44 Even in the unlikely event that such an accident should occur, in most cases any potential risk 

45 to the public is mitigated by the presence of a robust containment. The behavior of SG tubing 

46 during such severe accidents is of particular interest, since failure of the steam generator tubes 

47 could lead to bypass of the containment. The accident sequences that appear to produce the 

48 greatest risk of steam generator tube failure are those in which the reactor pressure vessel fails 

49 to depressurize, but depressurization does occur on the secondary side. The NRC is pursuing 

50 studies to better understand the progression of such sequences, the temperature of the steam 
5-2

1 generator tubes during such accidents, and the behavior of steam generator tubes at the high 

2 temperatures associated with such accidents. At these high temperatures, plastic deformation 

3 is likely to be much more extensive than at normal reactor operating temperatures, and creep 

4 effects may no longer be negligible. The development and validation of models to describe the 

5 failure of flawed steam generator tubes at high temperatures was a major objective of the ANL 

6 study. The tests conducted and the models developed do not attempt to accurately simulate 

7 any particular severe accident scenario; rather they are intended to provide tools that can be 

8 used to determine failure under a broad range of pressure and temperature histories.

9

10 5.2 Ligament Rupture Pressure

11

12 5.2.1 Analytical Failure Models

13

14 There is substantial literature on the development and validation of analytical models to 

15 describe the behavior of flawed tubes at normal reactor operating temperatures 

16 288–320 degrees C (550–608 degrees F). These models and data can be used to analyze the 

17 potential for failure during design basis accidents, during which the temperature of the steam 

18 generator tubing is less than 350 degrees C (662 degrees F). In this temperature range, creep 

19 effects are negligible in Alloy 600. However, in postulated severe accidents, much higher 

20 temperatures are possible. At these higher temperatures, plastic deformation is likely to be 

21 much more extensive than at normal reactor operating temperatures, and creep effects can no 

22 longer be neglected. Until recently, there were no test data or validated models to predict the 

23 failure of flawed tubes at temperatures associated with postulated severe accidents.

24

25 5.2.1.1 Axial Cracks

26

27 5.2.1.1.1 Flow Stress Model

28

29 ANL developed two analytical models for predicting ligament rupture pressure of tubes with 

30 axial part-through-wall (PTW) flaws at elevated temperatures. The first one, based on flow 

31 stress theory, was obtained by slightly modifying an empirical stress magnification factor mp

32 (Ref. 6), which depends only on the geometry of the flaw and the tube but is independent of the 

33 flow stress of the tube material. The modified form of the mp factor developed by ANL is as 

34 follows:

35

36 (5.1)

37 where

38

39 a = crack depth

40 h = tube wall thickness

41 m = bulging factor used for predicting unstable burst pressure of tubes with through-wall 

42 (TW) axial cracks and is given by

43
5-3

1

2 where

3

4 2c = axial crack length

5 Rm = mean radius of the tube

6 ν = Poisson’s ratio

7

8 The ligament rupture (psc) and unstable burst (pcr) pressures are obtained by reducing the 

9 unstable burst pressure (pb) of the unflawed tube by dividing it by mp and m, respectively, i.e.,

10

11 and (5.2a)

12 (5.2b)

13

14 where , the flow stress of the material, is defined as an average of the yield and ultimate 

15 tensile strengths (σy+σu)/2 and the unstable burst pressure of the unflawed tube is given by

16

17 (5.2c)

18

19 Equations 5.2a and 5.2b have been validated at low temperatures by tests conducted at ANL on 

20 Alloy 600 tubes with axial EDM notches (Figures 5-1a and 5-1b). (An EDM notch is a 

21 mechanically simulated defect, which is made by removal of material with an electrostatic 

22 discharge machine (EDM).)

23

24 In the generalized flow stress model it is assumed that, for any arbitrary history of hoop stress 

25 σ(t) and temperature T(t), failure occurs at a temperature T and hoop stress σ whenever the 

26 following failure equation is satisfied, independent of stress-temperature history:

27
5-4

(a) (b)

1

2 Figure 5-1 Predicted vs. observed (a) ligament rupture pressures and (b) unstable 

3 burst pressures of Alloy 600 tubes with axial notches at room temperature

4

5 (5.3)

6

7 where is the flow stress at temperature T and mp is the stress magnification factor.

8

9 Flow stresses for Alloy 600 computed from above data together with others from various 

10 sources are plotted in Figure 5-2. Most of these tests were conducted under stroke-control at a 

11 nominal strain rate of 34 percent/min. Data from room-temperature tensile tests on the tubing 

12 being tested at ANL are also shown in Figure 5-2. The flow stress decreases markedly with 

13 temperature above 600 degrees C (1,112 degrees F). Note that although there may be a wide 

14 variation in the flow stress at low temperatures, the heat-to-heat and product form variations in 

15 the flow stress diminish rapidly with increasing temperature. The INEL flow stress curve, which 

16 covers the widest range of temperature, is used for failure predictions.

17
5-5

1

2

3 Figure 5-2 Flow stress curves for various product forms of Alloy 600

4

5 5.2.1.1.2 Creep Rupture Model

6

7 In the creep rupture model, creep failure of an unflawed tube under a varying stress and 

8 temperature history can be predicted by a relatively straightforward analysis (Ref. 5) based on a 

9 linear time-fraction damage rule, such as used in the ASME Code, Section III, Subsection NH, 

10 as follows:

11

12 (4a)

13

14 where tR is the time to creep rupture for a uniaxial specimen under a stress σ and temperature 

15 T, both of which may be functions of time, and tf is the time to failure of the tube. In the creep 

16 rupture model for flawed tubes it was assumed that failure can be predicted by the following 

17 equation:

18

19 (4b)

20

21 The available literature data on the creep rupture properties of Alloy 600 were reviewed. A 

22 least-squares best fit is shown in Figure 5-3 along with the estimated ±95 percent confidence 

23 limits.

24
5-6

1

2

3 Figure 5-3 Larson-Miller plot for Alloy 600 tubes

4

5 In equation form, the Larson-Miller parameter is given by

6

7 Plm = (23.2±0.7–2.4 lnσ) x 103 for σ > 5.7 ksi (5.4)

8

9 where the time to rupture tR is then given by

10

11 (5.5)

12

13 with tR in h and T in K.

14

15 5.2.1.2 Circumferential Cracks

16

17 5.2.1.2.1 Through-Wall Circumferential Cracks

18

19 Failure loads of tubes with a single circumferential crack critically depend on the bending 

20 constraint imposed externally on the tubes. The two extreme cases are the free-bending case 

21 and the fully constrained case. In reality, steam generator tubes are partially constrained 

22 against bending by tube support plates.

23

24 Free Bending Case

25

26 For an unconstrained (free-to-bend) tube with a through-wall crack of angular length 2θ, 

27 where θ is the circumferential angle of the tube cross section, and no applied primary bending 

28 stress, the critical failure pressure is (Ref. 12):

29
5-7

1 (7a)

2

3 where the angular location of the neutral axis is given by

4

5 (7b)

6

7 Fully Constrained Case

8

9 Equation 7a is applicable to one extreme case, where the tube is completely free to bend. In 

10 the opposite extreme case of total constraint against bending, a criterion based on maximum 

11 shear stress in the net section (Ref. 1) can be used to calculate the instability limit pressure:

12

13 (8a)

14

15 where

16

17 (8b)

18

19 The following thin-shell, uniaxial approximation to Equation 8a is often used to predict failure of 

20 steam generator tubes that are fully constrained against bending:

21

22 (8c)

23

24 In reality, the tube support plates offer significant but not total restraint against bending, a 

25 circumstance that tends to increase the failure pressure to somewhere between the pressure 

26 those predicted by Equations 7a and 8a (or 8c).

27

28 5.2.1.2.2 Part-Through-Wall Circumferential Cracks

29

30 Consider a tube with mean radius Rm and wall thickness h, that contains either two symmetrical 

31 part-through circumferential cracks (SC) (Figure 5-4a) or a single part-through circumferential 

32 crack (Figure 5-4b) of angular length 2θ and depth a. At low temperatures, where creep effects 

33 are negligible, the ligament failure pressure (psc) is generally expressed in terms of a stress 

34 magnification factor (mp) by equating the magnified axial stress in the ligament to the flow 

35 stress,

36

37 (5.6)

38

39
5-8

1 Failure pressure for circumferentially cracked tubes (i.e., the value of the stress magnification 

2 factor mp), depends strongly on the degree of restraint the tubes are subjected to against 

3 bending. The two extreme cases, i.e., the free-bending case and the completely constrained 

4 case are relatively easy to analyze. Generally, steam generator tubes are sufficiently 

5 constrained laterally that the failure loads are expected to be much closer to the completely 

6 constrained case than the free-bending case. The discussion here assumes that the tubes are 

7 either completely constrained or are completely free to bend.

8

(a) (b)

9

10 Figure 5-4 Stress distributions through section at failure of tubes with (a) two symmetrically 

11 located part-through circumferential cracks and (b) single part-through circumferential 

12 crack

13

14 Fully Constrained Case

15

16 The fully constrained case would also include the case for an unrestrained tube that contains 

17 two symmetrical cracks (Figure 5-4a). In this case, the whole section that contains the crack (or 

18 cracks) is subjected to axial tensile stress, with the ligament (or ligaments) being subjected to 

19 stress intensification. If the average stress in the ligament (or ligaments) is expressed as 1/m 

20 times the average stress in the rest of the section that contains the crack (or cracks), the 

21 average ligament axial stress (σlig) can be calculated from a simple equilibrium of axial forces,

22

23 (10a)

24

25 where

26

27

28

29 Defining mp as the ratio of the average ligament axial stress and the average axial stress in the 

30 unflawed tube, mp is given by

31
5-9

1 (10b)

2

3 Originally, the following empirically obtained expression was used (Ref. 10).

4

5 (11)

6

7 (with n =1 ).

8

9 Although Kurihara recommended values of κ = 2 and μ = 0.2 for the exponents, the results are 

10 almost indistinguishable from those obtained by using κ = 3 and μ = 0.3. Because the behavior 

11 of Equation 11 is not correct (i.e., m does not tend to 0) when a/h tends to 1 for all θ, it was 

12 modified to have the same form as in the case of axial cracks, i.e.,

13

14 (12a)

15

16 where

17

18 (12b)

19

20 and λ and γ are fitting parameters.

21

22 Both the failure modes and moments of the original set of test data from four-point bending 

23 failure tests on pressurized part-through circumferentially cracked Type 304 stainless steel 

24 pipes at room temperature (used by Kurihara) can be predicted somewhat better by the current 

25 model with λ = 0.2 and γ = 0.2 and by defining the flow stress as 0.55[σy + σu], see Equation 1c 

26 than by the Kurihara model (see Figures 5-5a and 5-5b).

27

28 For unsymmetrical part-through circumferentially cracked 165.2-mm diameter (11-mm wall 

29 thickness) pipe specimens subjected to four-point bend test with constant internal pressure of 

30 6.9 MPa (1,000 psi) at room temperature). Dashed lines denote predicted failure bending 

31 moments for through-wall cracks; open symbols denote tests that failed by leakage, and filled 

32 symbols denote those that failed by breaking into two pieces.

33
5-10

(a) (b)

1

2 Figure 5-5 Variations of experimental failure bending moments with crack angle and those 

3 predicted by (a) Kurihara model and (b) ANL model

4

5 Free-Bending Case

6

7 Figure 5-4b shows that, in the free-bending case, part of the section that contains the crack will, 

8 in general, be subjected to compressive stress. As a result, Equation 10a must be replaced by

9

10 (13a)

11

12 where the angle β that defines the location of the neutral axis is given by

13

14 (13b)

15

16 and Equation 10b has to be replaced by

17

18 (13c)

19

20 with m and N defined by Equations 12a and 12b, respectively.

21

22 5.2.2 Validation Tests for Ligament Rupture

23

24 5.2.2.1 Validation Tests for Axial Notches

25

26 Seventy-three tests designed to validate the ANL creep rupture model were carried out in the 

27 high-temperature test facility using three types of loading histories. The tests were conducted 

on 19.1-mm (3

/4-in.) and 22.2-mm (7 28 /8-in.) diameter Alloy 600 tubes that contained a variety of 
5-11

1 EDM flaws. Such flaws are typically 0.0203 centimeter (cm) (0.008 inch [in.]) wide and are not 

2 as sharp as real cracks, but previous tests at lower temperatures have shown that the failure 

3 pressures of specimens with corrosion cracks are at most about 10 percent less than those 

4 predicted by failure correlations developed from specimens with machined flaws (Ref. 8). At 

5 higher temperatures, because of crack tip blunting, the effect of the initial crack tip geometry 

6 would be expected to be of even less significance.

7

8 Measurement of Axial Flaw Depth

9

10 The flaw depth and length are critical parameters in calculating the expected failure pressures of 

11 the tubes, and these dimensions must be determined as precisely as possible. The accurate 

12 determination of the flaw depths, in particular, poses some difficulties. Four methods were 

13 developed to measure the depths of the machined flaws. Two of these methods are applicable 

14 to the specimens before testing, one is performed after testing, and the fourth method is 

15 destructive and thereby precludes subsequent pressure testing of the specimen.

16

17 The first technique used to measure flaw depth was posttest fractography. In this method, the 

18 fracture surfaces of the failed specimen are photographed at a known magnification after the 

19 test, and the contrast between the machined portion of the fracture surface and the region of 

20 subsequent ductile fracture in the photograph permits a reasonably accurate determination of 

21 flaw depth.

22

23 The second technique used to measure flaw depth was replication of the pre-machined flaws. 

24 In this technique, a plastic replica was made of the flawed region of the specimen before testing, 

25 and the height of this replica, which corresponds to the depth of the flaw, was then determined 

26 by optical microscopy.

27

28 A third technique is to directly measure the flaw depth before testing with a traveling optical 

29 microscope that gives a digital readout of the x, y, and z positions of the objective lens. The 

30 flaw depth can be measured by focusing first on the outer surface of the specimen and then on 

31 the bottom of the machined flaw. The flaw depth corresponds to the movement of the 

32 microscope objective between these two steps; readings accurate to within about ±2,500 μm 

33 (±0.1 mil) are possible.

34

35 A fourth technique for determining flaw depth is destructive metallography of the flawed tube. 

36 The tube is simply sectioned through the flaw, and the depth at that position is determined from 

37 a microphotograph.

38

39 All four of these techniques were employed in the ANL program, and the results are listed in a 

40 table in NUREG/CR-6575 (Ref. 11). Aside from one invalid measurement, the agreement 

41 among the various techniques for these flaws was quite good. The largest variation in 

42 measured flaw depth was 0.02 mm (0.9 mils), or about 6-percent variation between the values 

43 measured by pretest optical microscopy and posttest metallography. In general, the flaw depth 

44 values obtained by replication are slightly greater than those obtained by posttest fractography; 

45 the pretest microscopy determinations agree reasonably well with the values obtained by 

46 replication. Because the posttest fractography values represent the only consistent set of 

47 values for all of the specimens, these are the flaw depth values that have been used in the 

48 analysis and modeling of the tests.

49
5-12

1 5.2.2.1.1 Constant Temperature/Pressure Rupture Tests

2

3 Unflawed tubes, tubes with shallow notches (55–65 percent deep, 1 in. long) and tubes with 

4 deep notches (90 percent deep and 0.25–2 in. long) were tested under constant pressure and 

5 constant temperature condition until failure. The unflawed tubes were tested at 

6 700–800 degrees C (1,292–1,472 degrees F) and 12.4–31.0 MPa (1.8–4.5 kilopound per 

7 square inch [ksi]). The shallow notches were tested at 667–800 degrees C (1,233–

8 1,472 degrees F) and 9.6–31 MPa

9 (1.4–4.5 ksi) pressure and the deep notches were tested at 800 degrees C (1,292 degrees F) 

10 and 2.1–3.1 MPa (0.30–0.45 ksi). The unflawed tubes and the tubes with shallow notches burst 

11 in an unstable manner with large crack opening and notch tip tearing. The predicted ligament 

12 rupture pressures of the tubes with shallow notches were greater than the burst pressure of the 

13 100 percent TW notches with the same length, thus precipitating burst immediately after 

14 ligament rupture. There was enough strain energy stored in these specimens which could drive 

15 them to burst even though the pump could not maintain the pressure after ligament rupture.

16 The deep flaws failed by ligament rupture with very little crack opening and stored energy. 

17 Figure 5-6 shows a plot of the predicted (creep rupture model) vs. observed failure pressures of 

18 the specimens. In all cases, the failure pressures are predicted to within ±95 percent prediction 

19 limits. It should be noted that the flow stress model is incapable of predicting time to failure for 

20 tests of this type and, in fact, would predict that none of the tubes should have failed.

21

22

23

24 Figure 5-6 Predicted vs. observed time to failure of flawed and unflawed tubes under 

25 constant temperature and pressure condition

26

27 5.2.2.1.2 Pressure and Temperature Ramp Tests

28

29 To evaluate the importance of loading rates on the failure conditions and compare the predictive 

30 capabilities of the creep rupture model and the flow stress model, two additional types of tests 
5-13

1 were conducted. In the first type, the specimens were heated to a temperature and then 

2 pressurized isothermally at a constant pressure ramp until failure. In the second type, the 

3 specimens were first pressurized at low temperature and then, with the pressure held constant, 

4 they were subjected to a constant temperature ramp until failure.

5

6 5.2.2.1.3 Pressure Ramp Tests

7

8 Eleven pressure ramp tests were conducted on notched and unnotched specimens. Most of the 

9 tests were conducted at a pressure ramp of 16 MPa/min (2.3 ksi/min) while the specimens were 

10 held at a constant temperature. The test temperature varied between 700 and 840 degrees C

11 (1,292 and 1544 degrees F). Two tests were conducted at 1.6 MPa/min (0.23 ksi/min) on 

12 unnotched specimens. Figures 5-7a and 5-7b show plots of the observed failure pressures vs. 

13 failure pressures predicted by creep rupture model and flow stress model, respectively. For 

14 both ramp rates, the creep rupture model gives a more consistent and accurate predicted failure 

15 pressures than the flow stress model.

16

(a) (b)

17

18 Figure 5-7 Predicted vs. observed failure pressures for isothermal (700–840 °C) pressure 

19 ramp tests on unflawed and flawed tubes 0.25–1 in. long and 65–80 % deep by (a) creep 

20 rupture model and (b) flow stress model

21

22 Figure 5-8 shows a plot of the same set of data but plotted as effective flow stress (i.e., mp x σh

23 at failure) vs. test temperature. Figure 5-8 also includes a flow stress vs. temperature plot (solid 

24 line) obtained from conventional tensile tests. Note that the experimentally derived effective 

25 flow stress increases with the ramp rate and the flow stress model using the flow stress curve 

26 (from tensile tests) would under-predict the failure pressures significantly. Figure 5-8 clearly 

27 demonstrates that for the flow stress model to be able to predict the failure pressures correctly, 

28 the flow stress curve has to be a function of the ramp rate. On the other hand, the rate effect is 

29 automatically taken into account by the creep rupture model.

30
5-14

1

2

3

4 Figure 5-8 Effective flow stress curves (dashed lines) computed from the pressure ramp 

5 tests (symbols) vs. temperature of test

6 Also shown is the standard flow stress curve of Alloy 600 (solid curve).

7

8 5.2.2.1.4 Temperature Ramp Tests

9

10 Thirteen flawed and unflawed specimens were tested at various temperature ramp rates. The 

11 flaw lengths in the tests varied from 0.64–5.1 cm (0.25–2 in.) and the flaw depths varied from 

12 65–93 percent. Three temperature ramp rates were chosen, 0.2, 2 and 20 degrees C/min. 

13 During the tests, the specimens were held at constant pressures ranging from 1.38–16.20 MPa

14 (0.22–2.35 ksi). A comparison of the observed failure temperatures with those predicted by the 

15 creep rupture and flow stress models is shown in Figures 5-9a and 5-9b, respectively. It is 

16 evident that the creep rupture model predicts the failure temperatures much more accurately 

17 than the flow stress model.

18

19 Two notched tests were specifically designed such that the product of mp and the nominal hoop 

20 stresses were approximately equal. Thus, the predicted failure temperatures for both 

21 geometries fall approximately on a single line for either the creep rupture or flow stress models, 

22 as shown in Figure 5-10. The experimental results are in much better agreement with the 

23 predictions of the creep rupture model and confirm that the effect of flaws on failure can be 

24 characterized by the mp approach. Therefore, the creep rupture model can be expected to 

25 predict failure under varying temperature and pressure histories during severe accidents more 

26 reliably than a simple rate-independent flow stress model.

27
5-15

(a) (b)

1

2 Figure 5-9 Comparison of observed failure temperatures with those predicted by (a) creep 

3 rupture model and (b) flow stress model for temperature ramp tests

4

5

6

7 Figure 5-10 Comparison of predicted failure temperatures by the creep rupture and flow 

8 stress models for flawed specimens as a function of temperature ramp rate

9

10 5.2.2.1.5 Tests under Simulated Severe Accident Time-Temperature Histories

11

12 Finally, tests were performed at ANL to determine the behavior of flawed tubes under 

13 time/temperature histories similar to those projected to occur under severe accident conditions. 

14 The purpose of the tests was to provide further validation for the creep rupture model to support 

15 its use to determine the time to failure of flawed tubes under projected time/temperature 

16 histories that could reach temperatures as high as 850 degrees C (1,562 degrees F).

17
5-16

1 In all the tests, the internal pressure was held constant at 16.2 MPa (2,350 psi). Tests were 

2 conducted on both 19.1-mm (3/4-in.) and 22.2-mm (7/8-in) diameter tubes with wall thicknesses 

3 1 mm (0.043 in.) and 1.3 mm (0.050 in.), respectively. Four different nominal flaw geometries 

4 with axial lengths 6 mm (0.25 in.), 25 mm (1 in.), and 50 mm (2 in.) and depths varying from 

5 20 percent to 65 percent of thickness were tested. Duplicate tests were run for all the 22.2-mm 

6 (7/8-in.) diameter tube tests. Rupture tests were also run on unnotched virgin samples.

7

8 For the tests, two time/temperature histories were considered. Both were based on preliminary 

9 analyses of an accident sequence involving total station blackout (SBO) with a stuck-open 

10 steam generator secondary-side atmospheric dump valve, resulting in loss of feed water and 

11 secondary-side depressurization. One, which is referred to as the “INEL ramp,” was based on a 

12 preliminary analyses by INEL and the other, referred to as the “EPRI ramp,” was based on a 

preliminary analysis reported by EPRI. The time-temperature scenarios calculated by INEL 1 13

and EPRI 2 14 for some postulated severe accident sequences are shown in Figure 5-11a and 

15 5-11b, respectively, which also show the time-temperature histories used in the ANL tests. In 

16 both series of tests, the specimens were first heated rapidly to 300 degrees C (572 degrees F), 

17 equilibrated at 300 degrees C (572 degrees F), and then subjected to the test ramps. Both 

18 analyses also predict depressurization of the system because of the failure of the surge line. 

19 Because the primary purpose of the tests was to help develop a failure model, the tests have 

20 ignored the predicted depressurization. The EPRI analysis also predicts a reduction in 

21 temperature following a short 5 min hold at 667 degrees C (1,232 degrees F). To increase the 

22 contribution of creep damage in the tests, the “EPRI” temperature history was arbitrarily 

23 modified to include a 2-hour holdtime at 667 degrees C (1,232 degrees F) and ignored the 

24 predicted reduction of temperature after the hold. If the specimen did not fail in 2 hours of 

25 constant temperature hold, it was subjected to a temperature ramp of 2 degrees C/min until 

26 failure. Neither ramp chosen for the tests was intended to be an accurate representation of a 

27 particular sequence, but together they can represent a range of histories for which a failure 

28 model would be needed. Thus, although the INEL and EPRI analyses predict that failure of the 

29 surge line nozzle and consequent depressurization of the system will occur before the failure of 

30 the steam generator tubes with or without flaws, the tests at ANL were continued with full 

31 pressure until failure occurred.

32

33 Figures 5-12a and 5-12b show comparison of the observed vs. predicted failure temperatures 

34 (calculated by the flow stress and creep rupture models). The creep rupture model gives a 

35 uniformly more accurate prediction of the failure temperatures than the flow stress model. 

36 Again, the difference in prediction between the two models arises because the creep rupture 

37 model includes rate effects, which are ignored by the flow stress model.

38

 1 P. G. Ellison, et. al, “The Risk Significance of Induced Steam Generator Tube Rupture,” INEL-95/0641, Rev. 1 

 (Draft), Lockheed Martin Idaho Technologies, Inc., Idaho National Engineering Laboratory, December 15, 1995. 2 E. L. Fuller, et. al, “Risks from Severe Accidents Involving Steam Generator Tube Leaks or Ruptures,” EPRI TR-

 106194, Electric Power Research Institute, Palo Alto, CA (to be published).
5-17

(a) (b)

1

2 Figure 5-11 Calculated and ANL simulation of (a) INEL ramp and (b) EPRI ramp for high3 temperature tests

4

5 (a) (b)

6

7 Figure 5-12 Observed vs. predicted failure temperatures by (a) creep rupture model and 

8 (b) flow stress model for tests simulating severe accident transients

9 Tests were conducted on 0.75 in. (19 mm) as well as 0.875 in. (22 mm) diameter Alloy 600 

10 tubes.

11

12 5.2.2.2 Validation Tests for Circumferential Notches

13

14 In contrast to axial cracks, only 15 failure tests with part-through circumferential cracks were 

15 conducted. These tests had a single loading history that consisted of a constant internal 

16 pressure of 16.2 MPa (2,350 psi) and a temperature ramp of 10 degrees C/min from 

17 300–600 degrees C, followed by a temperature ramp of 2 degrees C/min to ligament failure. As 

18 in the case of axial cracks, all specimens were depressurized immediately after ligament failure.

19

20 Constraint to bending was simulated by testing specimens with two symmetrically located 

21 cracks (Figure 5-4a). Tests were also conducted on unconstrained tubes with a single 

22 circumferential crack. In all but one case, the crack opening at failure was significantly smaller 

23 than the openings observed for axial cracks. The only exception was a single tube with a 
5-18

1 360-degree crack; this tube broke into two pieces. Most tests failed by developing pinhole leaks 

2 in the ligament. A single tube with a 240-degree crack failed by ligament failure across the 

3 whole front of the flaw.

4

5 As expected, all of the tubes with symmetrical flaws failed without significant bending. Tubes 

6 with deep flaws showed little or no bulging of the section that contained the flaws; those with 

7 shallower flaws showed some bulging. In contrast, all of the specimens with a single crack 

8 showed significant bending at failure (Ref. 11).

9

10 5.2.2.2.1 Tubes with Two Symmetrical Circumferential Flaws

11

12 Specimens with cracks of angular length 2θ = 90 degrees, 120 degrees, 150 degrees, and 

13 180 degrees (which is a full 360-degree crack) were tested. To keep the effects of crack length 

14 separate from the effects of crack depth, the depth to thickness ratio a/h was kept approximately 

15 constant at 0.77 for most of the test specimens.

16

17 The failure temperatures are plotted against the flaw length 2θ in Figure 5-13. Because of the 

18 variability of the crack depth around the circumference, the specimens with 360 degrees

19 (2θ = 180 degrees) cracks showed the largest scatter. However, the specimens with the 

20 highest failure temperature contained the shallowest cracks. The failure temperatures 

21 increased significantly when the crack depth was reduced at any angular crack length.

22

23

24

25 Figure 5-13 Variation of failure temperatures with crack angle for specimens with 

26 two symmetrical cracks of various depths

27

28 The failure temperatures for the tests were predicted by Equations 4b and 10b for mp. The mp

29 values were calculated with both the Kurihara model (Equation 11) and the ANL model 

30 (Equations 12a and 12b). The predicted failure temperatures are presented with the 

31 experimentally observed failure temperatures in Figure 5-14. On average, the ANL model gives 

32 a closer prediction of the failure temperatures than the Kurihara model. The maximum error in 

33 predicted failure temperature for the ANL model is 43 degrees C (109 degrees F).

34
5-19

1

2

3 Figure 5-14 Experimental failure temperatures and failure temperatures predicted by the 

4 Kurihara and ANL models for two symmetrical part-through circumferential cracks of 

5 various semiangular length θ

6

7 5.2.2.2.2 Tubes with a Single Circumferential Flaw

8

9 Three failure tests were conducted on free-to-bend specimens with a single circumferential flaw 

10 (Ref. 11). Specimens with cracks of angular length 2θ = 90 degrees, 180 degrees, and 

11 240 degrees were tested.

12

13 The failure temperatures for the tests were predicted by Equation 16b, with mp given by 

14 Equation 13c. The mp values were calculated with the ANL model (Equations 12a and 12b). 

15 The predicted failure temperatures were close to the experimentally observed failure 

16 temperatures in all cases (Ref. 11).

17

18 5.2.2.2.3 Comparison of Failure of Tubes with a Single Flaw and with Two Flaws

19

20 The failure of tubes with two symmetrical cracks was usually initiated on the crack with the 

21 greater depth. However, very little overall bending of the specimen occurred. Conversely, 

22 significant bending occurred in the specimens with a single crack. The longer the crack the 

23 more bending the specimen sustained.

24

25 All but one specimen with a 360-degree crack failed by ligament failure. A single specimen out 

26 of three with 360-degree cracks broke into two pieces. In most cases, ligament failure occurred 

27 locally, leading to a pinhole leak. One specimen with a single 240-degree crack failed by full 

28 ligament failure (accompanied by a loud noise). However, because of rapid depressurization of 

29 the specimen, the resulting through-wall crack did not propagate unstably to give rise to a 

30 guillotine break.

31

32 To demonstrate the influence of bending on failure pressure, the test results from both types of 

33 specimens are plotted against the total angular crack length (n = 2θ) in Figure 5-15. Note that 

34 the specimens with 360-degree cracks may be considered either as specimens with a single 

35 360-degree crack (n = 1) or two 180-degree cracks (n = 2). Thus the failure temperatures for 

36 both types of cracked specimens coincide at n = 2θ = 360 degrees. However, at smaller angles, 
5-20

1 the free-to-bend specimens failed at lower temperatures than the specimens with two 

2 symmetrical cracks, as expected.

3

4

5

6 Figure 5-15 Failure temperatures for specimens with one (n = 1) and two (n = 2) 

7 circumferential cracks

8

9 5.3 Crack Opening Rate at High Temperature

10

11 To determine the leak rate after through-wall penetration of axial cracks during severe 

12 accidents, it is necessary to estimate the crack-opening area as a function of time. A simple 

13 model was developed to calculate the crack-opening area as a function of time and temperature 

14 during severe accidents. It is derived by analogy from a model that is applicable to cracks in a 

15 rectangular plate. The model was used to analyze crack opening areas in flawed tubes 

16 subjected to severe-accident transients.

17

18 Consider a through-wall central crack of length 2c in a rectangular plate of width 2b (b>>c) 

19 subjected to a remotely applied axial load P. For a material with stress-plastic strain law

20

21 (14)

22

23 the crack-opening displacement at the middle of the crack, ignoring elastic displacement, is 

24 given by9

25 (15)

26

27 In Equation 15, P0 = plastic collapse load and the function h2 is tabulated in Reference 13 

28 (EPRI-NP-1931). Equation 15 was applied to the case of an axial crack in a relatively long 

29
5-21

1 steam generator tube by replacing the remote stress with the nominal hoop stress σ = , (R 

2 and h are the mean radius and thickness of the tube and ∆p is the pressure differential), the 

3 collapse stress with σ0/m (m is the bulging factor) and by putting c/b = 0, i.e.,

4

5 (16)

6 Equation 16 is expected to give reasonable estimates of crack-opening displacements as long 

7 as the pressure is small compared to the unstable burst pressure.

8

9 Equation 16 can be generalized for the high-temperature creep case as follows. If the material 

10 obeys a power law creep rate equation, i.e.,

11

12 (17)

13

14 then the crack opening rate is given by analogy with Equations 14 and 16 as follows:

15

16 (18)

17

18 5.3.1 Creep Rate Equation for Alloy 600

19

20 Creep rate data obtained by INEL are plotted in Figure 5-16. The data at three temperatures 

21 can be collapsed onto a bilinear plot (log-log basis) by using activation energy of 65 kcal/mole 

22 and plotting the stress normalized by the Young’s modulus at temperature, as shown in 

23 Figure 5-16.

24

25

26

27 Figure 5-16 INEL creep rate on Alloy 600 vs. stress data plotted using activation energy of 

28 65 kcal/mole and stress normalized by Young’s modulus at temperature

29
5-22

1 5.3.2 Crack Opening Area for Axial Cracks

2

3 The function h2 (c/b, n) is plotted as a function of c/b for three values of n in Figure 5-17a. Since 

4 our interest is in the value of h2(0,n), the graphs were extrapolated to c/b = 0 by polynomial fits 

5 and the results plotted as a function of n in Figure 5-17b.

6

(a) (b)

7

8 Figure 5-17(a) Variation of h2 (c/b,n) with c/b for various values of n

9 Figure 5-17(b) Variation of h2 (0,n) with n

10 Values of h2 (0,n) are 7.03 and 6.16 for n = 6.1 and 3.7, respectively.

11

12 5.3.3 Tests on Specimens with Circumferential Notches at High Temperature

13

14 Because in a tube under internal pressure, the crack opening area for a given crack length is 

15 much greater for an axial crack than it is for a circumferential crack, the primary interest is in 

16 axial cracks. It is, however, extremely difficult to carry out creep tests on tubular specimens with 

17 through-wall axial notches subjected to internal pressure. The validation tests were conducted 

18 instead on axially loaded tube specimens with two symmetrical through-wall circumferential 

19 EDM notches (Figure 5-18a). The symmetrical notches minimize bending and assure a pure 

20 tensile loading on the notches similar that experienced by axial cracks in an internally 

21 pressurized tube. By keeping the notch lengths small, the effects of tube curvature can be 

22 minimized. The small interaction between the two notches can be taken into account by using 

23 equations applicable to cracks in rectangular plates of finite width (Figure 5-18b).

24

25 As mentioned earlier, the periodicity of the circumferential crack geometry requires that the 

26 corresponding rectangular plate be of finite width (Figure 5-18b). The crack opening 

27 displacement (COD) of cracks in plates of finite width is given by Equation 16. For the current 

28 geometry, the remotely applied axial load P = 2πRhσ and the plastic collapse load P0 = 2(π29 2θ)Rhσ0, and Equation 16 reduces to the following:

30

31 (19)

32
5-23

1 where σ is the remotely applied axial stress, 2θ is the angular length of each circumferential 

2 crack, R and h are the mean radius and thickness of the tube, and

3

4 (c/b=0.25 for 45° cracks) (20)

5

(a) (b)

6

7 Figure 5-18(a) Tube with two symmetrical through-wall circumferential notches

8 Figure 5-18(b) Axial loading on a tube with two symmetrical 45 ° notches plotted after 

9 making an axial cut and unfolding the tube circumference into a plane

10

11 As before, under creep conditions, Equation 19 by analogy gives an expression for the 

12 displacement rate,

13

14 (21)

15

16 The variation of the function h2 (c/b, n) with c/b is shown in Figure 5-19 for two values of n 

17 applicable to Alloy 600. Note that, in contrast to axial cracks that were considered earlier, 

18 c/b ≠ 0 for the circumferential notches.

19
5-24

1

2

3 Figure 5-19 Variation of h2 with c/b for creep rate exponents n = 3.7 and 6.1

4

5 5.3.3.1 Validation Test Results

6

7 Six isothermal and nonisothermal tests were conducted to validate the approach. Two tests 

8 with 45-degree circumferential EDM notches were first conducted. The predicted notch opening 

9 with time for two symmetrical 45-degree circumferential cracks at two applied axial loads is 

10 compared with the experimentally observed notch opening in Figures 5-20a and 5-20b. The 

11 test under an axial load of 1,106.8 kgf (2,440 lbs.) (Figure 5-20a) was started initially at 

12 695 degrees C (1,283 degrees F), but changed to 685 degrees C (1,265 degrees F) after 

13 1 hour. The test under an applied axial load of 1,224.7 kgf (2,700 lb) (Figure 5-20b), was 

14 conducted at 665 degrees C (1,229 degrees F) with less variation in temperature. The 

15 agreement between experimentally measured notch openings and predicted values is 

16 reasonably good.

17

(a) (b)

18

19 Figure 5-20 Experimentally measured and predicted variation of total notch opening with 

20 time for specimens with 2 × 45° circumferential notches loaded at (a) 1,106.8 kgf (2,440 lb) 

21 and (b) 1,224.7 kgf (2,700 lb)
5-25

1

2 The temperature control of the specimen was improved subsequently. The next series of tests 

3 involved 2 x 0.635 cm (0.25 in.) and 2 x 0.508 cm (0.20 in.) circumferential notches subjected to 

4 an axial load of 1,089 kg (2,400 lb) at a constant temperature of 700 degrees C

5 (1,292 degrees F). Figures 5-21a and 5-21b show a comparison between measured and 

6 predicted notch opening with time for specimens with two symmetrical circumferential notches 

7 of length 0.635 cm (0.25 in.) and 0.508 cm (0.20 in.), respectively, each subjected to an applied 

8 axial load of 1,106.8 kgf (2,400 lbs.). As before, the predicted openings are close to the 

9 measured values.

10

(a) (b)

11

12 Figure 5-21 Experimentally measured and predicted variation of total notch opening with 

13 time for specimens with 2 symmetrical circumferential notches loaded at 1,108 kg 

14 (2,400 lb) for notch lengths (a) 6.35 mm (0.25 in.) and (b) 5.1 mm (0.20 in.)

15

16 All the tests reported so far were conducted isothermally. To validate the model for 

17 nonisothermal loading, two tests were conducted in which the temperature was ramped 

18 following the Case 6RU transient (Figure 5-22). In the nonisothermal tests the displacements 

19 could only be measured at the end of the test. Both nonisothermal tests had a constant axial 

20 load of 1,362 kg (3,000 lb). Test CR 106 had 2 x 6.35 mm (0.25 in.) circumferential notches and 

21 Test CR 108 had 2 x 5.1 mm (0.20 in.) circumferential notches. The predicted notch opening 

22 displacement vs. temperature plots for the two tests are given in Figures 5-23a and 5-23b, 

23 which also include the measured notch opening displacements at the end of the tests. One of 

24 the predicted notch openings is close to the measured value, and the other one is off by 

25 20 percent.

26
5-26

1

2

3 Figure 5-22 Time vs. temperature plot for tests CR 106 and CR 108

4 The curve for CR 108 has been displaced in the horizontal direction for clarity.

5

(a) (b)

6

7 Figure 5-23 Comparison of predicted (solid line) and experimentally measured (symbols) 

8 notch opening displacements for (a) Test CR 106 and (b) Test CR 108

9

10 5.3.4 Predicted Axial Crack Opening Rate at High Temperature

11

12 The variation of crack opening rate with crack length calculated with Equation 18 is shown in 

13 Figure 5-24a for steam generator tubes at 700 degrees C (1,292 degrees F) subjected to 

14 internal pressure of 16.2 MPa (2,350 psi). Note that the crack opening rate increases very 

15 rapidly for crack lengths greater than 10 mm (0.4 in.).

16

17 The crack opening area at temperatures of 700 and 750 degrees C (1,292 and 

18 1,382 degrees F) as a function of crack length for an SG tube subjected to a thermal transient 

19 characteristic of SBO “high-dry” accident (Case 6RU in Reference 15) is shown in Figure 5-24b. 

20 Note that for temperatures greater than or equal to 750 degrees C (1,382 degrees F), cracks 

21 greater than 15 mm (0.6 in.) long will have crack opening areas that are greater than the tube 
5-27

1 cross-sectional flow area (303 square millimeters [0.47 square inch] for a 22.2-millimeter

2 [0.875-inch] diameter tube).

3

(a) (b)

4

5 Figure 5-24 Variations of (a) crack opening displacement rate with through-wall axial crack 

6 length for a tube subjected to internal pressure of 2,350 psi at 700 °C and (b) crack opening 

7 area with crack length at final temperatures 700 and 750 °C for a tube subjected to severe 

8 accident transient

9

10 5.4 Stability of Flaws after Ligament Rupture

11

12 To address the question of stability of part-through cracks after ligament failure, two specimens 

13 were fabricated with 12.7-mm (0.5-in.) through-wall cracks and with inside metallic liners to act 

14 as patches to prevent leakage of the pressurizing gas. It was hoped that the metallic liner would 

15 transmit the pressure to the tube wall by creep. In the first specimen, a 0.25-mm (0.01 in.) thick 

16 pure nickel liner was used. It was first heated to 850 degrees C (1,562 degrees F) and then 

17 pressurized at a rate of 7 MPa/min (1,000 psi/min). The nickel liner developed a pinhole under 

18 the crack at a pressure of 10.3 MPa (1,500 psi), just as the cracked section of the tube started 

19 to bulge. The predicted instability pressure for the tube was 16 MPa (2,300 psi). A second 

20 specimen, also with a 12.7-mm (0.5-in.) through-wall crack, but with a 0.2-mm (0.008-in.) thick 

21 Type 304 SS liner was heated to 750 degrees C, (1,382 degrees F) pressurized to 16.2 MPa 

22 (2,350 psi), and then held. This specimen also developed a leak because of failure of the 

23 stainless steel liner after about 1 min of temperature and pressure hold. The measured crack 

24 opening after the test was 1.1 mm (0.043 in.). Subtracting the initial flaw width of 0.2 mm 

25 (0.008 in.), the crack opening rate in this specimen because of creep was 0.89 mm/min 

26 (0.035 in./min). No other tests with through-wall cracks were performed.

27

28 Although none of the part-through flawed specimens failed in an unstable manner after ligament 

29 failure, some of the specimens with shallower initial flaws and higher failure pressure showed 

30 tearing at the crack tip. The tearing may indicate that these specimens were probably close to 

31 instability when the ligaments failed. At failure, the crack opening angles (COAs) of these 

32 specimens were 40–50 degrees. To get an estimate of the time it would take for a through-wall 

33 crack to open to a COA of 45 degrees, the calculations based on C* analysis, Equation 19 and 

34 Figure 5-18, were performed, although admittedly a more rigorous analysis would require that 

35 effects of finite deformation at the crack tip be taken into account. The calculations showed that 

36 the crack opening rate for a pressure of 16.2 MPa (2,350 psi) is as plotted in Figure 5-25a. 
5-28

1 For a 0.25-in. crack, the times to open to 0.25 mm (0.010 in.) are about 2 minutes at 

2 732 degrees C (1,350 degrees F) and a few seconds at 871 degrees C (1,600 degrees F). 

3 Considering the measured COD result reported earlier for a 12.7-mm (0.5-in)-long through-wall 

4 crack with stainless steel liner, the calculated COD because of creep at 732 degrees C

5 (1,350 degrees F), after correcting for hoop stress because of the stainless steel liner, is 1.0 

6 mm/min (0.04 in./min), which agrees reasonably well with the measured value of 0.89 mm/min

7 (0.035 in./min).

8

9 The times to open an initially closed through-wall crack of various lengths to a COA of 

10 45 degrees at 732 degrees C (1,350 degrees F) and at 871 degrees C (1,600 degrees F) under 

11 an internal pressure of 16.2 MPa (2,350 psi) are shown in Figure 5-25b. Note that the time 

12 varies from greater than 40 min for a 6.4-mm (0.250-in.)-long crack, to 3 minutes for a 12.7-mm 

13 (0.5-in)-long crack, and to 10 s for a 25.4 mm (1-in)-long crack at 732 degrees C

14 (1,350 degrees F). The corresponding times at 871 degrees°C (1,600 degrees F) are 4 min, 

15 50 s, and 5 s, respectively. Because most of the failure temperatures for tests were in the range 

16 of 750 degrees C (1,382 degrees F) to 850 degrees C (1,562 degrees F), the times to open the 

17 cracks to a COA of 45 degrees are relatively short unless the cracks are less than 5 mm 

18 (0.2 in.).

19

(a) (b)

20

21 Figure 5-25(a) Crack opening rate in mm/min versus crack length at 732 °C and 871 °C

22 Figure 5-25(b) Time to open initially closed through-wall cracks to a crack opening 

angle (COA) of 45° for a 22.3-mm (7 23 /8-in.) diameter SG tube at 732 °C (1,350 °F) and 

24 871 °C (1,600 °F) under a constant internal pressure of 16 MPa (2,350 psi)

25

26 5.4.1 Failure Modes of Specimens Tested at High Temperature

27

28 Depending on the absence or presence of flaws in the specimens and on the pressure and 

29 temperature at failure (independent of the details of the loading history), a variety of failure 

30 modes was observed.

31

32 5.4.1.1 Unflawed specimens

33

34 Typically, most of the unflawed specimens failed in an unstable manner. However, a single 

35 unflawed specimen subjected to 12.4 MPa (1,800 psi) at 800 degrees C (1,472 degrees F) 

36 showed a completely different failure mode that is more typical of creep failure of internally 
5-29

1 pressurized tubes. It failed in 4 hours by developing a pinhole leak and after accumulating a 

2 significant amount of creep deformation (ballooning). This was the only specimen that was 

3 tested at a pressure less than 14 MPa (2,000 psi). All the other unflawed specimens were 

4 tested at greater pressures and failed in an unstable manner independent of the temperature 

5 history.

6

7 5.4.1.2 Flawed Specimens

8

9 None of the flawed specimens failed in an unstable manner with fishmouth opening. Test 

10 specimens with 50-mm (2-in.) long/20 percent deep, 25-mm (1-in.) long/60 percent deep, and 6-

11 mm (0.25-in.) long/90 percent deep initial flaws were depressurized immediately on ligament 

12 failure. At a given failure pressure and temperature, the longer and shallower the initial flaw, the 

13 greater was the crack opening at failure. The 50- and 25-mm (2- and 1-in.) long cracks showed 

14 evidence of a slight tear at the crack tips.

15

16 The crack opening displacements in all the failed specimens with axial cracks were measured. 

17 Flaws that had a measurable crack opening are classified as “fishmouth,” and flaws that had no 

18 measurable COD are classified as leakers. The CODs and COAs are plotted against the initial 

19 flaw depths (a/h) in Figures 5-26a and 5-26b, respectively, where a trend of increased COD and 

20 COA with decreasing initial flaw depth is clearly evident. Intuitively, this is to be expected, 

21 because the shallower flaws require proportionately larger pressures or higher temperatures or 

22 longer times to cause failure of the ligament than the deeper flaws of same length. The 

23 specimens with the 1-in. (2.54-cm) and 2-in. (5.1-cm) cracks which showed the largest COA at 

24 failure also had slight tears at the crack tips.

25

(a) (b)

26

27 Figure 5-26 Measured (a) crack opening displacements (CODs) and (b) crack opening angles 

28 (COAs) in failed high temperature test specimens as a function of initial axial flaw depth 

29 and initial flaw length

30

31 At low temperatures, stability of a part-through crack after ligament failure can be determined 

32 from the following conditions:

33

34 If pcr > psc then the crack is stable (22a)

35 If pcr < psc then the crack is unstable (22b)

36
5-30

1 where pcr and psc are the unstable burst pressures of through-wall cracks and ligament rupture 

2 pressures of part-through-wall cracks, respectively. In other words, the stability boundary on a 

3 plot with crack length (2c) and crack depth (a/h) as axes is given by

4

5 m = mp (23)

6

7 which is independent of the flow stress or loading and depends only on the crack length and the 

8 crack depth. The curve corresponding to Equation 23 together with all the high temperature test 

9 data are plotted in Figure 5-27a. Although the curve m = mp appears to separate the specimens 

10 that leaked from those that fishmouthed remarkably well, a closer examination of the data for 

11 1 in. crack length shows that the correlation does not work for all constant pressure tests. In 

12 Figure 5-27b, constant pressure data (both isothermal and T-ramp tests) for specimens with 

13 25 mm (1 in.) crack are plotted. Contrary to what would be expected from the correlation, all the 

14 specimens below the m = mp line did not fishmouth. A better correlation that distinguishes 

15 specimens that fishmouthed from those that leaked is shown in Figure 5-28 for specimens with 

16 a 25 mm (1 in.) flaw in a plot of failure pressure versus temperature at failure.

17

(a) (b)

18

19 Figure 5-27(a) Initial flaw depth (a/h) versus axial crack length plot for specimens 

20 tested at high temperature

21 Figure 5-27(b) Flaw depth (a/h) versus pressure plot for constant-pressure tests on 

22 specimens with 1 in. part-through axial crack conducted isothermally or under a 

23 temperature ramp

24
5-31

1

2

3 Figure 5-28 Variation of failure pressure with failure temperature for tests conducted on 

4 specimens with a 25-mm (1-in.)-long crack

5 Open symbols denote specimens that leaked (no measurable COD) and filled symbols denote 

6 specimens whose cracks opened (fishmouthed). The numbers denote COD (in mm) at failure 

7 for the specimens that fishmouthed.

8

9 5.4.2 Lower Bound Flow Stress for Computing Unstable Burst at High Temperature

10

11 A lower bound to the flow stress for computing unstable failure of tubes with through-wall cracks 

12 can be obtained by ignoring the time it takes for a crack to open to a critical COA after ligament 

13 failure and calculate effective flow stresses from the dashed line in Figure 5-28 by using 

14 Equation 2b. Such calculated flow stresses are plotted together with flow stresses obtained 

15 from tensile tests in Figure 5-29. Note that the calculated flow stress curve lies considerably 

16 above those obtained from tensile tests at high temperatures but approaches the latter at lower 

17 temperatures. This is to be expected, because the tensile tests are normally conducted at 

18 about 10-3/s, whereas the maximum flow stresses at instability correspond to much higher 

19 strain rates. Although more data would be desirable, the instability pressures calculated from 

20 the flow stress curve in Figure 5-29 and indicated by solid lines in Figures 5-30a and 5-30b are 

21 consistent with the failure modes of the test specimens with 0.25 in (0.6 cm) and 2-in. (5.1-cm) 

22 cracks. It is proposed that the higher flow stress curve of Figure 5-29 can be used to determine 

23 the stability of a through-wall crack conservatively, using only the pressure and temperature at 

24 the moment of ligament failure and ignoring the pressure and temperature histories before

25 ligament failure.

26
5-32

1

2

3 Figure 5-29 Temperature variation of flow stress (using k=0.5) of Alloy 600 

4 specimens derived from tensile test data as reported in the literature

5 Dashed line indicates a lower bound to flow stress (calculated from dashed line in Figure 5-28 

6 using Equation 2b) for calculating instability pressures of tube specimens with through-wall 

7 cracks.

8

(a) (b)

9

10 Figure 5-30 Pressure at failure as a function of temperature at failure for all specimens with a 

11 (a) 6-mm (0.25-in.)-long axial crack and (b) 51-mm (2-in.) long axial crack

12 The solid lines are predicted from the higher flow stress curve of Figure 5.2-32.

13

14 The critical crack length for a 22.2-mm (7/8-in.) diameter tube as a function of temperature at a 

15 pressure of 16.2 MPa (2,350 psi) is shown in Figure 5-31. For typical severe accident 

16 temperatures (600–900 degrees C, or 1,112–1,652 degrees F) at a pressure of 16.2 MPa 

17 (2,350 psi), the critical crack length varies from 23 mm (0.9 in.) at 600 degrees C 

18 (1,112 degrees F) to 10 mm (0.4 in.) at 900 degrees C (1,652 degrees F). These represent 

19 minimum lengths of part-through cracks that will become unstable immediately after ligament 

20 rupture. However, at high temperatures, shorter cracks can grow in a stable manner by creep 

21 mechanisms prior to instability.

22
5-33

1

2

Figure 5-31 Critical crack length as a function of temperature for a 22.3-mm (7 3 /8-in.) diameter

4 Alloy 600 tube at an internal pressure of 16 MPa (2,350 psi)

5

6 5.5 References

7

8 1. Cochet, B., J. Engstrom, and B. Flesch, “PWR Steam generator tube and tube support 

9 plate plugging criteria,” Paper 4.1, Steam Generator Tubes Mechanical, LBRB, and 

10 Probabilistic Studies, EDF, France, 1990.

11 2. Flesch, B., and B. Cochet, “Crack stability criteria in steam generator tubes,”

12 International Conference on Pressure Vessel Technology, Beijing, September 1988.

13 3. Erdogan, F., “Ductile failure theories for pressurized pipes and containers,” International 

14 Journal of Pressure Vessels & Piping, Vol. 4, 1976.

15 4. Hahn, G.T., M. Sarrate, and A.R. Rosenfield, “Criteria for crack extension in cylindrical 

16 pressure vessels,” International Journal of Fracture Mechanics, Vol. 5, No. 3, 1969.

17 5. Finnie, I. and W.R. Heller, “Creep of Engineering Materials,” New York, McGraw-Hill, 

18 1959.

19 6. Kiefner, J.F., et al., “Failure stress levels of flaws in pressurized cylinders,” Progress in 

20 Flaw Growth and Fracture Toughness Testing, Kaufman, J.G., National Symposium on 

21 Fracture Mechanics (6th : 1972 : Philadelphia), American Society for Testing and 

22 Materials, Committee E–24 on Fracture Testing of Metals, American Society for Testing 

23 and Materials, ASTM Special Technical Publication 536, Philadelphia 1973.

24 7. U.S. Nuclear Regulatory Commission, Rempe, J.L., et al., “Light Water Reactor Lower 

25 Head Failure Analysis,” NUREG/CR-5642, EGG-2618, Idaho National Engineering 

26 Laboratory, Idaho Falls, ID, October 1993.

27 8. Alzheimer, J.M., et al., “Steam Generator Tube Integrity Program Phase I Report,”

28 NUREG/CR–0718, PNL-2937, Richland, WA, September 1979.

29 9. Eiber, R.J., et al., “Investigation of the Initiation and Extent of Ductile Pipe Rupture,” 

30 BMI–1908, Battelle Memorial Institute, June 1971.
5-34

1 10. Kurihara, R., S. Ueda, and D. Sturm, “Estimation of the ductile unstable fracture of pipe 

2 with a circumferential surface crack subjected to bending,” Nuclear Engineering and

3 Design, Vol. 106, 1988.

4 11. Majumdar, S., et al., “Failure Behavior of Internally Pressurized Flawed and Unflawed 

5 Steam Generator Tubing at High Temperatures – Experiments and Comparison with 

6 Model Predictions,” NUREG/CR-6575, Argonne National Laboratory, 1998.

7 12. Ranganath, S., and H.S. Mehta, “Engineering Methods for the Assessment of Ductile 

8 Fracture Margin in Nuclear Power Plant Piping,” Elastic Plastic Fracture Second 

9 Symposium, Vol. 2, Fracture Resistance Curves and Engineering Applications, 

10 American Society for Testing and Materials, ASTM Special Technical Publication 803, 

11 Philadelphia 1973.

12 13. Kumar, V., M.D. German, and C.F. Shih, “An Engineering Approach for Elastic-Plastic 

13 Fracture Analysis,” EPRI NP-1931, Electric Power Research Institute, 1981.

14 14. Majumdar, S., D.R. Diercks, W.J. Shack, “Analysis of Potential for Jet-Impingement 

15 Erosion from Leaking Steam Generator Tubes during Severe Accidents 

16 (NUREG/CR-6756),” Argonne National laboratory, 2002.

17 15. U.S. Nuclear Regulatory Commission, SGTR Severe Accident Working Group, “Risk 

18 Assessment of Severe Accident-Induced Steam Generator Tube Rupture,” NUREG19 1750, 1998, Agencywide Documents Access and Management System (ADAMS) 

20 Accession No. ML070570094.

21
6-1

1 6. ESTIMATION OF SG TUBE FLAW DISTRIBUTIONS

2

3

4 6.1 Introduction

5

6 This section presents the recent estimates for steam generator (SG) tube flaw distributions, 

7 based on selected inservice inspection (ISI) reports available to the U.S. Nuclear Regulatory 

8 Commission (NRC) for U-tube SGs (for Westinghouse and Combustion Engineering (CE) 

9 nuclear power plants (NPPs)).

10

11 Also included in Section 6.4 is the discussion for once-through SG axial loads on tubes during 

12 severe accidents.

13

14 The SG flaw distributions are used as input in estimation of consequential steam generator tube 

15 rupture (C-SGTR) probabilities during severe accidents after core damage occurs, and also for 

16 initiating events during power operation where sudden large pressure differences between the 

17 primary and the secondary sides can occur. Such probability estimates were done in support of 

18 the NRC’s Steam Generator Action Plan during the early 2000s, but were not formally 

19 documented. In that work, the estimated flaw distributions available at that time were used in 

20 supporting PRA reports, such as Reference 1. Those flaw distributions were based on data for 

21 SGs that are replaced since then. Reference 3 provides the most recent SG flaw distributions, 

22 applicable to both the Westinghouse and CE plants.

23

24 The flaw distributions in Reference 2 are summarized in Table 2 of that reference. This table is 

25 reproduced as Figure 6-1 here for the convenience of the reader. This table comes with the 

26 following clarification concerning primary water stress corrosion cracking (PWSCC) and outer 

27 diameter stress corrosion cracking (ODSCC):

28

29 The examples in Appendix C do not cover axial PWSCC at roll transitions, nor do 

30 they cover circumferential ODSCC at TTS.... (This quote is taken from page 17 

31 of the reference, and applies to the table below.)

32

33 The new SG tube flaw distribution estimates from Reference 3 are summarized in Table 6 of 

34 Section 3 of the reference. This table is reproduced as Table 6-2 for the convenience of the 

35 reader.

36
6-2

1

2

3 Figure 6-1 Table 2 reproduced from NUREG/CR-6521

4
6-3

1 6.2 Data Selection

2

3 To aid the probabilistic risk assessment of SG tube rupture events, a series of plant SG tube 

4 inspection reports were chosen to represent the flaw distributions in SG tubes for the current 

5 U.S. fleet. The rationale for the selection of specific reports is detailed in the following 

6 paragraphs.

7

8 Pressurized water reactor (PWR) plants in the United States were divided into three main 

9 categories: CE-designed plants, Westinghouse designs, and plants with once-through steam 

10 generator (OTSG) designs. For the Westinghouse and the CE designs, specific power plants 

11 were selected. Raw data from the SG tube inspection reports for those plants were provided as 

12 input for estimating probable flaw distributions, and primary coolant leakage estimates for 

13 various accident scenarios.

14

15 Regarding C-SGTR in OTSGs, an issue of axial loads on SG tubes during design-basis 

16 accidents was investigated at Argonne National Laboratory (ANL). Other analyses have shown 

17 that the once-through design is not susceptible to the problems of steam backflow, and the 

18 associated much higher temperatures, which could occur during severe accidents in SGs with 

19 recirculating designs. Therefore, ISI reports for OTSG plants were not used in this study.

20

21 Because most U.S. plants have replaced their original SGs, only ISI data for currently operating 

22 SGs were included here. Only SG tubes made of either thermally treated nickel Alloy 600 or 

23 nickel Alloy 690 were considered, because those are the main tube materials in use in the 

24 United States. (There are some mill-annealed Alloy 600 tubes in service in the United States, 

25 but they are rare exceptions.)

26

27 Historical summaries of SG operating experience are published in NUREG-1771, 

28 “U.S. Operating Experience with Alloy 600 Thermally Treated [TT] Tubes,” and in NUREG-1841, 

29 “U.S. Operating Experience with Thermally Treated Alloy 690 Steam Generator Tubes.” Those 

30 documents were reviewed to select a group of plants which would be considered as 

31 representative of the current fleet with regard to the distributions of flaws in the steam 

32 generators.

33

34 Sets of consecutive inspection reports covering a range from the most recent inspection back 

35 through approximately 10 or 12 years, and even as much as the past 20 years, were collected 

36 and reviewed. The number of reports varied, of course, depending on the SG date of 

37 replacement.

38

39 It could be suggested that SGs in service for longer times would experience more degradation 

40 of tubes. However that is not always the case, depending upon many factors such as operating 

41 temperatures, water chemistry, contaminants, and others. So, to properly characterize the 

42 current fleet, it was decided to include plants that had a lot of degradation and those which had 

43 little degradations, regardless of the number of effective full power years of operation. In this 

44 way, the flaw distributions for C-SGTR would be bounded by best and worst cases. Indeed, it 

45 was found that some of the longest operating steam generators have fewer flaws, while some of 

46 the newly replaced SGs have more flaws.

47

48 Two main categories are used here to characterize SG tube flaw types in the ISI reports: cracks 

49 and wear scars. Cracks are generally tight, sharp-tipped, irregularly shaped (jagged) defects, 

50 which can be described as a “tearing of the material.” Wear scars are usually of a more smooth 

51 and broader (not tight) shape. Wear scars are essentially a removal of surface material at areas 
6-4

1 where the tube comes in contact with another surface, such as a support plate, antivibration bar, 

2 loose part, another tube, and the like. Wear defects have been found in all SGs, regardless of 

3 the materials used to manufacture the tubes. Cracks, however, have not yet been found in any 

4 Alloy 690 SG tubes in the United States despite some being in operation for over 20 years. So, 

5 the ISI data used herein for flaw distribution estimates include cracks and wear defects for 

6 thermally treated Alloy 600 SGs, but only wear flaws for SGs constructed with Alloy 690 

7 material. It should be noted that the flaw data did not include any ISI data for mill-annealed 

8 tubes.

9

10 For CE plant designs, all of the replacement steam generators have been constructed with 

11 tubes made of Alloy 690 material with the exception of Palisades. The following plants were 

12 selected:

13

14 • Millstone 2, because it is the first CE plant to employ Alloy 690. Reviewing the longer 

15 history of Millstone 2 could provide insight into the progression of flaw growth and 

16 incidence of new flaw initiation over time.

17

18 • Calvert Cliffs, because several ISI reports for this plant include extra dimensional data 

19 describing tube defects, beyond the minimum information required. For example, one 

20 report lists the length, depth, and width of defects, while only the depth (or through-wall 

21 percentage) is required to be reported.

22

23 • St. Lucie 1, as having relatively newer SG replacements, because it showed some more 

24 flaw defects, compared to some of the older, similar SGs in service at CE plants.

25

26 Westinghouse-design power plants in the United States employ some steam generators made 

27 with Alloy 600 thermally treated tubes, and some SGs made with Alloy 690 tubes. Therefore, 

28 ISI reports from both of these categories of Westinghouse SGs were collected to characterize 

29 the current fleet of SGs used at power plants designed by Westinghouse.

30

31 Following a similar rationale as that which was explained above for CE-design plants, ISI 

32 reports for certain power plants were selected to represent the current state of flaw distributions 

33 in the Westinghouse fleet. For the two major categories of tube materials (Alloy 690TT and 

34 Alloy 600TT), four plants were chosen to be used to characterize the flaws in the current fleet of 

35 steam generators used at Westinghouse plants.

36

37 (1) To characterize Alloy 690TT SG tubes at Westinghouse plants, four sets of ISI reports 

38 from four different power plants (two lightly degraded plants, and two of the more 

39 degraded plants) were complied. The plants were Donald C. Cook Unit 2, McGuire Unit 

40 1, Prairie Island Unit 1, and Sequoyah Unit 1.

41

42 Likewise, for the Westinghouse design power plants with Alloy 600TT SG tubes, the following 

43 plants were chosen: Byron Unit 2, Seabrook Unit 1, Surry Unit 2, and Vogtle Unit 1.

44

45 Table 6-1 presents a summary of all the plants selected to have their inservice inspection 

46 reports reviewed and compiled for the purpose of characterizing the state of flaw distributions in 

47 the current fleet, to be used in C-SGTR risk assessment.

48

49 In Table 6-1, the “current model” designations in the table refer to the SG manufacturers, and 

50 the size or geometry of the steam generator. The basic design of all these SGs, at both CE and 

51 Westinghouse plants, is a recirculating design with inverted U-bend shaped tubes. However 
6-5

1 different manufacturers have different designs regarding the exact dimensions and the number 

2 of tubes. The symbols for the current manufacturers are explained as follows:

3

4 • BWC = Babcock and Wilcox Canada

5 • Fr = Framatome (now called AREVA)

6 • ABB/Doosan = ABB/Doosan

7 • all others are Westinghouse (W/51 F, D5, F, and W/54F)

8

9 Table 6-1 SG Properties for Flaw Distribution Estimates for C-SGTR Studies

10

Combustion Engineering Plant Designs

Plant Current Model Material Replace Date

Calvert Cliffs 1 BWC - 7811 690TT Jun-02

Millstone 2 BWC 690TT Jan-93

St. Lucie 1 BWC 690TT Jan-98

11

Westinghouse—Alloy 600TT SG Tubes

Plant Current Model Material Replace Date

Byron 2 D5 600TT Not Applicable (NA)

Seabrook 1 F 600TT NA

Surry 2 W/51 F 600TT Sep-80

Vogtle 1 F 600TT NA

12

Westinghouse—Alloy 690TT SG Tubes

Plant Current Model Material Replace Date

Donald C. Cook 2 W/54F 690TT Mar-89

McGuire 1 BWC 690TT May-97

Prairie Island 1 Fr 56/19 690TT Nov-04

Sequoyah 1 ABB/Doosan 690TT Jun-03

13

14 All of the raw data from the plants selected above, for the currently operating steam generators, 

15 was reviewed and summarized. The data were used for statistical estimations of flaw 

16 distributions, with respect to size and number of flaws. Finally, the flaw numbers and sizes may 

17 be used as input for the overall estimation of the LERF consequences of a steam generator 

18 tube rupture event caused by a severe accident.

19

20 6.3 Estimation of SG Tube Flaw Distributions in Replacement SGs

21

22 6.3.1 Summary 

23

24 The previous work on estimating SG tube flaw distributions was done for SGs for which the data 

25 existed before 1995. These (U-tube) SGs are replaced with those having new SG tube 

26 materials. Recent work has been done to estimate a new set of flaw distributions for U-tube 

27 SGs (used by domestic Westinghouse and CE NNPs) (Ref. 4). For this purpose, selected data 

28 from ISI reports available to the NRC was used, as discussed in Section 6.2. The work done is 

29 discussed in Reference 3 and contains the analysis of the ISI Reports, the creation of the 

30 database, and the estimation of flaw rate and other flaw characteristics. Because of the 

31 limitations of the detailed information available for the flaw characteristics, the data have been 

32 consolidated into Inconel 600 material applicable to all SGs (W and CE) as a function of 
6-6

1 effective full power year (EFPY) (parameter K in the equations of Table 6-2), and similarly for 

2 Inconel 690. Thus, the equations do not distinguish by the SG-type, but provide flaw 

3 distributions as a function of time (EFPYs).

4

5 The number of flaws generated in the last operating cycle K can be estimated by calculating the 

number of flaws at Kth 6 and (K-1)th cycles and subtracting the two. This allows estimating the 

7 large (deep) cracks (e.g., greater than 30 percent deep) that may be present during an accident 

sequence in the Kth 8 cycle. It can be assumed that flaws with 40 percent or more depth 

observed before the Kth 9 cycle are removed by plugging the associated tubes.

10

11 Table 6-2 summarizes the new SG tube flaw distributions that can be used for NPPs with 

12 replacement SGs. These distributions are applicable to both Westinghouse and CE 

13 replacement generators with thermally treated Inconel 600 and 690 materials.

14

15 Appendix K contains a further discussion of input flaw data (empirical distribution) and shifted 

16 flaw distribution as used for PRA purposes. The shifted flaw distribution is introduced in Section 

17 7.1.3 of this report.

18

19 Table 6-2 SG Tube Flaw Distributions Taken from Reference 3

20

Flaw 

Characteristics Thermally Treated Inconel 600 Thermally Treated Inconel 690

Volumetric/Wear 

Flaw Rates

h(k) = 6.4166·10-5 K + 1.3236·10-3

μ = 6.4166·10-5, Ω = 1.3236·10-3

h(k) = 5.5826·10-5 K + 6.8627·10-4

μ = 5.5826·10-5, Ω = 6.8627·10-4

Axial Crack 

Flaw Rates

K<15, h(k) = Negligible

μ = 0.0, Ω = 0.0

K>15, h(k) = 2.0·10-4

μ = 0.0, Ω = 2.0·10-4

h(k) = Negligible

μ = 0.0, Ω = 0.0

Circumferential Crack 

Flaw Rates

K<15, h(k) = Negligible

μ = 0.0, Ω = 0.0

K>15, h(k) = 1.0·10-3

μ = 0.0, Ω = 1.0·10-3

h(k) = Negligible

μ = 0.0, Ω = 0.0

Axial Flaw Length: 

Axial Cracks, Wear 

Marks, or 

Volumetric Flaws

Gamma(α =2.33318781, β= 2.0847)

Circumferential Crack 

Angle 0.58 Gamma(α=28.6565, β=0.4187) + (1-0.58)·Gamma(α=9.5638, β=0.0670)

Flaw Depth: 

Cracks, Wear, 

Volumetric Flaws

Gamma(α =2.0658, β=16.3274)

21 Note: If the gamma function in EXCEL is to be used to evaluate values with the above parameters, the “beta” to be 

22 placed in the EXCEL gamma function is actually 1/ β of Table 6.3-1.

23
6-7

1 6.3.2 An Example Calculation

2

3 A linear hazard rate is provided in Table 6-2 for the SG tube flaws as a function of EFPY. This 

4 hazard rate is defined by:

5

6 h(k) = μ * k + Ω

7

8 where k is EFPY, and both coefficients μ and Ω are positive.

9

10 Given the above hazard rate the cumulative flaw probability can be expressed by:

11

P(f) = 1 - exp[-{(1/2) * μ * k2 12 + Ω * k}] (6.1)

13

14 A four-loop Westinghouse plant (four SGs) with thermally treated Inconel 600 SG tubes is 

15 considered. Each SG is assumed to have 3,300 tubes and the plant has accumulated 

16 15.6 EFPYs of operation. The expected number of flaws (NFlaws-Avg) that will be identified at 

17 the end of the current cycle is estimated from the cumulative probability distribution using the 

18 following equation:

19

20 NFlaws-Avg = (3,300 * 4) * [1.0 - exp[-{(1/2) * μ * k2 + Ω * k}]] (6.2)

21

22 The values μ and Ω can be found from the summary table shown above in Table 6-2. For the 

23 case discussed above, it is expected that 370 wear/volumetric flaws be present in all the SGs 

24 (13,200 tubes). Thirty-one (31) out of these 370 flaws will be generated in this cycle. This is 

25 estimated directly by setting k=15.6 in the equation for hazard rate

26

27 (h(k) = 6.4166·10-5 K + 1.3236·10-3)

28

29 It also implies that the larger flaws could only be found in the last cycle (the estimated 31 flaws), 

30 since large flaws found earlier in previous cycle were all subjected to plugging and other repair 

31 practice per inspection procedure.

32

33 The current statistical analysis and this illustrative example are based on flaws that are 

34 detected. They do not account for the hidden flaws that are not detected during ISI. The 

35 number or fraction of the hidden flaws is generally estimated by using a probability of detection 

36 (POD). The POD delivers the realistic, statistical assessment of the reliability for a Non 

37 Destructive Testing (NDT) method. The POD probability curves (typically S shaped) are 

38 developed as a function of flaw size and type. The larger and deeper the flaw, the higher will be 

39 the POD. The POD value also depends on the flaw type. For example, the POD value is larger 

40 for a crack with sharp edges than for a wear with smooth surface (Reference 4). For more 

41 detailed analysis, the flaws in the last cycle should be adjusted for not considering the POD, 

42 using the information in NUREG/CR-6791. The impact of such adjustments for large flaws is 

43 expected to be around 10 percent.

44

45 Figure 6-2 shows the NFlaws-Avg, which includes both wear and cracks for 13,200 tubes, as a 

46 function of EFPY for both 600 and 690 thermally treated tubes.

47
6-8

1

2

3 Figure 6-2 Average number of flaws as a function of EFPY for 4 SGs

4

5 6.3.3 Example Flaw Samples

6

7 To illustrate the flaws that may be present during the 15th EFPY, 10 flaw samples are 

8 generated for 1 SG with 3,588 TT600 tubes. It is assumed that the tubes with 40 percent deep 

9 and deeper flaws are plugged when revealed by tests. Seven hundred seventy-five total flaws 

10 in 10 samples were created, with an average of 78 flaws per sample per SG. Average length of 

11 the 775 flaws is 1.1 centimeters (0.43 inch); Average depth is 18 percent. All flaws are “wear” 

12 type.

13

14 Histograms in Figures 6-3 and 6-4 show the distribution of the 775 flaws by length and depth. 

15 Note that all flaws of depth 40 percent or deeper are removed at or before the last outage; thus 

16 such large flaws are generated since the last refueling outage or were not detected (i.e., POD 

17 less than 1).

18

0

200

400

600

800

1000

1200

1400

0 5 10 15 20 25 30 35 40

Flaws per 13,200 tubes

EFPY (K)

Inconel 600

Inconel 690
6-9

1

2

3

4

5

6 Figure 6-3 TT600 flaws for 10 SGs—distribution by length

7

138

270

189

99

44

17

5 10

3

0

50

100

150

200

250

300

0.25 0.75 1.25 1.75 2.25 2.75 3.25 3.75 4.25

# of Flaws

Midpoint of bin in length (cm)

TT600 Flaws for 10 SGs

Distribution by Length in cm

# of Flaws

Example: There are 270 flaws larger 

than 0.25 cm in length; smaller or 

equal to 0.75 cm in length
6-10

1

2

3 Figure 6-4 TT600 flaws for 10 SGs—distribution by depth

4

5 6.4 OTSG Axial Loads on Tubes during Severe Accidents

6

7 ANL has completed a study , “Stability of Circumferential Flaws in Once-Through Steam 

8 Generator Tubes under Loading during LOCA, MSLB, and FWLB,” on the assessment for 

9 potential elevated axial tube loads because of thermal expansion between the SG shell and 

10 tubes during severe accident conditions in OTSGs. This work was performed for NRC/RES/DE, 

11 and is being reviewed. Also, OTSG designs are not susceptible to a severe accident effect of a 

12 backflow of steam, which may cause much higher local temperatures in recirculating steam 

13 generators. Based on the preliminary results of the ANL work, and the backflow characteristics, 

14 RES’s current assessment is that the phenomenon investigated does not contribute significantly 

15 to C-SGTR for severe accident conditions.

16

131

393

176

61

14

0 0 0 0 0

0

50

100

150

200

250

300

350

400

450

0.05 0.15 0.25 0.35 0.45 0.55 0.65 0.75 0.85 0.95

# of Flaws

Midpoint of bin in depth

TT600 Flaws for 10 SGs 

Distribution by Depth

# of Flaws

Example: There are 176 flaws deeper 

than 15%, but not deeper than 25%.
6-11

1 6.5 References

2

3 1. Sandia National Laboratories, “Severe Accident Initiated Steam Generator Tube 

4 Ruptures Leading to Containment Bypass – Integrated Risk Assessment,” JCN Y6486, 

5 February 2008, Agencywide Documents Access and Management System (ADAMS) 

6 Accession No. ML15054A514.

7 2. Gorman, J.A., et al., “Estimating Probable Flaw Distributions in PWR Steam Generator 

8 Tubes,” U.S. Nuclear Regulatory Commission, NUREG/CR-6521 (ANL-96/20), 1996.

9 3. Azarm, M.A., et al., “A Letter Report on Flaw Database and C-SGTR Calculator Flaw 

10 Input,” Information Systems Laboratories, December 2014.

11 4. Kupperman, D.S., et al., “Eddy Current Reliability Results from the Steam Generator 

12 Mock-up Analysis Round-Robin,” U.S. Nuclear Regulatory Commission, NUREG/CR13 6791, Revision 1, October 2009.

7-1

1 7. A PRA PERSPECTIVE OF SEQUENCES STUDIED

2

3

4 In this section, representative Westinghouse and Combustion Engineering (CE) plant designs

5 are considered to estimate both C-SGTR probabilities and corresponding large early release 

6 frequency (LERF) fractions.

7

8 Section 7.1 discusses Westinghouse steam generator (SG) types; Section 7.2 discusses CE SG 

9 types.

10

11 7.1 PRA Perspective of C-SGTR for a Westinghouse Plant

12

13 The thermal-hydraulic (TH) analysis and the success criteria used for developing the 

14 probabilistic risk assessment (PRA) models for C-SGTR for a representative Westinghouse 

15 plant were gleaned from the information reported in NUREG/CR-6995, “SCDAP/RELAP5 

16 Thermal-Hydraulic Evaluations of the Potential for Containment Bypass during Extended Station 

17 Blackout Severe Accident Sequences in a Westinghouse Four-Loop PWR.” NUREG/CR-6995 

18 documents the TH evaluations performed using the SCDAP/RELAP5 systems analysis code 

19 and a model representing a Westinghouse four-loop pressurized-water reactor (PWR); i.e., Zion 

20 Nuclear Power Plant (ZNPP). The plant model benefitted from the following:

21

22 • extensive iterative comparisons with evaluations of natural circulation flows and turbulent 

23 mixing using a computational fluid dynamics code

24

25 • comparison with experimental data for pertinent fluid-mixing behavior

26

27 NUREG/CR-6995 also included some sensitivity evaluations and uncertainty analyses of the 

28 station blackout (SBO) accident sequences.

29

30 7.1.1 Description of the Selected TH Sequences

31

32 The following representative scenarios from NUREG/CR-6995 (Ref. 1) were examined for 

33 potential use in evaluating C-SGTR. These scenarios modeled leakage through the secondary 

side of each SG, equivalent to a hole of 3.2 square centimeters (cm2

) (0.5 square inch [in.2 34 ]). 

35 This size of leakage is sufficient to ensure that the pressure in the secondary side of the SGs 

36 approach the atmospheric pressure after SG dryout. However, this assumed leakage area is 

37 not sufficient to maintain a low SG secondary-side pressure after the occurrence of a guillotine 

38 break of a single SG tube.

39

40 (1) Station Blackout with Early Failure of the Turbine Driven Auxiliary Feedwater 

41 (TDAFW) Pump Resulting in Core Damage and a Potential for C-SGTR due to 

42 Creep Rupture: Normal reactor coolant pump (RCP) seal leakage of 79.4 Liters per 

43 minute (21 gpm) per pump is modeled for this scenario. Core damage is expected in 

44 less than 2 hours. The potential for C-SGTR is considered after the onset of core 

45 damage. This scenario is referred to as the “Wnewbase” case. The primary and 

46 secondary-side pressure in pounds per square inch (psi) and the HL (HL) temperature in 

47 degrees Celsius are shown in Figure 7-1a. The difference between HL temperature and 

48 the hottest tube temperature (HLT-HTT), the average hot tube temperature (HLT-AHTT), 

49 and the average cold tube temperature (HLT-ACTT) is shown in Figure 7-1b.

50
7-2

1 (2 & 3) Station Blackout with Failure of TDAFW after Battery Depletion: TDAFW is initially 

2 considered available but it fails a short time after the battery depletes because of the 

3 loss of direct current (dc). Normal RCP seal leakage of 79.4 Liters per minute (21 gpm)

4 per pump is modeled. The operator’s action to depressurize SGs at 30 minutes, by 

5 opening at least one SG atmospheric dump valve (ADV) or SG power-operated relief 

6 valve (PORV) per SG, drops the primary pressure below 4.82 megapascal (MPa)

7 (700 psi). This actuates the accumulator discharge. Two cases have been analyzed 

8 depending on the rate of depressurization (slower and faster rate). These cases are 

9 referred to as Cases 153 and 153A. Case 153A results in sequence timing including 

10 the core damage that are delayed by at most 1.3 hours compared to Case 153, 

11 because of depressurization of the SGs to the lower pressure (120 psia, rather than 280 

12 psia for Case 153) in Case 153A resulting in a greater depressurization of the RCS and 

13 more accumulator injection.

14

15 (4) Station Blackout with Early Failure of the TDAFW Pump and Guillotine Break of 

16 One SG Tube after Core Damage: Normal RCP seal leakage of 79.4 Liters per 

17 minute (21 gpm) is assumed. Early core damage is expected in less than 2 hours. 

18 After the onset of core damage, at approximately 12,926 seconds, one of the flawed 

19 tubes with a stress magnification factor of 2 (mp = 2) ruptures. The resulting modeled 

20 leak area is equivalent to the area associated with a guillotine break of one tube. This 

21 will result in a slow depressurization of the primary; however, it is not fast enough to 

22 prevent HL failure. The HL fails shortly after (13,630 seconds, approximately 

23 11 minutes), terminating the containment bypass. This scenario is referred to as 

24 Case F2 and the results are shown in Figure 7-2.

25

26 Similar to Case F2 Except that the Failed Flawed Tube has A Stress Magnification Factor 

27 of 3 (mp = 3): The flawed tube fails at 12,930 seconds. The HL failure was excluded from the 

28 model. Prolonged depressurization of the primary as a function of time because of the guillotine 

29 break of one SG tube is, therefore, captured in this case run. This scenario is referred to as 

30 Case F3 and the results are shown in Figure 7-3.

31

32 Similar to Case “Wnewbase” Except with Different Sizes of RCS Seal Leakages: Initial 

33 leakage is 79.4 Liters per minute (21 gpm) per RCP. At 13 minutes, leakage is increased to 

34 60 gpm per RCP. Finally, when fluid in the RCPs becomes saturated, leakage is increased to 

35 450 gpm per RCP. This is called Case Run C21-60-450. This case resulted in a clearance of 

36 the loop seal.

37

38 The following observations are made from the results of the TH analyses. These observations 

39 are used in developing the PRA models and the associated sensitivity runs:

40

41 As noted in Figures 7-1a and 7-1b, the HL temperature is significantly higher than the average 

42 hot tube and the hottest tube temperatures by as high as 400 degrees C (752 degrees F). The 

43 differences between the HL temperature and the hottest tube temperature, average hot tube 

44 temperature, or average cold tube temperature, are shown in Figure 7-1b. A higher HL

45 temperature is the driving factor for HL failure before the failure of the SG tubes. This would 

46 also explain the lower estimate of the risk associated with the C-SGTR for the representative W 

47 plant.

48

49 For those cases where TDAFW is operating, the time to core uncovery depends on the scheme 

50 used for primary depressurization. Two cases were analyzed by SCDAP/RELAP5 models:

51 Case 153 and 153 A. In both cases aggressive cooling and depressurization using secondary 
7-3

1 system resulted in the dropping of primary pressure below the accumulator discharge setpoint. 

2 The discharge of accumulator resulted in core uncovery to be delayed significantly (about 11 

3 hours for Case 153 and 13 hours for Case 153A). No case runs were performed for when the 

4 operator fails to depressurize the primary via rapid secondary cool down. In such cases it is 

5 assumed that the TH response will be similar to the Wnewbase case but shifted by at least 4 

6 hours corresponding to the battery duration.

7

8 As noted in Figure 7-4, the guillotine break of one tube will not depressurize the primary such 

9 that it prevents subsequent HL failure. This is shown in Figure 7-4. Therefore, the PRA event 

10 trees and resulting estimated probabilities should differentiate between single tube failures and 

11 multiple tube failures.

12

13 As seen in Figure 7-4, the failure of SG tubes with a leak area equivalent to the guillotine break 

14 of one tube, will result in the pressurization of the SG secondary side. For the purpose of 

15 severe-accident management guideline (SAMG) activities related to flooding the SG, the SG 

16 secondary side has to be fully depressurized. This requires opening the secondary-side PORVs

17 or safety relief valves (SRVs). The opening of PORVs/SRV occurs under the harsh 

18 environment resulting from a core melt accident.

19

20 The TH runs showed that the loop seal is cleared when the RCP leakage is about 1,703 Liters 

21 per minute (450 gpm) per pump. The TH runs also indicate that the time of RCP seal failure 

22 and its relation to the time when the cold leg becomes saturated, impacts loop seal clearing.

23
7-4

1

2

Figure 7-1(a) TH results for Wnewbase 3

3.00E+03

2.50E+03

2.00E+03

1.50E+03

1.00E+03

5.00E+02

0.00E+00

1.60E+03

1.40E+03

1.20E+03

1.00E+03

8.00E+02

6.00E+02

4.00E+02

2.00E+02

0.00E+00

0.00E+00 5.00E+01 1.00E+02 1.50E+02 2.00E+02 2.50E+02 3.00E+02 3.50E+02

P

r

e

s

s

u

r

e

( p

s

i

)

Temp (Deg. C)

Time (Min.)
7-5

1

2

Figure 7-1(b) Difference between the HL temperature and the temperatures of the hottest tube and th3

and cold tube for Wnewbase 4

6.00E+02

5.00E+02

4.00E+02

3.00E+02

2.00E+02

1.00E+02

0.00E+00

5.00E+02 6.00E+02 7.00E+02 8.00E+02 9.00E+02 1.00E+03 1.10E+03 1.20E+03 1.30E+03 1

Temp(Deg. C)

Time (Min.)
7-6

1

2

Figure 7-2 TH results for Case F2 3

1.40E+03

1.20E+03

1.00E+03

8.00E+02

6.00E+02

4.00E+02

2.00E+02

0.00E+00

3.00E+03

2.50E+03

2.00E+03

1.50E+03

1.00E+03

5.00E+02

0.00E+00

0.E+00 5.E+01 1.E+02 2.E+02 2.E+02 3.E+02

Pressure (psi)

Time (minutes)

Case F2: Tube failure followed by HL failure shortly after

Te

on 

Ya
7-7

1

2

Figure 7-3 TH results for Case F3 3

1.60E+03

1.40E+03

1.20E+03

1.00E+03

8.00E+02

6.00E+02

4.00E+02

2.00E+02

0.00E+00

3.00E+03

2.50E+03

2.00E+03

1.50E+03

1.00E+03

5.00E+02

0.00E+00

0.E+00 5.E+01 1.E+02 2.E+02 2.E+02 3.E+02 3.E+02 4.E+02

Pressure (psi)

Time (minutes)

Case F3: Guillotine break of one tube with intact RCS system

Tem

on s

Yaxi
7-8

1

2

3 Figure 7-4 Shifted distribution for flaw depth (600 TT)

4

5 7.1.2 Estimating the Entry Frequency from Level 1 PRA for Level 2 PRA

6

7 ZNPP was selected for developing the Level 2 PRA models to ensure consistency with the TH 

8 analyses results. No current PRA or standardized plant analysis risk (SPAR) models are 

9 available for ZNPP, and ZNPP units are no longer in operation. The estimates for a prolonged 

10 SBO condition, as the entry point for the Level 2 PRA was, therefore, estimated based on the 

11 plant design features and information from vintage ZNPP PRA documents. Appendix M 

12 provides a detail discussion of various core damage frequency (CDF) contributors from SBO 

13 scenarios to overall CDF from both internal and external events. The quantitative values used 

14 in this section are supported by technical discussion in Appendix G (Subsection G.1).

15

16 The frequency of core damage because of a prolonged SBO (beyond battery depletion) that can 

17 be used as the entry point for Level 2 PRA is estimated to be around 1.2E-5 per reactor year 

18 (RY). This estimate is consistent with the estimate of the long term SBO scenarios reported in 

19 the NUREG 1935 (Ref. 2) study [between 1.0E-5 to 2.0E-5 per RY]. Table 7-1 shows the 

20 contributions from both internal and external hazards.

21

22 Table 7-1 Contributions of Various Events to Long Term SBO Scenarios

23

Initiating Event Long Term 

SBO CDF

Percent 

Contribution

Source

Internal events including internal floods 5.2E-6 25.5% NUREG-4551

Seismic 5.6E-6 27.5% NUREG/CR-3300

Fire 9.5E-6 47.0% Appendix G

Total 2.03E-5 100.0%

24

25 The uncertainties associated with these frequencies are not presently estimated because of the 

26 lack of detailed models and data. Surrogate uncertainties from similar plants such as Indian 

27 Point Unit 3, could be considered if needed.

28

0.00E+00

1.00E-01

2.00E-01

3.00E-01

4.00E-01

5.00E-01

6.00E-01

7.00E-01

8.00E-01

9.00E-01

1.00E+00

0 0.5 1

Probability 

Depth 

Shifted flaw depth distribution

Cumulative

Probability

distribution
7-9

1 The main plant features of ZNPP which are pertinent to this study are shown in Table 7-2 below.

2

3 Table 7-2 Related Information from Zion Nuclear Stations for This Study

4

Systems System Features

Number SGs and number of 

tubes per SG

4 SGs each with 3300 tubes

Emergency Power System

a. Each unit consists of 3 4160-VAC class 1E buses, each 

feeding 1 480-VAC class 1E bus and a motor control center

b. For the 2 units there are 5 diesel generators, with one being a 

swing diesel generator shared by both units

c. 3 trains of dc power are supplied from the inverters and 3 unit 

batteries. It has a battery life of 6 hours

Auxiliary Feedwater System

a. Two 50 percent motor-driven pumps and one 100 percent 

turbine-driven pump

b. Pumps take suction from their own unit condensate storage 

tank (CST) but can be manually cross-tied to the other unit’s 

CST

Service Water (SW)

a. Shared system between both units

b. Consists of 6 pumps and 2 supply headers

c. Cools component cooling heat exchangers, containment fan 

coolers, diesel generator coolers, auxiliary feed water pumps

d. 2 out of 6 pumps can supply sufficient flow

Component Cooling Water 

(CCW)

a. Shared system between both units

b. Consists of 5 pumps, 3 heat exchangers, and 2 surge tanks

c. Cools RHR heat exchangers, RCP motors and thermal 

barriers, RHR pumps, SI pumps, and charging pumps

d. One of 5 pumps can provide sufficient flow

Secondary Relief

a. Steam Dump valves

b. Atmospheric dump valves (one per SG)

c. Safety Relief Valves

Primary Relief a. 2 PORVs

b. 3 safety relief valves

Containment

a. Large, dry, pre-stressed concrete

b. 2.6 million cubic foot volume

c. 49 psig design pressure

5 Reproduced from NUREG/CR-3300, NUREG/CR-4550, and NUREG/CR-4551*

6

7 * References 3, 4, and 5

8

9 7.1.3 Conditional Probability of C-SGTR at Each Flaw Bin

10

11 In this section, the flaw distributions obtained in Section 6 and the Wnewbase sequence TH 

12 input discussed earlier in Section 7.1 are used to gain an understanding of various SG tube 

13 leaks and their relation to HL failure time. This is done for different flaw sizes; effect of multiple 

14 flaws is analyzed later in this section.

15

16 Current Westinghouse plants use SGs with thermally treated Inconel 600 and 690. The number 

17 of flaws per cycle for thermally treated Inconel 600 and 690 SG tubes is significantly lower than 

18 the older SG tubes made of mill-annealed Inconel 600. The size distributions of flaws in terms 

19 of flaw length and depth were developed based on the available surveillance data, as discussed 

20 in Section 6. There were a limited number of plants and inspection cycles in the surveillance 

21 data. Therefore, the resulting estimated flaw rates and flaw characteristics are significantly 
7-10

1 dependent on the degree to which the surveillance data represents the U.S. plants. Any 

2 potential anomalies in the data of even one plant, would significantly affect the 

3 estimates because of the small number of plant samples. Lack of surveillance data from a 

4 larger population of plants limits the range of the applicability of the estimates, and it causes 

5 uncertainties in the estimated parameters for characterizing the flaws. As an example, a large 

6 number of unreliable small depth measurements; less than 10 percent, from one of the plants in 

7 the surveillance data, significantly skewed the depth distribution toward the shallow flaws. This 

8 issue was compounded because of surveillance records with a large number of missing depth 

9 measurements. The depth distribution generated from the data, therefore, is expected to be 

10 skewed toward the lower depth values. Some adjustments were made to the original estimated 

11 distributions of flaw depth and length. These adjustments were made to compensate for the 

12 potential shift of flaw size distributions toward the shallower and smaller flaws. This was done 

13 by shifting the depth distribution by 7 percent deeper and length distribution by 0.8 centimeter 

14 (cm) (0.31 inch [in.]) longer to ensure that the numbers of large flaws, i.e., flaws that are 

15 plugged, have been maintained. The raw data for plugging is readily available in the flaw 

16 database. The flaw data shows that out of 2,440 flaws, 233 were plugged (about 9.5 percent). 

17 Furthermore, a plugged tube is expected to have a flaw with an average length of 1.3 cm

18 (0.5 in.), and a depth greater than 30 percent. The size distributions are shifted such that the 

19 probability of an occurrence of flaw below these sizes accounts for 90 percent of the total 

20 number of flaws. Figures 7-5 and 7-6 show the shifted distribution for flaw depth and flaw 

21 length.

22

23

24

25 Figure 7-5 Shifted distribution for flaw length (690 TT)

26

27 ZNPP was equipped with four SGs, each with about 3,300 tubes. As a representative plant, this 

28 study assumes that the tubes could either be made of Inconel 600 or Inconel 690. There are, 

29 therefore, 13,200 tubes for a unit of ZNPP. The average number of flaws generated for the first 

30 14 effective full power years (EFPYs) of operation using the Inconel 600 TT flaw generation rate 

31 equation, is about 323 flaws per one unit of ZNPP. (Refer to Section 6.1.1 for an example 

32 calculation.) At the end of the 14 EFPYs, it was assumed that there was a periodic SG 

33 inspection, therefore, all the large flaws out of 323 flaws per unit are expected to be plugged 

34 (approximately 31 plugged tubes for four SGs). An additional 31 flaws will be generated during 

35 the 15 EFPYs of operation. Therefore, 323 flawed tubes was expected for all four SGs during 

0.00E+00

1.00E-01

2.00E-01

3.00E-01

4.00E-01

5.00E-01

6.00E-01

7.00E-01

8.00E-01

9.00E-01

1.00E+00

0 2 4 6 8

Probability

Length (Cm)

Shifted flaw length distribution

Cumulative

Probability

Distribution
7-11

1 the operating period at 15 EFPYs, with an average of about 2 large flaws that may need 

2 plugging at the end of the 15 EFPYs.

3

4

5

6 Figure 7-6 RCS survival probability as a function of accident time for Wnewbase

7

8 Flaw lengths and depths are sorted into a set of bins. The probability that a flaw resides in one 

9 of the bins at a time of 15 EFPYs is shown in Table 7-3. These probabilities are estimated 

10 based on the length and depth distributions shown in Figures 7-5 and 7-6. These distributions 

11 are applicable to both thermally treated Inconel 600 and 690, and do not differentiate between 

12 the W and CE plants. These probabilities are multiplied by the number of flaws estimated 

13 earlier to determine the average numbers of flaws for each flaw bin. The bins consisting of 

14 large flaws are estimated by considering the expected number of flaws only in the last cycle. All 

15 flaws deeper than approximately 0.3 discovered in the previous cycles are assumed to have 

16 been plugged. The total number of flaws used for calculating the expected number of flaws for 

17 each bin, therefore, follows the following rules:

18

19 • For flaw bins with a depth of less than 0.3, the total number of flaws used to estimate the 

20 expected number of flaws was the summation of all flaws in previous cycles plus the 

21 number of flaws in the last cycle. For Inconel 600, this value is 354 flaws (323 flaws in 

22 previous cycle plus 31 flaws in the last cycle). For Inconel 690, this value is 218 flaws 

23 (198 flaws in previous cycle plus 20 flaws in the last cycle.)

24

25 • For flaw bins with a depth greater than 0.3, the total number of flaws is based on the 

26 flaws generated in the last cycle (cycle 15). The values for Inconel 600 and 690 are 31 

27 and 20, respectively.

28

29 The average number of flaws is shown in Tables 7-4 and 7-5 for Inconel 600 and 690, 

30 respectively. The values shown in these tables represent the expected number of flaws in each 

31 bin rounded to the nearest integer. Therefore, a value of zero for the expected numbers of 

32 flaws in a bin should not be construed as having a zero probability of occurrence. To find the 

33 probability that a flaw is realized in each flaw bin, Table 7-3 is to be consulted.

34

0

0.2

0.4

0.6

0.8

1

12000 12500 13000 13500 14000

Probability

Time (S)

Survival Probability RCS
7-12

1 Table 7-3 Probability that a Detected Flaw Belongs to a Bin Size at 15 EFPY

2

Length of Flaw

Total

0 cm to 

1 cm

1 cm to 

2 cm

2 cm to 

3 cm

3 cm to 

4 cm

4 cm to 

5 cm

5 cm to 

6 cm

Flaw Depth

0 to 0.1 2.74E-3 4.62E-2 2.23E-2 5.38E-3 1.04E-3 1.80E-4 7.78E-2

0.1 to 0.2 1.86E-2 3.14E-1 1.52E-1 3.66E-2 7.08E-3 1.23E-3 5.29E-1

0.2 to 0.3 9.59E-3 1.62E-1 7.81E-2 1.89E-2 3.64E-3 6.31E-4 2.73E-1

0.3 to 0.4 3.09E-3 5.21E-2 2.52E-2 6.07E-3 1.17E-3 2.03E-4 8.78E-2

0.4 to 0.5 8.47E-4 1.43E-2 6.90E-3 1.66E-3 3.22E-4 5.57E-5 2.41E-2

0.5 to 0.6 2.14E-4 3.61E-3 1.74E-3 4.21E-4 8.13E-5 1.41E-5 6.08E-3

0.6 to 0.7 5.14E-5 8.67E-4 4.19E-4 1.01E-4 1.95E-5 3.38E-6 1.46E-3

0.7 to 0.8 1.19E-5 2.01E-4 9.73E-5 2.35E-5 4.54E-6 7.86E-7 3.39E-4

0.8 to 0.9 2.71E-6 4.57E-5 2.21E-5 5.32E-6 1.03E-6 1.78E-7 7.70E-5

0.9 to 1.0 small

Total 3.52E-2 5.93E-1 2.86E-1 6.91E-2 1.34E-2 2.31E-3 ~1

3

4 Table 7-4 Expected Number of Flaws That Belong to a Flaw Bin Defined by Depth and 

5 Length Range for Zion SGs with Tubes Made of Inconel 600

6

Depth/ 

Length

0 cm to 

1 cm

1 cm to 

2 cm

2 cm to 

3 cm

3 cm to 

4 cm

4 cm to 

5 cm

5 cm to 

6 cm

Total

0 to 0.1 1 16 8 2 0 0 27

0.1 to 0.2 7 111 54 13 3 0 188

0.2 to 0.3 3 57 28 7 1 0 96

0.3 to 0.4 1 2 1 0 0 0 4

0.4 to 0.5 0 0 0 0 0 0 0

0.5 to 0.6 0 0 0 0 0 0 0

0.6 to 0.7 0 0 0 0 0 0 0

0.7 to 0.8 0 0 0 0 0 0 0

0.8 to 0.9 0 0 0 0 0 0 0

Total 12 186 91 22 4 0 315

7

8 The expected values of flaws in each bin are shown to illustrate the expected size distribution of 

9 flaws. The values shown in the tables also account for the flaws detected in previous cycles 

10 that they were large enough such that the affected tubes were plugged. The approximation 

11 used in these calculations plus the effect of rounding off the expected number of flaws per bin 

12 have generally resulted in slightly fewer flaws than expected. As an example, for Inconel 600, 

13 an expected number of 315 flaws was indicated in Table 7-4, rather than the 323 flawed tubes 

14 (323 flaws in previous cycles, plus 31 flaws in the last cycle, and minus approximately 31 

15 plugged tubes) estimated earlier.

16
7-13

1 Table 7-5 Expected Number of Flaws That Belong to a Flaw Bin Defined by Depth and 

2 Length Range for Zion SGs with Tubes Made of Inconel 690

3

Depth/ 

Length

0 cm to 

1 cm

1 cm to 

2 cm

2 cm to 

3 cm

3 cm to 

4 cm

4 cm to 

5 cm

5 cm to 

6 cm

Total

0 to 0.1 1 10 5 1 0 0 17

0.1 to 0.2 4 68 33 8 2 0 115

0.2 to 0.3 2 35 17 4 1 0 59

0.3 to 0.4 1 1 1 0 0 0 3

0.4 to 0.5 0 0 0 0 0 0 0

0.5 to 0.6 0 0 0 0 0 0 0

0.6 to 0.7 0 0 0 0 0 0 0

0.7 to 0.8 0 0 0 0 0 0 0

0.8 to 0.9 0 0 0 0 0 0 0

Total 8 114 56 13 3 0 194

4

5 Using “Wnewbase” as the TH input file, and the flaw length and depth representing the 

6 mid-point of each flaw bin, a series of case runs were performed, using the C-SGTR calculator. 

7 The calculator is discussed in Appendix B. Example calculator input files and runs are also 

8 provided in the appendices.

9

Each case run estimated the probability of an SGTR with an area of at least 1 cm2 (0.16 in.2 10 ) 

before HL or surge line failure. The 1 cm2 (0.16 in.2 11 ) threshold leak area was conservatively 

12 selected as the criteria for a gross tube failure.

13

14 All case runs for the Westinghouse plant in Section 7.1.4 was done by assuming that a flawed 

15 tube can either be exposed to an average hot tube temperature or an average cold tube 

16 temperature. The fraction of tubes exposed to average hot temperature and average cold 

17 temperature used in the analysis were 0.45 and 0.55 respectively. The case runs with the 

18 hottest tube were not performed, mainly due to the following reasons:

19

20 (1) The number of tubes exposed to the hottest temperature is not reported in 

21 NUREG/CR-6995; therefore the probability of flaw locating in the hottest tube cannot be 

22 estimated.

23

24 (2) The hottest tube temperature deviates significantly from the average hot tube 

25 temperature for temperatures exceeding 850 degrees C (1,562 degrees F) (e.g., see 

26 Figure 7-1a, around 225 minutes). Hot-leg failures generally occur before this deviation 

27 takes place. Therefore, the effect of hottest tube temperature could be enveloped with 

28 the average hot tube temperature for flawed tubes.

29

30 The results from these case runs for each flaw bin are presented in Table 7-6 for Inconel 600 

31 and Table 7-7 for Inconel 690. The results reaffirm that for the wear flaws, the bounding 

32 probability of tube failure is only a function of the flaw depth. These results show that a

33 significant contribution to C-SGTR probability for the W representative plant comes only from 

34 flaws with a depth greater than 60 percent. For all smaller flaw sizes the probability that the SG 

35 tubes fails before the HL is estimated to be negligible (i.e., zero). Therefore, it is expected that 

36 the aggregate C-SGTR probability for the average flaw samples shown in Tables 7-4 and 7-5 
7-14

1 will result in negligible or zero C-SGTR probability, because the expected flaw samples shown 

2 in these tables have a depth less than 60 percent.

3

4 Table 7-6 Probability that a Flaw That Belongs to a Bin Defined by Depth and Length 

Range Fails a 5 before the HL Failure for Inconel 600 Tubes for “Wnewbase” TH File for 

6 Westinghouse Representative Plant

7

Depth/ 

Length 1 cm 2 cm 3 cm 4 cm 5 cm 6 cm

Average 

Across 

Length

0.0 to 0.1 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0

0.1 to 0.2 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0

0.2 to 0.3 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0

0.3 to 0.4 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0

0.4 to 0.5 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0

0.5 to 0.6 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0

0.6 to 0.7 ~ 0.05 ~ 0.05 ~ 0.05 ~ 0.05 ~ 0.05 ~ 0.05 ~ 0.05

0.7 to 0.8 ~ 0.8 ~ 0.8 ~ 0.8 ~ 0.8 ~ 0.8 ~ 0.8 ~ 0.8

0.8 to 0.9 ~ 1 ~ 1 ~ 1 ~ 1 ~ 1 ~ 1 ~ 1

0.9 to 1.0 ~ 1 ~ 1 ~ 1 ~ 1 ~ 1 ~ 1 ~ 1

a For Tables 7-6 and 7-7, a conservative screening criteria of a flaw leak area greater than 1 square cm is used to 

determine failure.

8

9 Table 7-7 Probability that a Flaw That Belongs to a Bin Defined by Depth and 

10 Length Range Fails before the HL Failure for Inconel 690 Tubes for “Wnewbase” TH File 

11 for Westinghouse Representative Plant

12

Depth/ 

Length 1 cm 2 cm 3 cm 4 cm 5 cm 6 cm

Average 

Across 

Length

0.1 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0

0.2 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0

0.3 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0

0.4 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0

0.5 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0 ~ 0

0.6 ~ 0.05 ~ 0.05 ~ 0.05 ~ 0.05 ~ 0.05 ~ 0.05 ~ 0.05

0.78 ~ 0.75 ~ 0.75 ~ 0.75 ~ 0.75 ~ 0.75 ~ 0.75 ~ 0.75

0.8 ~ 1 ~ 1 ~ 1 ~ 1 ~ 1 ~ 1 ~ 1

0.9 ~ 1 ~ 1 ~ 1 ~ 1 ~ 1 ~ 1 ~ 1

13

14 Tables 7-6 and 7-7 show the probability of a C-SGTR with a relatively large leakage area 

(i.e., greater than 1 cm2

[0.16 in.2 15 ]) from single flawed tube as a function of the flaw depth. 

16 These probabilities could be viewed as relative indications of the effect of flaw depth on the 

17 C-SGTR probability for the Westinghouse plant. Two observations are made based on these 

18 results:

19
7-15

1 (1) The contribution to C-SGTR probability from flaws with a depth less than 60 percent is 

2 expected to be small.

3

4 (2) Thermally treated Inconel 600 and 690 tube materials have comparable performance 

5 when considering the overall C-SGTR probability.

6

7 The first observation signifies that flawed tubes should be plugged at a threshold depth so that 

8 the possibility of flaw growing to a depth greater than 60 percent in the next cycle is minimized. 

9 The second observation highlights that a lower flaw rate generation in Inconel 690 is offset with 

10 a slightly higher creep rupture resistance of the Inconel 600.

11

12 7.1.4 Estimating C-SGTR Probability

13

14 In this section, the C-SGTR probability is estimated. First, a conservative screening estimate is 

15 made. It is followed by using a best-estimate leak rate is aggregated over all flawed tubes.

16

17 7.1.4.1 A Screening Approach Based on Flaw Depth

18

19 This section provides a simple and quick estimate of C-SGTR probability using information 

20 obtained in the previous section. This approach assumes that only large flaws generated during 

21 the last operating cycle significantly contribute to C-SGTR. This analysis can be used for 

22 risk-informed screening purposes or for evaluating inspection findings in which the surveillance 

23 data is only available for flaw depth. This assumes that all flaws with greater than 30 percent

24 depth were plugged during the last inspection outage and none of the remaining flaws would 

25 grow to more than a 60 percent depth during the operating cycle. Note that leakage areas of 

1 cm2 (0.15 in.2 26 )or larger are included; this is more conservative than the guillotine break size 

27 later used as the critical leak area for the best estimate calculation.

28

29 The approach consists of the following steps:

30

31 (1) Estimate the number of flaws generated during the last operating cycle using 

32 distributions in Section 6.

33

34 (2) Using Table 7-3, estimate the expected number of flaws in each depth bin based on the 

35 total number flaws generated during the cycle.

36

37 (3) Determine the probability of one or more flaws failing during a high/dry/low accident 

38 sequence by multiplying the expected number of flaws in each depth bin by the 

39 conditional probability of the flaw leak area exceeding 1 cm2 (0.16 in.2) during a 

40 representative C-SGTR accident sequence (obtained from Table 7-6 for Alloy 600TT 

41 and 7-7 for Alloy 690TT tubes) and summing across all depth bins.

42

43 As an example of this approach, consider the following example for a Westinghouse plant. As 

44 discussed in Section 7.1.3, assume that 31 flaws were generated during the last cycle for SG

45 tubes made of Inconel 600TT. The probability that at least one flaw out of these flaws belongs 

46 to the three large bins that contribute to C-SGTR (depths of 0.6, 0.7, and 0.8) is estimated by 

47 multiplying the cell probabilities in Table 7-3 by 31 flaws. The C-SGTR probability for each flaw 

48 bin then is estimated by multiplying the resulting number by the conditional C-SGTR probability 

49 for that bin from Table 7-6. The overall C-SGTR probability is then estimated by summing over 

50 the bins. This is shown below:

51
7-16

Depth Bin Probability of 

Flaw Belonging 

to Depth Bin 

(Table 7-3)

Expected 

Number of Flaws 

in Depth Bin

Probability of CSGTR from a 

Single Flaw in

Depth Bin 

(Table 7-6)

Conditional 

Probability of CSGTR for 

Accident 

Sequence

0.6 – 0.7 1.46E-3 0.0453 0.05 0.00226

0.7 – 0.8 3.39E-4 0.0105 0.80 0.00841

0.8 – 0.9 7.70E-5 0.0024 1.00 0.00239

0.9 – 1.0 small small 1.00 small

Total 0.01310

1

2 A similar example using Alloy 690TT tubes with 20 flaws generated during the last operating 

3 cycle yields an estimate of 8.1E-03 for the conditional probability of C-SGTR for the 

4 representative accident sequence.

5

6 Although this approach provides a relatively straightforward method to estimate the potential for 

7 an SG flaw to lead to C-SGTR, it does not consider the potential for the failure of multiple flaws. 

Therefore, a conservative threshold for defining C-SGTR of 1 cm2 (0.16 in.2 8 ) leak area is used.

9 In the next section, multiple flaws are included in a rigorous, but more involved calculation to 

10 estimate the C-SGTR probability.

11

12 7.1.4.2 A Screening Approach Based on Flaw Depth and Length

13

14 A refined method that accounts for both the distributions of flaw lengths and depths is detailed in 

15 Appendix H. This approach focuses on large flaws generated in last cycle and neglects all 

16 smaller flaws that have no potential for C-SGTR. Large flaws are characterized as flaws that if 

17 detected, the associated tube will be plugged. It is believed that the data associated with flaw 

18 sizes of large flaws which are subject to tube plugging, are more precise and less susceptible to 

19 measurement errors. In this approach, both single and multiple tube failures with flaw sizes 

20 capable of creating leakage areas to be considered C-SGTR were evaluated. The results 

21 showed that the contribution from single tube failure is comparable to the estimates obtained 

22 from the previous method. The results showed that for Inconel 600, the single tube failure 

23 contribution to C-SGTR is about 1.31E-2 from both this and previous methods. Similarly, for 

24 Inconel 690, the single tube failure contribution to C-SGTR is 8.1E-3 and 8.9E-3 from the 

25 previous and this method respectively. The contribution of multiple tube failures causing 

26 C-SGTR was estimated to be 8.2E-5 and 3.8E-5 for Inconel 600 and 690. The results are 

27 shown in Table 7-8. The results generally show that the contribution of multiple tube failures to 

28 C-SGTR is negligible compared to single large tube failure.

29

30 Table 7-8 Probability of Single and Multitube Failure in C-SGTR for Inconel 600/690 

31 (Westinghouse)

32 (Early failure of TDAFW pump sequences.)

33

Tube Materials C-SGTR: One Tube 

Failure

C-SGTR: Two Tubes 

Failure

C-SGTR: More Than 

Two Tubes Failure

Inconel 600 1.31E-2 8.24E-5 Negligible

Inconel 690 8.90E-3 3.85E-5 Negligible

34
7-17

1 7.1.4.3 C-SGTR Probability Estimation Using Integrated Flaw Samples

2

3 In this approach, the leak rate is estimated and aggregated over all flawed tubes. It is assumed 

4 that the flaw lengths and depths are available for all tubes in each SG based on the SG periodic 

5 inspection data. This approach could also be used with simulated flaw data for SG tubes, 

6 generated by statistical sampling of flaw generation rate, depth, and size distribution. In this 

7 manner, the approach accounts for the distributions of flaw depth, flaw length, and number of 

8 flawed tubes. This approach is demonstrated in this study for Westinghouse SGs by simulating 

9 a set of flaws which included at least one large flaw (a set of expected flaws plus one large 

10 flaw). This method accounted for single and multiple tube failures and the likelihood that the 

leak area exceeds the critical leak area discussed in Section 2.5 (i.e., 6 cm2 [0.93 in.2 11 ]). This is 

12 the most flexible approach for state of art PRA. It has wide applicability to various regulatory 

13 evaluations; including cases where the actual data from SG periodic surveillance are available.

14

15 As an example, assume that an expected flaw sample consists of 315 flaws was shown earlier 

16 in Table 7-4. A case run was performed with the C-SGTR calculator to estimate the conditional 

17 probability of C-SGTR for these 315 expected flaws in the four SGs. Each flaw was modeled 

18 using the mid-point of its associated flaw bin. For example, a flaw cell with a length ranging 

19 from 2 to 3 centimeter (cm) (0.79 to 1.18 inch [in.]), and a depth ranging from 0.2 to 0.3 cm

20 (0.08 to 0.12 in.), was represented by a flaw with a length of 2.5 cm (0.98 in.) and a depth of 

21 0.25. There would be 28 flaws for this flaw bin; therefore, the same flaw size is repeated 

22 28 times in the flaw file. A C-SGTR software case run was then performed using this flaw file 

23 and the TH case run of “wnewbase.” The results from this case run were used to estimate the 

24 Failure probability (or survival probability) of RCS and C-SGTR as a function of accident time.

25

26 The survival probability of RCS at a given time is defined by the probability that the surge line 

27 has not failed and that none of the four HLs has experienced any failures. An easy way to 

28 combine these probabilities is to estimate the individual hazard rates of each of the RCS 

29 components (four HLs and one surge line) as a function of time. This is done for the individual 

30 RCS components using the following equation.

31

h(tt) = �

dd�FF(tt)�

dd

1−FF(tt)

� = ([FFii+1 − FFii 32 ]/[TTii − TTii+1])/(1 − FFii) (7.1)

33

34 The failure rate for the RCS (λRCS) then can be estimated by the sum of the hazard rates for the 

35 four HLs and the one surge line. λRCS is used to estimate the survival function of RCS. The 

36 RCS survival function is shown in Figure 7-6. The probability that the RCS has not failed at a 

37 given time can be read from the curve. The graph shows a very rapid drop of the survival 

38 probability as a function of time. This indicates that the survival distribution has a small 

39 variance. RCS failure probability can be estimated by the complement of the survival probability 

40 (1-Survival probability).

41

42 Failure probability for SG tubes was estimated by examining the percentiles of the leak area at 

the critical leak area (6 cm2 [0.93 in2 43 ] for this case study) as generated by the C-SGTR software. 

44 The survival probability then was estimated by one minus the failure probability. Figure 7-7

45 shows the percentiles of leak rate area for this case run.

46
7-18

1

2

3 Figure 7-7 Percentiles of the SG leak area distribution as a function of accident time

4

The percentile of the leak area probability at the critical area of 6 cm2 (0.93 in.

2 5 ) was used to 

6 generate the probability distribution for critical failure time. This distribution was used to 

7 calculate the SG survival probability. The resulting survival probabilities for RCS components 

8 and the survival and failure probabilities for SG tubes (with a leak area less than the critical 

9 area) are shown in Figure 7-8.

10

11 The probability of C-SGTR between t to (t + dt), was estimated by the product of the 

12 probabilities that RCS has survived up to time (t) and the SG failure with critical area has 

13 occurred between t and (t + dt).

14

15 PPPPPPPP(CCCCCC CC) =

16 ∫ PPPPPPPP ( ssss ssssssss aa tt) ∗ PPPPPPPP(CCCCCC CC oooo bb bb tt aa aa (tt + ) ∗ (7.2)

17

0

1

2

3

4

5

6

7

8

9

10

14000 14050 14100 14150 14200 14250 14300

Tube leak area (Cm^2)

Accident Time (Sec)

Critical Area

Am

A0.05

A0.25

A0.50

A0.75

A0.95
7-19

1

2

3 Figure 7-8 Survival functions for RCS and SG tube failures with critical leak rate

4

5 Figure 7-8 shows no overlap between the SG failure probability and RCS survival function; 

6 therefore, indicating a negligible probability of the occurrence of C-SGTR for this set of flaws 

7 (i.e., SGTR failure with an area greater than critical area can occur before RCS fails).Simple 

8 numerical integration, using spread sheet calculations, shows that this probability is practically 

9 zero because of very small variances of the two random variables depicted by the survival 

10 graphs (less than 1.0E-10).

11

12 Although the above conclusion is valid for the expected flaw sample set, it may not hold when a 

13 flaw sample deviates from the expected set. Past experiences have shown that, even with a 

14 low probability, there is some possibility of detecting one or two large flaws at the end of an 

15 operating cycle. This is the main reason why much higher SGTR probabilities were calculated 

16 in the previous sections. To examine this hypothesis and its effect on C-SGTR probability, 

17 additional case runs were performed using the earlier expected flaw sample by adding an 

18 additional large flaw. The earlier results showed that the additional large flaw needs to be larger 

19 than 60 percent of the nominal depth to effectively change the C-SGTR probability.

20

21 A case run was, therefore, performed using the expected flaw set and an added flaw with a 

22 length of 3.5 cm (1.4 in.) and depth of 65 percent. Figure 7-9 shows the percentiles of leak rate 

23 area for this case run.

24

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

12000 12500 13000 13500 14000 14500 15000

Probability 

Time (S)

Survival Probability 

 RCS Survival

SG Survival

SG Failure Probability
7-20

1

2

3 Figure 7-9 Percentiles of the SG leak area distribution as a function of accident time

4

Using the percentile of the leak area probability at the critical area of 6 cm2 (0.93 in.2 5 ), the 

6 probability distribution for critical failure time was generated. This distribution was used to 

7 calculate the SG survival probability. The resulting survival probabilities for RCS components 

8 and SGs for this case are shown in Figure 7-10 below.

9

10

11

12 Figure 7-10 Survival probability functions for RCS and flawed tubes

13

14 This graph shows a significant overlap between the two survival probabilities. When the RCS 

15 survival probability is very close to one (around 12,900 seconds), the probability of C-SGTR is 

16 as high as a 40 percent (i.e., 1 - 0.6). Therefore, the probability that C-SGTR could occur 

17 before HL failure is expected to be greater than 40 percent. In fact, simple numerical 

0

2

4

6

8

10

12

14

16

18

20

10000 11000 12000 13000 14000 15000

Leak area for SGTR (Cm^2)

Time (s)

Am

A0.05

A0.25

A0.50

A0.75

A0.95

0

0.2

0.4

0.6

0.8

1

1.2

10000 11000 12000 13000 14000 15000 16000

Probability

Time (S)

Survival Probability Functions

RCS Survival

CSGTR
7-21

1 integrations, using spread sheet calculations, show that the conditional C-SGTR probability, 

2 given the specified 65-percent depth flaw and accident sequence, is about 0.47.

3

4 7.1.4.4 Summary of the Results of C-CSGTR Calculations

5

6 In Sections 7.1.4.2, 7.1.4.3, and 7.1.4.4, the C-SGTR probability was calculated for the 

7 Westinghouse-type SGs by three methods; each with different assumptions and complexity. 

8 This is done since the calculator does not directly assess the C-SGTR probability, but it only 

9 calculates the progression of the total leak area resulting from a set of input flaws. Other

10 calculations must be made to get a probability of C-SGTR for a specified critical leak 

11 area. Therefore, using the calculator to determine the distribution of C-SGTR probability, which 

12 accounts for variations among the plants and the performance of their SGs as reflected by a 

13 large number of flaw sets, would be difficult. A set of flaws, which are determined, or sampled, 

14 exterior to the calculator, are placed as an input for the calculator. Thus, the three methods 

15 discussed in this section are designed to provide quantitative insights to the expected probability 

16 of C-SGTR without performing large numbers of simulations.

17

18 The results of each of the methods are summarized in Table 7-9 along with the assumptions 

19 used. The benefits and limitations of each approach are briefly discussed below.

20

21 • Integrated Analysis: The method in Section 7.1.4.4 uses a single flaw set to determine 

22 the expected probability of C-SGTR among all similar Westinghouse plants. This flaw 

23 set reflects the flaws and the flaw sizes expected (i.e., averaged over all similar plants) 

24 in cycle 15 of their operations. Using the average flaw set as input, the calculator is 

25 expected to estimate the probability of C-SGTR in an average plant. There could be 

26 plants with higher or lower C-SGTR probability as reflected by their plant-specific flaw 

27 sets. The method in Section 7.1.4.4 is the most rigorous, and it can be used for 

28 plant-specific analysis when plant-specific flaw data is available. It involves calculations

29 that are in the spirit of this project. The results from this method indicated that the 

30 C-SGTR probability when averaged over all observed flaws will be small for the 

31 Westinghouse plants with similar TH behavior (i.e., ~1.0E-3 or less limited by uncertainty 

32 routines and samples used in the calculators). The result is shown as “negligible” in 

33 Table 7-9 reflecting a small C-SGTR probability for all similar Westinghouse plants.

34

35 • Refined Screening Approach: The calculation in Section 7.1.4.3 uses an expected 

36 plugging rate (average over all plants) at cycle 15 of operation. The number of tubes 

37 that will be plugged at the end of cycle 15 therefore follows a binomial distribution with 

38 the specified rate. The flaw sizes associated with these plugged tubes (i.e., the flaw 

39 bins) are estimated based on the tails of the flaw size distributions. This can be done for 

40 W plants because only large flaw sizes will contribute to probability of C-SGTR. This 

41 method estimates the contribution to C-SGTR from a failures of single and double large 

42 flaws. It shows that the contribution of failures of multiple flaws to C-SGTR is much 

43 smaller than the contribution of failure of single flaw. However, the probability of 

44 C-SGTR or its contribution from each flaw bin estimated by this method is not as 

45 rigorous as the method in Section 7.1.4.4. The contribution to the probability of 

46 C-SGTR, as a result of failure of a flaw in a bin, is estimated approximately by the 

47 probability that a relatively large C-SGTR leakage occurs before the time that HL failure 

48 probability reaches 0.5. Relative large leakage should be defined here as a leakage 

49 area below the critical C-SGTR leakage area (guillotine break of one tube), since each 

flaw is examined individually as its potential to contribute to C-SGTR. A value of 2 cm2 50

(0.31 in.

2 51 ) was used as the minimum leakage area for this method.
7-22

1

2 • Screening Approach: The calculation in 7.1.4.2 is very similar to the calculation in 

3 7.1.4.3 with the following differences:

4

5 – No specific rate for plugged tubes was used and the expected number of flaw in 

6 a large flaw bin was estimated based on the distributions of flaw depth and 

7 length. Possible variations of number of flaws within a flaw bin of large flaws is 

8 not considered (i.e., no binomial distribution was applied).

9

– A value of 1 cm2 (0.16 in.2

) rather than 2 cm2 (0.31 in.2 10 ) was used for the 

11 minimum leakage area.

12

13 Although this method is the least rigorous of the three methods, it generated similar 

14 quantitative results for probability of C-SGTR and offered a quick method to estimate the 

15 C-SGTR probability using the “lookup tables” calculated from the results the calculator 

16 for a set of runs. This method is therefore quite easy to use and provides reasonable 

17 estimates for many PRA applications.

18

19 Table 7-9 Summary of 3 Types of C-SGTR Failure Probability Estimates Discussed in 

20 Sections 7.1.4.2, 7.1.4.3, and 7.1.4.4

21

I. Considering Deep Flaws 

Only (7.1.4.2) > = 60% Deep

Screening Approach

II. Considering Deep Flaws 

with Size Distribution Only

(7.1.4.3) >= 50% Deep

Refined Screening Approach

III. Considering a Sample of 

Flaws (7.1.4.4) of All Sizes and 

Depths

Integrated Analysis

EFPY = 15 EFPY = 15 EFPY = 15

31 flaws generated in the last 

cycle – earlier deep flaws are 

plugged

1 to 3 deep flaws were 

generated in the last cycle 

(binomial probability with a fixed 

rate) – earlier deep flaws are 

plugged

315 flaws in 4 SGs

(statistical sample)

Critical area for declaring SGTR 

is >= 1 cm2

Critical area for declaring SGTR 

is >= 2 cm2

Critical area for declaring SGTR 

is >= 6 cm2 (equivalent to a 

guillotine break of one tube)

C-SGTR Probability

Alloy 600 1.3E-2 Alloy 600 1.3E-2 1 tube (*) Negligible (**)

Alloy 690 8.1E-3 Alloy 690 8.1E-3 1 tube

Alloy 600 8.2E-5 2 tubes (**)

Alloy 690 3.9E-5 2 tubes

Greater than 2 tubes - negligible

Notes:

* Using probability that one large flaw is created in the 15th cycle.

** Based on C-SGTR runs with sampled flaws: the margin between hotleg failure time and SG tube failure time 

(for the critical leak area to be reached) is large and the overlap in uncertainty is insignificant.

22

23 The two screening approaches are applicable only if the major contribution to C-SGTR is from a 

24 few large flaws. The screening approaches cannot be used, if the TH run for an accident 

25 scenario used as an input to the calculator, indicates that small flaws will also contribute to the 

26 probability of C-SGTR. For these cases, only the integrated analysis method should be used for 

27 either generic industrywide analysis or plant specific analysis. This is the case for the TH 
7-23

1 results of the SBO scenarios for the selected CE plant. Therefore, the two screening 

2 approaches will not be discussed for the CE plant analysis, which follows in Section 7.2.

3

4 7.1.5 Estimating Containment Bypass Frequency

5

6 Table 7-8 of Section 7.1.4.2 provides the estimates for the probabilities of single and multitube 

7 failure leading to C-SGTR for Inconel 600/690 for a core damage sequence initiated by SBO 

8 and with an early failure of turbine driven auxiliary feedwater (AFW) pump. The occurrence of 

9 such C-SGTR would lead to a containment bypass scenario. All the containment bypass 

10 scenarios have a potential to become a LERF scenario if the release is large. Furthermore, for 

11 a large release to be considered as LERF it should start early before an effective evacuation, 

12 and not terminated by successful SAMG actions.

13

14 A preliminary estimate of the annual frequency of containment bypass because of consequential 

15 failures of one or more tubes was discussed earlier. There are two additional contributors to 

16 containment bypass caused by C-SGTR that were not included in the earlier estimates. These 

17 are briefly discussed below:

18

19 (1) Operators are expected to start the RCPs (bump the pumps) and transfer the 

20 accumulated water in the loop seal into the vessel, thereby clearing the loop seal. This 

21 is only applicable if the offsite power is recovered after the onset of core damage, and 

22 the operator fails to restore the secondary cooling first. Unlike CE (and Babcock & 

23 Wilcox (B&W)) plants, Westinghouse SAMG does not explicitly require the operator to 

24 bump the pumps. It is, therefore, expected to be unlikely for the operators at a 

25 Westinghouse plant to inadvertently perform such errors of commission.

26

27 (2) Operators are expected to introduce secondary cooling to an SG that has dried out, after 

28 alternating current (ac) power is recovered. This action is expected to be performed 

29 slowly and the operator should maintain certain cooling/flow limits. The SG tubes are 

30 considered ductile and for recirculating (U-tube) SGs, the tubes can expand axially. The 

31 SAMG, and the emergency operating procedure guidance, on limiting cooling 

32 rate/secondary flow appears to be intended to limit the added strain because of thermal 

33 shock because of steep temperature gradient across the tube wall. For the purpose of 

34 PRA analysis, it is assumed that a significant deviation from the recommended limits for 

35 introducing the cold feed water into a hot SG could result in tube failures. Introduction of 

36 cold water into a dry SG could also take place before the onset of core damage. 

37 Therefore, it has a specific procedure under EOPs. Operators are fully aware of the 

38 limits associated with this action. Should tubes rupture as a result of the introduction of 

39 cold water into a dry SG, the radioactive releases are expected to be significantly less 

40 than C-SGTR accident with a dry SG secondary side. The presence of subcooled water 

41 in the secondary side of the SG is expected to provide a scrubbing action of the 

42 radioactive releases and significantly reduces the offsite consequences. The 

43 contribution from this mechanism, therefore, is expected to be significantly lower than 

44 other mechanisms for multiple tube failures.

45

46 A simplified SBO event tree in Figure 7-11 depicts the three types of SBO core damage 

47 sequences most likely to dominate the C-SGTR risk:

48

49 (1) Sequences with early failure of AFW: For these sequences the containment bypass 

50 fraction is defined as Q1. Value of Q1 is approximately set to 0.01 for both Inconel 600 

51 and 690 (See Table 7-8 in Section 7.1.4.2).
7-24

1

2 (2) Sequences with loop seal clearance are assigned to the containment bypass fraction 

3 Q2: the value of Q2 is equal to 1.0. Note that TH runs indicated that the probability that 

4 the loop seal is cleared is almost certain if the RCP leakage is about 1,703 liters per 

5 minute (Lpm) (450 gpm) per pump. For RCP seal leakage of 1,135 Lpm (300 gpm), the 

6 TH analysis predicted no possibility that the loop seal is cleared. For the purpose of a 

7 bounding analysis, the probability of loop seal clearing is considered to be 0.1 when the 

8 proceduralized operator action of rapid depressurization fails (seal leakage range of 

9 1,135–1,817 Lpm (300–480 gpm) per pump exists); 0.0025 when this operator action is 

10 successful (only 1,817 Lpm (480 gpm) per pump seal leakage scenario is postulated).

11

12 (3) Sequences with the failure of TDAFW pump in the intermediate timeframe 

13 (approximately 4 hours) (long timeframe for ac recovery is related to recovery of ac even 

14 later for crediting other recovery actions for dealing with releases): although the 

15 C-SGTR probability and the fraction of containment bypass could vary, depending on the 

16 depressurization scheme, it is bounded by twice the values estimated for the SBO 

17 sequences with an early failure of TDAFW. The containment bypass fraction Q3 is 

18 assigned to these sequences. The estimate for this fraction is currently considered to be 

twice the value for the sequences with early failure of the TDAFW pump, namely 2Q1.1 19

20

21 These containment bypass (Cont.-BP) fractions are to be used with individual core damage 

22 sequences. An example of using these containment bypass fractions in a sequence from an 

23 internal event SBO sequence is shown in Figure 7-12. The probabilities used are deemed to be 

24 representative of the event tree nodes typically used in PRA models.

25

26 For other SBO events, such as those induced during seismic, external flooding, and high wind 

27 related events, the ac power recovery could be drastically different from the internal events. 

28 Figure 7-13 presents an example of an external event driven SBO event tree for quantification 

29 of containment bypass probability due to C-SGTR.

30

31 One can also define an additional containment bypass fraction that could be used with an SBO 

32 core damage frequency (instead of being used with an individual SBO sequence). In 

33 Figures 7-12 and 7-13, this frequency is calculated as the ratio of the total C-SGTR frequency to 

34 the total CDF frequency. The values estimated in these two figures are 0.02 and 0.018 

35 respectively.

 1 Both in Westinghouse and CE TH input files exhibit the following property when the SG tube temperatures reach the

 creep-rupture range, namely 600–700 degrees Celsius (1,112–1,292 degrees Fahrenheit): the temperature 

 difference between the HL and the average tube temperature is larger for the scenarios where AFW (TDP) fails at 

 T=0, compared to when the AFW fails at T = battery depletion. This results in a higher likelihood for HL failure in the

 case with earlier AFW failure. Thus, the C-SGTR probability is higher for the sequences with “late” failure of AFW. 

 This phenomenon is illustrated in Figures 7-15 and 7-16 for early AFW failure and Figures 7-18 and 7-19 for late 

 AFW failure. It should be noted that the C-SGTR, if it occurs, occurs much later in the sequences with late AFW 

 failure, compared to sequences where AFW fails at T=0.
7-25

SBO AFW

Operating

ST Power 

Recovery

Rapid Secondary 

Depressurization

Loop Seal 

Intact

IT Power 

Recovery

CD with 

H/D/L

Loop 

Seal 

Intact

YES 1 No

YES

NO 2 Yes Yes 

YES

YES 3 No

NO

NO 4 Yes No 

YES 5 No

YES YES

NO 6 Yes Yes 

NO

YES 7 No

NO

NO 8 Yes No 

YES 9 No

NO

NO 10 Yes N/Q 

1

Figure 7-11 Definition of bounding SBO sequences with high/dry/low (H/D/L) conditions 2

3

4
7-26

Notes: 1

a. N/Q = Not Questioned 2

b. ST (short term ac power recovery) refers to 1–2 hours following failure of TDAFW Pump (fails to 3

c. IT (intermediate term ac power recovery) refers to 4–6 hours following later failure of TDAFW Pu4

battery depletion) 5

d. ac power can also be recovered later than the IT window. This can be credited for release freque6

is not used in the current estimates. 7

e. SBO refers to occurrence of loss of offsite power event coupled with loss of emergency ac power8

f. Power recovery refers to reestablishment of either offsite on onsite emergency power to at least 9

related ac buses. 10

g. Loop seal is intact if 1,817 Lpm (480 gpm) per pump and 1,135 Lpm (300 gpm) per pump RCP s11

accident (LOCA) does not occur. 12

h. If rapid secondary depressurization is successful, the primary is depressurized similar to SCDAP13

153 and 153A. The core damage and C-SGTR is occurring late due to accumulator discharge. 14

i. If rapid secondary depressurization is not successful, then the sequence is assumed to be the sa15

early failure of TDAFW with time line shifted by 4 hours. 16
7-27

SBO Occurs 

(frequency)

AFW 

Operates

ST Power 

Recovery

Rapid Secondary 

Depressurization

Loop Seal 

Intact

IT Power 

Recovery

Sequence 

Frequency

C-SGTR 

Fraction

1

1.0E+00

2.0E-01 2 9.E-07 0.02 

1.0E+00

3

2.5E-03

4.0E-01 4 4.E-09 1. 

5

9.0E-01 9.0E-01

2.0E-01 6 4.E-09 0.01 

5.0E-03

5.0E-06 7

1.0E-01

4.0E-01 8 9.E-10 1 

5.0E-01 9

1.0E-01

5.0E-01 10 3.E-07 0.01 

Sum = 1.2E-06 

1

Figure 7-12 An estimate of bounding SBO sequences frequencies leading to C-SGTR and containm2

3
7-28

SBO Occurs 

(Seismic, Ext. 

Flooding, 

Wind)

AFW 

Operates

ST Power 

Recovery

Rapid Secondary 

Depressurization

Loop Seal 

Intact

IT Power 

Recovery

Sequence 

Frequency

C-SGTR 

Fraction

1

1.0E+00

5.0E-01 2 2.E-06 0.02 

1.0E+00

3

2.5E-03

7.0E-01 4 8.E-09 1 

5

9.0E-01 9.0E-01

5.0E-01 6 1.E-08 0.01 

5.0E-03

5.0E-06 7

1.0E-01

7.0E-01 8 2.E-09 1 

0.0E+00 9

1.0E-01

1.0E+00 10 5.E-07 0.01 

Sum = 3.E-06 

1

Figure 7-13 Another estimate of bounding SBO sequences frequencies leading to C-SGTR and conta2

3
7-29

1 Earlier in this section, the total frequency of SBO core damage sequences for internal events 

2 only, and for all hazard categories, were shown to be 5.2E-06/year and 2.0E-05/year 

3 respectively. To estimate the containment bypass frequency due C-SGTR for these two cases, 

4 a containment bypass fraction of 0.02 will be used. Note that this fraction is consistent with the 

5 two corresponding values estimated in Figures 7-12 and 7-13.

6

7 For internal event SBOs:

8

9 Cont.BPC-SGTR = CDF * 0.02 = 5.2E-06 * 0.02 = 1E-07/year.

10

11 For SBOs from all hazard categories:

12

13 Cont.BPC-SGTR = CDF * 0.02 = 2.0E-05 * 0.02 = 4E-07/year.

14

15 The estimates from this section are further summarized in Table 7-12.

16

17 7.1.6 Level 2 Analysis of C-SGTR for ZNPP

18

19 This section expands on the discussion provided in Chapter 3 on simplified Level 2 analysis. A 

20 prolonged SBO event is considered as an entry level for the Level 2 analysis. TDAFW is 

21 demanded right after SBO. The time required for SG dry out is about an hour and a half based 

22 on TH analysis as shown in Figure 7-1 for the case “Wnewbase.” The vessel breach is not 

23 expected until at least 8 hours after core uncovery. The recovery of offsite power in less than 

24 8 hours is necessary for crediting the SAMG activities. The timing for the major events 

25 corresponding to the accident progression of a scenario of an SBO and early failure of TDAFWs 

26 is shown in Table 7-10. These timings are generated by a combination of RELAP results and 

27 sensitivity case runs with C-SGTR software.

28

29 The following observations can be made based on an examination of the information shown on 

30 this table:

31

32 (1) For cases that the primary pressure is maintained at the primary relief set point 

33 (approximately 15.2 MPa, or 2,200 psi), the HL is expected to fail before the occurrence 

34 of SGTR unless there are one or more large flaws with a depth of at least 60 percent in 

35 one of the SGs. This is generally consistent with the deterministic results obtained from 

36 RELAP runs.

37

38 (2) For cases where there is at least one large flaw in one of the SGs such that C-SGTR 

39 occurs early shortly after core uncovery, the HL is expected to fail in less than 15 

40 minutes after C-SGTR as long as the primary is not significantly depressurized. 

41 Therefore, the releases through containment bypass are expected to be small and last 

42 for a short duration. This statement is valid even if the primary is somewhat 

43 depressurized as long as it stays above the accumulator setpoint (4.82 MPa, or 700 psi).

44

45 (3) Cases where primary pressure is reduced below 4.82 MPa (700 psi), such that the 

46 accumulators are discharged, core melt is expected to be arrested and delayed and HL

47 failure is not expected to occur before restart of the core melt and repressurization of 

48 primary. In such cases, the releases are expected to be late and possibly diverted into 

49 the containment rather than through the containment bypass. LERF cases can mainly 

50 occur if secondary relief valves are open (either intentionally or by stick open failures) 
7-30

1 post C-SGTR, such that primary system remains depressurized, therefore significantly 

2 reducing the probability that HLs fail.

3

4 Table 7-10 Timing of Major Events during an SBO with Early Failures of TDAFWs 

5 (Wnewbase with Inconel 600 TT SG)

6

Time Events for Extended SBO with Early Failure of TDAFWs

0 SBO started

~ 14 minutes ECCS signal actuated

~ 2 hours 30 minutes Onset of core uncovery, corresponding to 1200 °F

~3 hours 30 minutes 50% probability of HL failure if the primary pressure remains 

around 2200 psi after onset of core uncovery (as estimated by 

C-SGTR software)

~3 hours 30 minutes Cladding damage and start of gap release

Around 3 hours 30 minutes to 3 

hours 45 minutes

Some likelihood that SGTR with varying leak rates occurs if there 

is at least one flaw larger than 60% of nominal depth 

Around 3 hours 45 minutes HL failure if the primary pressure reduced to around 700 psi (but 

above accumulator discharge pressure) at the time of core 

uncovery due to the opening of a PORV or stuck open of a single 

PORV and SRV b

~ 4 hours DC assumed depleted a

Between 7 to 8 hours Core structure failures, fuel melting and quenching. Start of 

in-vessel releases 

~ 8 hours HL failure if the primary is fully depressurized at the onset of core 

uncovery b

a Although RELAP models assume dc is depleted in 4 hours for both early and late failure of TDAFWs, PRA 

considers DC to be available for a longer duration for the case when TDAFWs were not available at time zero. 

The availability of DC will facilitate SAMG activities such as depressurization of primary and secondary. b These values were supported by sensitivity runs performed using C-SGTR software.

7

8 For those cases where TDAFW is operating, the time to core uncovery depends on the scheme 

9 used for primary depressurization. Two cases were analyzed by RELAP models: Case 153 

10 and 153A. In both cases aggressive cooling and depressurization using secondary system 

11 resulted in the dropping of primary pressure below the accumulator discharge setpoint. The 

12 discharge of accumulator resulted in core uncovery to be delayed significantly (about 11 hours 

13 for Case 153 and 13 hours for Case 153A). The C-SGTR and HL failure occurred shortly after 

14 the onset of core uncovery. If the operators do not take any action to depressurize and perform 

15 aggressive cooling although they are instructed by the EOPs to do so, the scenario is expected 

16 to follow similar to that of SBO with early failures of TDAFW but after the secondary cooling is 

17 lost. The time associated with the sequences of events in this case is similar to the case 

18 “Wnewbase” but they are shifted by at least 4 hours. As an example, in this case, the onset of 

19 core uncovery is expected to occur in 6 hours and 33 minutes with the core damage starting at 

20 around 8 hours. There is currently no SCDAP/RELAP case run available for this case.

21

22 The timing for the major events corresponding to the accident progression of a scenario of an 

23 SBO and the failure of TDAFWs after battery depletion is shown in Table 7-11 for normal 

24 depressurization scheme (RELAP Case 153). These timings are generated by a combination of 

25 SCDAP/RELAP results and sensitivity case runs with C-SGTR.

26
7-31

1 Table 7-11 Timing of Major Events during an SBO with Failures of TDAFWs after Battery 

2 Depletion (SCDAP/RELAP case 153 with Inconel 600 TT SG)

3

Time Events for Extended SBO with Early Failure of TDAFWs

0 SBO started

~ 4 hours DC assumed depleted

~ 11 hours and 30 minutes Onset of core uncovery, corresponding to 1200 °F

~12 hours 30 minutes to 12 hours 

45 minutes 

Some likelihood that SGTR with varying leak rates occurs if there 

is at least one flaw bigger than 50% depth

~12 hours and 45 minutes HL Failure

~13 hours 30 minutes Cladding damage and start of gap release

4

5 Estimating the frequency of containment bypass because of C-SGTR was detailed in 

6 Section 7.1.4. The fractions of Containment bypass scenarios that can lead to LERF, depends 

7 on the success probabilities of SAMG actions and effective evacuation. These two items are 

8 part of the five-factor formula proposed for LERF estimation as it was discussed in Section 2.6.

9

10 A review of the SAMG actions for Westinghouse plants was performed as a part of this study. 

11 From the PRA’s perspective, there are two major SAMG actions:

12

13 (1) to arrest the core melt within the vessel by depressurization and injecting water

14

15 (2) to reduce radioactive release magnitude by scrubbing through depressurizing the SG 

16 and filling it up with an alternate water source

17

18 The vessel can be depressurized by opening all PORVs (both PORVs are required to open 

19 based on the success criteria identified in TH case runs for post core damage in ZNPP) if ac

20 power is restored or the availability of DC power is ensured via load shedding or through other 

21 means. Relieving the primary pressure would allow injection from either the high pressure or 

22 low pressure ECC systems. RCS depressurization could also take place because of medium or 

23 large LOCA, but not small LOCA post core damage.

24

25 Primary depressurization for SBO scenarios with early failure of TDAFW could result in 

26 discharge of the accumulator water into the vessel which could provide more time for the 

27 operator to align the makeup water sources to reactor water storage tank (RWST) for later 

28 injection into vessel. Injection into the vessel is assumed to arrest core melt, and therefore, limit 

29 the in-vessel releases. Two cases were analyzed in NUREG/CR-6995 (Ref.-1): Case 153 and 

30 153A. In both cases aggressive cooling and depressurization using secondary system resulted 

31 in the dropping of primary pressure below the accumulator discharge setpoint. The discharge of

32 accumulators resulted in core uncovery to be delayed significantly (about 11 hours for Case 153 

33 and 13 hours for Case 153A). These cases were not considered to be LERF since the 

34 radioactive releases will be late and expected to occur after the initiation of effective evacuation.

35

36 RCS depressurization through the PORVs or the occurrence of medium or large LOCA would 

37 also create a major path of release into the containment rather than through the ruptured SG 

38 tubes. A lower magnitude of releases would, therefore, be expected. These cases were also 

39 not considered to be contributors to LERF.

40
7-32

1 SAMG also recommends depressurizing the SG using the available relief paths when an SG 

2 tube ruptures, and filling the SG secondary side using motor-driven AFW trains after power is 

3 recovered. If power is not recovered, injection from low pressure alternate water sources such 

4 as fire water could be used. As guided by TH analysis, operation of the atmospheric dump 

5 valve (one per SG) or opening of main stem isolation valves (MSIVs) and bypass valves, will be 

6 required if an alternate source of water is implemented. SG depressurization would require both 

7 dc power as well as instrument air. Local manual operation could also be performed and may 

8 not require dc power. However, the possibility of a high radiation environment should be 

9 considered.

10

11 The emergency response timeline and the process for effective evacuation of the SBO scenario 

12 with early and late failure of TDAFW (e.g., after batteries are depleted) was discussed in 

13 Section 2.6. It was concluded that the evacuation is most likely effective for C-SGTR 

14 containment bypass events during SBO scenarios with late failures of TDAFW and not effective 

15 for SBO scenarios with early failure of TDAFW. The only exception to this general rule is the 

16 C-SGTR containment bypass scenarios of SBO with late failure of TDAFW, and the failure of 

17 operators to rapidly depressurize the primary through secondary systems. As discussed earlier, 

18 in such scenarios the time available for effective evacuation could be reduced to less than 10 

19 hours for some plants, such that assuming probability of 1 for successful and effective 

20 evacuation during some external events may not be conservative. Site and plant specific 

21 analysis may be needed to address the probability of effective evacuation for such cases.

22

23 7.1.7 Quantification of Level 2 Models

24

25 A simplified LERF model that relies on five factors was discussed in Section 2.6. These factors 

26 are:

27

28 (1) frequency of severe accident sequences with potential for C-SGTR (fAC), as discussed in 

29 Section 7.1.2

30

31 (2) C-SGTR probability (PCSGTR), see discussion for estimating containment bypass 

32 probability in Section 7.1.5

33

34 (3) Conditional Probability that the subsequent failure of RCS including the stuck open relief 

35 valves do not occur (PNDEP)

36

37 (4) Failure Probability of all SAMG actions (PSAMG)

38

39 (5) probability that early effective evacuation is not successful (PEVAC)

40

41 The issues considered for estimating PNDEP, PSAMG, and PEVAC are qualitatively discussed below. 

42 Some values are suggested for each of these three parameters for estimating the bounding 

43 values of LERF.

44

45 PNDEP: Failure of the HL shortly after C-SGTR or stick open failures of at least two primary relief 

46 valves (SRVs/PORVs) will divert most of its releases into the containment; thereby significantly 

47 reducing the conditional LER (large early release) probability, given a containment bypass is 

48 caused by C-SGTR. For cases where only one relief valve fails to reclose (sticks open), the HL

49 failure would be delayed because of primary depressurization. The conditional LER probability 

50 given containment bypass will therefore increase. Note that the above discussion is not 

51 applicable when TDAFW is initially available and primary is further depressurized by rapid 
7-33

1 secondary cooling. In such cases, the primary pressure is expected to be initially reduced 

2 below 4.82 MPa (700 psi) because of rapid primary depressurization through secondary, and 

3 through the stick open primary relief valve. Accumulators are then discharged, core melt is 

4 delayed, and C-SGTR and HL failure are not expected to occur before the restart of core melt. 

5 The release through containment bypass is expected to be relatively small (a portion of release 

6 will be diverted into the containment through stick open relief) and the release would be late. It 

7 is, therefore, not considered as LERF. Generally, the conditional probability that C-SGTR is not 

8 followed shortly (e.g., less than 30 minutes) by a large primary openings (i.e., PNDEP) is expected 

9 to be small (much less than 1). As discussed, the only possible way for a containment bypass 

10 because of C-SGTR to result in LERF, is when only one of the primary relief valves (SRVs or 

11 PORVs) sticks open after core uncovery. However, the performance of these relief valves after

12 onset of core damage, is not well understood. The probability that the relief valves sticks 

13 because of limited clearance in some parts, under the harsh environment of after core damage 

14 in severe accident scenarios, is not known. These components are demanded under a severe 

15 accident condition, although they are generally qualified for design-basis accidents (DBAs). For 

16 these reasons and for the purpose of bounding evaluation, a value of 1 is assigned to PNDEP.

17

18 PSAMG: A bounding value of 1.0 is proposed for PSAMG to obtain a bounding estimate of LERF. 

19 This crude approach is implemented because the state of knowledge in modeling operator 

20 performance after core damage for performing SAMG activities is also quite limited. SAMG’s 

21 actions are not procedure based; they are directed by emergency directors, coordinated by 

22 emergency coordinators, and executed by emergency responders and operators. For the 

23 SAMG, there is no scripted compliance. The appropriate actions must be defined “on the fly” 

24 based on the understanding of the plant conditions, and the pros and cons of carrying out a 

25 particular set of actions versus an alternative set of actions or no action at all (see Lutz, et 

26 al., 2008). This is considered as a human decisionmaking process that would be influenced by 

27 complexity of the situation, training, and other personal attributes of the operator. The human 

28 reliability model for these actions, under severe accident conditions, is expected to be different 

29 than those governed by EOPs. Finally, the effectiveness of SAMG activities under different 

30 accident conditions is not known.

31

32 PEVAC: These timing diagrams discussed in Section 2.5 indicate that there is a high likelihood 

33 that effective evacuation can be completed for all SBO scenarios with an initial availability of 

34 TDAFW, and a successful aggressive depressurization through secondary cooling. Therefore, 

35 for all these scenarios, the value estimated for PEVAC is considered to be zero. For SBO 

36 scenarios with initial availability of TDAFW, but failure of aggressive depressurization through 

37 secondary cooling, releases can occur at an earlier time, but only after at least 8 hours. The 

38 time of the release will depend on the battery capacity and the duration of dc power availability,

39 including potential load shedding. Furthermore, the failure probability for aggressive 

depressurization is expected to be small, about 1.0 ×10-3 40 per demand. Therefore, for all SBO 

41 scenarios with an initial availability of TDAFW, PEVAC was assigned a value of zero.

42

43 The same timing diagrams revealed that there is a high likelihood that effective evacuation 

44 cannot be completed in time for all SBO scenarios with early failure of TDAFW. Therefore, 

45 PEVAC is assigned a failure value of 1.0 to all SBO scenarios with an early failure of TDAFW.

46

47 The conditional LERF probabilities because of C-SGTR for SBOs with early or late failures of 

48 TDAFW are summarized below in Table 7-12.

49
7-34

1 Table 7-12 Conditional LERF Probabilities for an SBO with Early and Late Failures 

2 of TDAFW for Representative Westinghouse Plant

3

Factors Applicability LERF Factors a

PCSGTR Because of one or more tube breaks in an SBO CD 

Sequence 1.3E-2

 — Due to single tube breaks only 1.3E-2

 — Due to multiple tube breaks 8.2E-5

In an SBO, CD Sequence with loop seal clearing 1.0

PNDEP In an SBO, CD Sequence with loop seal clearing or 

multiple Tube breaks 1.0

In an SBO, CD Sequence with one tube breaks 1.0 b

PSAMG In an SBO, CD Sequence with loop clearing or 

multiple Tube breaks 1.0

In an SBO, CD Sequence with one tube breaks 1.0 b

PEVAC In an SBO, CD Sequence with early failure of TDAFW 1.0

In an SBO, CD Sequence with late failure of TDAFW 

(at least with 4 hours battery capacity) 0

a LERF factors are applicable to both SBO scenarios with early and late failure of TDAFW unless it is specifically 

identified. b This value is believed to be conservative and it is used for screening purposes only.

4

5 A crude estimate of the conditional probability of containment bypass for all the prolonged SBO 

6 scenarios is about 0.02 when considering scenarios involving loop seal clearing. The CDF from 

7 SBO sequences, considering all hazard categories is about 2.0E-05/year from Table 7-1. This 

8 CDF multiplied by the conditional probability of containment bypass (0.02) gives a bounding 

9 containment bypass frequency estimate of 4E-07/yr for all hazard categories. Please note that 

10 the LERF estimate is negligible (approximately 0), since only the containment bypass resulting 

11 from the SBO scenarios with early failure of TDAFW have a potential for LERF.

12

13 A bounding estimate of the conditional LERF probability, given an SBO with early failure of 

14 TDAFW, is about 0.02. The all hazard CDF multiplied by the early failure probability of TDAFW 

15 (approximately 0.1) and the LERF fraction of 0.02, gives a bounding LERF estimate of 4E-08/yr 

16 for all hazard categories. Considering SBO CDF for internal events only is 5.2E-06/yr, the 

17 LERF estimate due to C-SGTR for the representative W plant is about 1.0E-08/yr for internal 

18 events.

19

20 7.1.8 Concluding Remarks

21

22 Occurrence of C-SGTR, Containment bypass probability, and LERF are significantly influenced 

23 by the TH results obtained from various case studies. These TH results reflect the specific 

24 design, configuration, and geometry of the plant systems specifically the SG design and primary 

25 connections such as HL and surge line. They should not be interpreted as generic results for W 

26 plants. The more important plant features that can affect the results are:

27
7-35

1 (1) mixing in the SG inlet plenum(deep or shallow SG inlet plenum)

2

3 (2) mixing in HL (physical characteristics such as length and diameter of HL )

4

5 (3) pressure drop in HL and SG tubes (i.e., an integral effect)

6

7 (4) heat transfer and heat losses from the HL walls (e.g., heat up inertia including condition 

8 of the insulation on the HL)

9

10 (5) performance of primary and secondary relief valves pre/post onset of core damage

11

12 (6) duration of DC availability including load shedding capabilities

13

14 (7) effectiveness and successful SAMG activities

15

16 (8) success of other severe accident mitigation measures that are provided by EDMG 

17 (extensive damage mitigation guidelines) and FLEX (diverse and flexible mitigation 

18 capabilities); for example, black start and extended operation of TDAFW without DC

19

20 The conclusions of this study based on the case studies performed for the representative 

21 Westinghouse plant, as described in this chapter, are discussed below:

22

23 • The contribution of C-SGTR to LERF is expected to be about 4.0E-08 when all hazard 

24 categories applicable to the site are included.

25

26 • The contribution of C-SGTR to LERF is expected to be about 1.0E-08 when only internal 

27 event SBO core damage sequences are considered.

28

29 • Based on the existing PRAs, C-SGTR appears not to be a major contributor to LERF for 

30 these types of plant design.

31

32 • It is generally concluded that in plants with design similar to the representative 

33 Westinghouse plant, the C-SGTR and the associated LERF do not make a significant 

34 contribution, unless there exist large and deep flaws in one or more SGs.

35

36 7.2 PRA Perspective of C-SGTR for a Combustion Engineering Plant

37

38 MELCOR analyses were performed in two stages over a given time period to study a 

39 combustion engineering plant’s response to RCS conditions that could lead to C-SGTR. The 

40 first stage analyses were completed in October 2012. These analyses were initially used in 

41 PRA evaluation of C-SGTR probability. The second stage of MELCOR analyses were 

42 completed in August 2013. These updated MELCOR analyses and results are used for the 

43 updated PRA evaluation discussed in this section.

44

45 The second stage TH analyses are mainly used in support of the development of the PRA 

46 models and success criteria. The other required information for C-SGTR PRA evaluation was 

47 gleaned from the documents for the Calvert Cliffs individual plant evaluation (IPE) and individual 

48 plant evaluation for external events (IPEEE). A detailed discussion of the MELCOR model and 

49 the results of the MELCOR evaluation for Calvert Cliffs Nuclear Power Plant (CCNPP) are 

50 provided in Section 3.
7-36

1

2 7.2.1 Description of the Selected TH Sequences

3

4 A specific naming scheme is used in defining main features of various scenarios evaluated in 

5 this section. The general format for the naming scheme is “SBO type,” “Secondary Side relief 

6 mode,” “Creep rupture failure progression,” and “plant loop.” These are further defined below:

7

8 (1) SBO type (stsbo/ltsbo)

9

10 a. stsbo: station black out scenario with failure of TDAFW at time zero

11 b. ltsbo: station black out scenario with failure of TDAFW after 4 hours of operation

12

13 (2) Secondary Side relief mode (a/as)

14

15 a. a: no stick open failure of either primary PORVs or SRVs, or secondary PORVs 

or main steam safety valves (MSSVs); a pre-existing leakage area of 3.22 cm2 16

(0.5 in.2 17 ) in secondary side is assumed.

18

19 b. as: no stick open primary PORVs or SRVs but failure of MSSVs to reclose when 

20 first demanded (before on set of core damage); no other pre-existing leakage is 

21 assumed.

22

23 (3) Creep rupture failure progression (SCF)

24

25 a. SCF nomenclature is used when creep rupture failure is suppressed. In such 

26 cases, the scenario will proceed without any failure of RCS components or SG 

27 tubes due to creep rupture.

28

29 (4) Plant loop (a/b)

30

31 a. a: refers to the plant loop equipped with the pressurizer.

32

33 b. b: refers to the plant loop without pressurizer.

34

35 The MELCOR predicts the temperature profile for the average hot tube where the gas flows 

36 from the hot side of the steam generator to the cold side, and the average temperature of cold 

37 tubes where the gas flow is reversed. The average hot tube is divided to two sections: the 

38 section where the gas flows upward and the section where the gas flows downward. The 

39 average temperature of the upward flow section is higher than the downward flow section. The 

40 average hot tube temperature in the following graphs refers to the section of the hot tubes 

41 where the hot gas flows upwards. The average section where the gas flows downward has a 

42 temperature profile similar to that of the cold tubes, and they are averaged with the temperature 

43 of cold tubes to obtain an average cold tube temperature for the purpose of estimating the 

44 C-SGTR probability using the C-SGTR software. The fraction of tubes considered to be 

45 exposed to the average hot temperature, where the gas flow is upward, is estimated to be 

46 around 0.25 for the base case analysis. This same fraction was also used as the probability 

47 that a flaw in an SG will be exposed to the average hot tube temperature for all base case 

48 evaluation. Sensitivity analysis was performed using a fraction of 0.125 instead of 0.25 and its 

49 impact on the final C-SGTR probability was estimated. This is discussed in Section 7.3.2.

50
7-37

1 The number of tubes exposed to the hottest temperature is approximated by the number of 

2 tubes exposed to a normalized temperature of 0.9 to 0.99 for CE plant (see the table in Section 

3 3.3). Multiple unflawed tubes generally could fail because of creep rupture before HL failures 

4 with varying leakage area. Expert elicitation of NRC staff members previously involved in the 

5 issue resulted in a range from 10 to 100 tubes failing (See Section 3.4). The PRA study, 

6 therefore, considered a small number of tubes; about 100 tubes in each steam generator, is 

7 assumed to be exposed to hotter gas temperatures.

8

9 These tubes are referred to as the hottest tube and presented by a single average hottest 

10 temperature. Considering 8,247 tubes per SG, the fraction of the hottest tubes is estimated to 

11 be around 0.01.

12

13 The following two representative base scenarios were evaluated using the second stage of 

14 MELCOR evaluation for use in estimating the base probability of C-SGTR. In these two 

scenarios, a leakage through the secondary side of each SG, equivalent to an area of 3.2-cm2 15

(0.5-in2 16 ) hole, was modeled. This size of leakage was sufficient to ensure that the pressure in 

17 the secondary side of the SGs approached the atmospheric pressure after steam generators 

18 have been dried out. This size of leakages, however, is not sufficient to maintain low 

19 secondary-side pressure if SG tubes have ruptured or represent a significant contribution to 

20 LERF.

21

22 • An SBO with failure of the TDAFW pumps early in the sequence (i.e., at time zero) 

23 followed by an early core damage with a potential for C-SGTR because of creep rupture 

24 is considered for this scenario. An RCP seal leakage of 79 Lpm (21 gpm) per pump is 

25 also considered for this scenario. The MELCOR results for these case runs are 

26 applicable to several PRA accident sequences with similar behavior (see discussion in 

27 Section 2). For SBO sequences, this includes an SBO scenario with simultaneous 

28 failures of TDAFW pumps because of common cause failure (CCF) to start, and an SBO 

29 with an initial availability of TDAFW pumps followed by their failures because of SG 

30 overfill in an hour. For this case run, the onset of core damage is expected to occur in 

31 less than 2 hours. The potential for the occurrence of C-SGTR is considered after the 

32 onset of core damage. The temperature at the inner surface of the top section of the HL 

33 in degrees Celsius, the average temperature of the hot SG tubes, the average 

34 temperature of the cold SG tubes, and the temperature of the hottest SG tube are shown 

35 in Figure 7-14 for the loop A, which is equipped with pressurizer. Similar results for the 

36 loop without the pressurizer (loop B) are shown in Figure 7-15. The differences between 

37 the HL temperature and the average tube and the hottest tube temperature are shown 

38 for loops A and B in Figures 7-16 and 7-17a, respectively. These graphs show that the 

39 temperature response for HL heat up after core damage is slower than the SG tube 

40 temperature response. Therefore, the HL is expected to be initially at a lower 

41 temperature than the average hot and the hottest tube after the onset of core damage. 

42 This would increase the probability of C-SGTR, especially because of the failure of 

43 hottest tubes. The pressure in the primary and the secondary sides of SGs are shown in 

44 Figure 7-17b. This graph shows that the secondary side will be depressurized owing to 

3.2 cm2 (0.5 in.2 45 ) of assumed leakage. The primary side pressure is maintained at the 

46 set point of primary safety relief valves.

47

48 • An SBO with delayed failures of TDAFW pumps after battery depletion is considered for 

49 this scenario. TDAFW is initially available, but it will fail shortly after the depletion of the 

50 battery because of the loss of dc power. A normal RCP seal leakage of 79 Lpm 

51 (21 gpm) per pump is considered. The MELCOR analysis assumes that the TDAFW 
7-38

1 pumps were operating for a period of 4 hours. The temperature at the inner surface of 

2 the top section of the HL in degrees Celsius, the surge line temperature, the average 

3 temperature of the hot SG tubes, the average temperature of the cold SG tubes, and the 

4 temperature of the hottest SG tube are shown in Figure 7-18 for loop A. Similar results 

5 for loop B are shown in Figure 7-19. The differences between the HL temperature and 

6 the temperature of the different SG tubes are shown for Loops A and B in Figures 7-20

7 and 7-21a respectively. These graphs show that the temperature response for HL heat 

8 up after core damage is much slower than the SG tube temperature response. 

9 Therefore, the HL is initially expected to be at a lower temperature than the average hot 

10 and the hottest tube after the onset of core damage. This results in a higher probability 

11 of failure of SG tubes due to creep rupture, before creep rupture failure of the HL. The 

12 pressure in the primary and the secondary sides of SGs are shown in Figure 7-21b. 

13 This graph shows that the secondary side will be depressurized owing to 

3.2 cm2

(0.5 in.2 14 ) of assumed leakage. The primary side pressure is maintained at the 

15 set point of primary safety relief valves.

16

17 As discussed in Section 2.5, for C-SGTR during a severe accident, the size of the leak area 

18 would determine the size of the release through containment bypass (i.e., it determines if the 

19 containment bypass should be categorized as LERF). For a small leakage, the primary is 

20 expected to stay pressurized (generally at primary relief set point approximately 15.5 MPa

21 (2,250 psi)) resulting in the failure of other RCS components (e.g., HL) shortly after the failure of 

22 the tubes. This significantly reduces and eliminates any release through the SGs. Larger 

23 leakages could pressurize the secondary side of the affected SG such that both the primary and 

24 secondary sides equalize at the pressure set point of the SG relief valves. In this case, there is 

25 a lower probability of the failure of other RCS components (e.g., HL) because of a lower primary 

26 pressure (approximately 8.3 MPa (1,200 psi)). This pressure assumes that the SG PORVs and 

27 MSSVs cycle as many times as needed without any failures. If any of the SG relief valves fails

28 open (sticks open) early during an accident, the primary will be depressurized, and it will 

29 practically eliminate any possibility of the HL failure (or other RCS components). The SG relief 

30 valves could also be opened in short SBO scenarios by the operators following the onset of core 

31 damage per SAMG. In SBO scenarios where TDAFW is initially operating, the probability that 

32 the operator opens any of the secondary relief valves is small since the batteries are assumed 

33 to have been depleted, and the recovery of dc power in the short period of time after the onset 

34 of core damage and before C-SGTR, is less likely. There could also be a threshold for a larger 

35 leak areas through the failed SG tubes such that the countercurrent flow through the HL can no 

36 longer be maintained. In such cases, the hot steam will flow through the SG tubes causing 

37 massive tube failures resulting in a large containment bypass.

38

39 A sensitivity analysis was performed using the MELCOR evaluation by assuming that there is 

40 zero leakage through secondary system at the start of SBO (instead of the generally assumed 

leakage area of 3.2 cm2 [0.5 in.2 41 ]), such that the secondary relief and safety valves will be 

42 demanded early during accident and before the onset of core damage. MELCOR evaluation for 

43 this case further assumes that the secondary relief and safety valves fail to reclose after the first 

44 opening. The result of this sensitivity case run is discussed in Section 7.3 as a part of sensitivity 

45 case studies.

46

47 Additional sensitivity analyses were performed by Stage 1 and 2 MELCOR evaluations to further 

48 examine the impact of various scenarios. The following were noted:

49

50 • C-SGTR with an equivalent leakage area of the guillotine break of less than one tube will 

51 not result in depressurization of the primary.
7-39

1

2 • An equivalent leakage area of one or more tubes could result in a significant release if 

3 one or more of the SG safeties, or the relief valves are left open or stick open.

4

5 • The primary is initially depressurized and accumulator discharges when one or more 

6 secondary relief valve sticks open early in the accident. This will further delay HL/surge 

7 line creep rupture failures. The probability of C-SGTR due to creep rupture, however, is 

8 not affected as much since the lower secondary-side pressure increases the delta 

9 pressure across the tube.

10

11 For PRA quantifications and in PRA models (event trees and probability estimations) the analyst 

12 should, therefore, differentiate between C-SGTR equivalent leakage areas less than and more 

13 than the guillotine break of a single tube. PRA models also consider the probability that manual 

14 secondary-side depressurization is performed to facilitate the performance of SAMG activities 

15 for flooding the SG secondary side. MELCOR runs were not performed for such scenarios. In 

16 addition, MELCOR runs did not provide any information about the conditions for loop seal 

17 clearing or the large C-SGTR leakages that could possibly reverse the direction of the cold gas 

18 flow, eliminating the countercurrent flow regime in the HL.
7-40

1

2

Figure 7-14 Loop A temperature profiles of the HL and SG tubes for the SBO with an early failure of T3

4

0

800

600

400

200

1400

1200

1000

0 100 200 300 400 500 600

Temperature (in 

oCelsius)

Time (in minutes)

SBO with TDAFW Operating for 0 Hours; Calvert Cliffs Loop A
7-41

1

2

Figure 7-15 Loop B temperature profiles of the HL and SG tubes for the SBO with an early failure of T3

4

0

800

600

400

200

1400

1200

1000

0 100 200 300 400 500 600

Temperature (in 

oCelsius)

Time (in minutes)

SBO with TDAFW Operating for 0 Hours; Calvert Cliff
7-42

1

2

Figure 7-16 Difference in loop A temperature of the HL and SG tubes for the SBO with an early failure o3

4

-100

-50

0

50

250

200

150

100

0 100 200 300 400 500 600

Temperature (in 

oCelsius)

Time (in minutes)

SBO with TDAFW Operating for 0 Hours; Calvert Cliffs Loop 

A

 Hot Leg Temp-Hotte

 Hot Leg Temp-Av. Ho
7-43

1

2

Figure 7-17(a) Difference in loop B temperature of the HL and SG tubes for the SBO with an early failure 3

4

-100

-150

-50

0

50

250

200

150

100

0 100 200 300 400 500 600

Temperature (in 

oCelsius)

Time (in minutes)

SBOwith TDAFW Operating for 0 Hours; Calvert Cliffs Loop 

Hot Leg Temp-Ho

 Hot Leg Temp-AV
7-44

1

2

Figure 7-17(b) Primary and secondary pressure for the SBO with an early failure of TDAFW 3

4

3.00E+03

2.50E+03

2.00E+03

1.50E+03

1.00E+03

5.00E+02

0.00E+00

0 100 200 300 400 500 600

Pressure (psi)

Time (min)

Primary and Secondary Pressure for SBO with TDAFW Operat

for 0 Hours; Calvert Cliffs 

P

S
7-45

1

2

Figure 7-18 Loop A temperature profiles of the HL and SG tubes for the SBO with a delayed failure of 3

4

0

800

600

400

200

1600

1400

1200

1000

0 200 400 600 800 1000 1200 1400

Temperature (in 

oCelsius)

Time (in minutes)

Extended SBO with TDAFW Operating for 4 Hours; Calvert Cli

Loop A
7-46

1

2

Figure 7-19 Loop B temperature profiles of the HL and SG tubes for the SBO with a delayed failure of 3

4

0

800

600

400

200

1600

1400

1200

1000

0 200 400 600 800 1000 1200 1400

Temperature (in 

oCelsius)

Time (in minutes)

Extended SBO with TDAFW Operating for 4 Hours; Calvert 

Cliffs Loop B
7-47

1

2

Figure 7-20 Difference in loop A temperature of the HL and SG tubes for the SBO with a delayed failure o3

4

-100

0

600

500

400

300

200

100

0 200 400 600 800 1000 1200 1400

Temperature (in 

oCelsius)

Time (in minutes)

Extended SBO with TDAFW Operating for 4 Hours; Calvert Cliffs 

Loop A

 Hot Leg Temp. - Hott

 Hot Leg Temp. - Av. H
7-48

1

2

Figure 7-21(a) Difference in loop B temperature of the HL and SG tubes for the SBO with a delayed failur3

4

-100

-200

-300

-400

-500

-600

0

200

100

0 200 400 600 800 1000 1200

Temperature (in 

oCelsius)

Time (in minutes)

Extended SBO with TDAFW Operating for 4 Hours; Calvert Cliffs 

Loop B

Hot Leg Temp. - Hottest T

Hot leg Temp. - Ave. Hot 
7-49

1

2

Figure 7-21(b) Primary and secondary pressure for the SBO with a delayed failure of TDAFW 3

4

3.00E+03

2.50E+03

2.00E+03

1.50E+03

1.00E+03

5.00E+02

0.00E+00

0 100 200 300 400 500 600 700 800 900 1000

Pressure (psi)

Time (min)

Primary and Secondary Pressure for Extended SBO with TDAF

Operating for 4 Hours; Calvert Cliffs 
7-50

1 7.2.2 Estimating the Entry Frequency from Level 1 PRA for Level 2 PRA Analysis

2

3 Calvert Cliffs nuclear power plant (NPP) was also selected as the reference plant for this study 

4 for developing the Level 2 PRA models to ensure consistency with the TH analyses results. 

5 The estimates for a prolonged SBO condition, as the entry point for the Level 2 PRA, were 

6 found based on the plant design features and the information obtained from SPAR models for 

the internal events, and from the vintage Calvert Cliffs NPP IPE/IPEEE 2 7 documents for external 

8 and other internal hazards. The process to develop the Level 2 PRA entry condition for 

9 containment bypass resulting from C-SGTR for Unit 1 of Calvert Cliffs NPP is discussed in this 

10 section. Appendix G (Section G.2) provides a detail discussion of various CDF contributors 

11 from SBO scenarios to overall CDF from both internal and external events. The quantitative 

12 values used in this section are supported by technical discussion in Appendix G. All potential 

13 conditions from the internal and external hazards resulting in a prolonged station blackout are 

14 considered.

15

16 Relevant plant information for Calvert Cliffs Units 1 and 2 are provided in Table 7-13. Each unit 

17 of Calvert Cliffs is equipped with two TDAFW pumps; and the duration to battery depletion is 

18 nominally 2 hours, although they are expected to last for 4 hours. TH runs in MELCOR also 

19 used a value of 4 hours for battery depletion.

20

21 The frequency of prolonged SBO with either early failures of AFW or failure of AFW after battery 

22 depletion, which is used as the entry point for Level 2 PRA, is estimated based on the 

23 discussion provided for each internal and external hazard for the single and dual unit core 

24 damage. The following table shows the contributions from both the internal and external 

25 hazards, broken down for the two scenarios of the SBO with early and delayed failures of AFW, 

26 for single and dual unit core damage frequency.

27

28 The CDF contributions of SBO scenarios from internal and external initiating events, for both 

29 units of Calvert Cliffs, are partitioned to two bins as follows:

30

31 • The frequency of those SBO core damage scenarios that affect only one unit (i.e., only 

32 one unit experiences SBO). For example, a single unit loss of offsite power with failure 

33 of emergency power system (e.g., diesel generators) belonging to the affected unit will 

34 only affect one unit.

35

36 • The frequency of those SBO core damage scenarios that affect both units (e.g., a dual 

37 unit loop followed by failure of emergency power systems in both units (CCF of all 

38 emergency diesel generators)).

39

 2 IPE Summary Report, “Calvert Cliffs Nuclear Power Plant December 1993, IPEEE Summary Report, Vol. 1, Calvert 

 Cliffs Nuclear Power Plant August 1997
7-51

1 Table 7-13 Related Information from the Reference CE Plant

2

Systems System Features

Emergency Power System • Currently there are 5 emergency diesel generators for the 

2 units. One of these 5 EDGs is the SBO EDG, which can 

power any safety related 4-kV bus at either unit. The 

operation of 1 EDG with success of 1 TDAFW pump per unit 

is adequate for a long-term SG heat removal. The SBO EDG 

requires operator action to align it to a safety bus and is 

credited as a recovery action in the PRA models.

• At the time when plant IPE/IPEEE was performed, each unit 

had a dedicated EDG with a shared EDG for both units. 

Therefore, the information contained in IPE/IPEEE should be 

used as a guide, and they are not directly applicable.

• Each unit has 3 4,160-VAC Class 1E buses, each feeding 

1 480-VAC Class 1E bus and motor control center.

• 3 trains of dc power are supplied from the inverters and 3 unit 

batteries. The battery duration is 2 hours, but it is expected to 

last 4 hours during most scenarios.

Auxiliary Feedwater System Each unit is equipped with 2 turbine-driven pumps (TDAFW) and 

1 motor-driven pump (MDAFW). There is a cross connection to 

other unit’s MDAFW discharge line.

Salt Water System (SW) There are 2 cross-tied trains, each with 1 pump and 1 heat 

exchanger. A third pump could also supply either trains, if 

needed.

Service Water (SRW) There are 2 trains, each with a salt water pump, a CCW HX, an

SRW HX, and ECCS pump room air cooler. A third pump could 

be aligned to each train if needed.

Component Cooling Water (CCW) The CCW pumps do not restart automatically after a LOOP. The 

operators manually re-establish RCP seal cooling after a LOOP.

Secondary Relief • 4 Turbine Bypass Valves—TBVs (2 SG)

• Atmospheric dump valve (1 per SG)

• Main Steam Safety Relief Valve (8 Per SG)

Primary Relief • 2 reverse-seated PORVs (2400 psi); 

1. The PORVs do not require dc power for once-through 

cooling (feed and bleed)

2. 2 block valves that are powered from the opposite 

480 VAC with respect to their PORVs

• 2 spring loaded safety relief valves (P>2500 psig)

Containment Large, dry

3

4 The SBO frequency for single and double units are then further evaluated to arrive at the CDF 

5 for short SBO and long SBO contribution of single and double units. The overall frequency of 

6 the SBO scenarios can be categorized in the following six bins:

7

8 (1) the CDF for short term SBO scenarios affecting Unit 1 only

9 (2) the CDF for long term SBO scenarios affecting Unit 1 only

10 (3) the CDF for short term SBO scenarios affecting Unit 2 only

11 (4) the CDF for long term SBO scenarios affecting Unit 2 only

12 (5) the CDF for short term SBO scenarios affecting both Units

13 (6) the CDF for long term SBO scenarios affecting both Units
7-52

1

2 For convenience, only the single unit with the largest contributor to CDF is shown in 

3 Figure 7-15. The CDF affecting one unit can be arrived at by combining the frequency of CDF 

4 affecting the single unit only plus the CDF affecting both units.

5

6 The results shown in Table 7-14 indicate that the risk of the SBO scenarios is dominated by the 

7 SBO scenarios with the failure of TDAFW trains, after the depletion of the battery. Similar 

8 conclusion is also made for the dual unit SBO scenarios. The uncertainties associated with 

9 these frequencies are not presently estimated due to the lack of detailed models and data. 

10 Surrogate uncertainties from similar plants could be considered if needed.

11

12 Table 7-14 Contributions of Various Events to the Long Term SBO Scenarios for Single 

13 and Dual Unit Core Damage

14

Initiating 

Event

SBO with Early 

Failure of AFW

SBO with Failure of 

AFW after 

Battery Depletion

Unit CDF from SBO Scenarios 

with

Single 

Unit *

Dual Unit Single 

Unit *

Dual 

Unit

Early Failure 

of AFW

Failure of 

AFW after 

Battery 

Depletion

Internal 

events 1.9E-8 5.5E-9 4.5E-8 1.2E-7 2.5E-8(~13%)

1.7E-7 

(~87%)

Seismic 5.0E-8 1.4E-8 ε + 2.0E-7 6.4E-8

(24%)

2.0E-7

(~76%)

Fire ε 2.4E-6 2.2E-5 2.2E-6 2.4E-6

(~9%)

2.4E-5 

(~91%)

Flood ε ε 1.6E-6 ε ε

1.6E-6 

(~100%)

High wind ε 4.7E-8 ε 4.3E-6 4.7E-8

(~1%)

4.3E-6 

(~99%)

Total 6.9E-8 2.5E-6 2.4E-5 6.8E-6 2.6E-6

(~8%)

3.1E-5 

(~92%)

* The unit with the largest CDF contribution is used. + For the details of the quantitative values, consult Appendix G (G-2). “ε” generally indicates a value less than 

1.0E-8 per year that could not be easily quantified by the results of plant specific PRA.

15

16 7.2.3 Flaw Bins to Calculate C-SGTR Probability

17

18 CE plants use SGs with thermally treated Inconel 690. Similar to the discussion in the previous 

19 chapter, the number of flaws per cycle for these SG tubes is significantly lower than the older 

20 SG tubes made of Inconel 600 mill annealed (MA). For thermally treated Inconel 690, the 

21 probability that a flaw length and depth belong to a certain range (or bin), is estimated using 

22 these adjusted flaw distributions (see Section 7.1.3). This was shown in Table 7-3 in the 

23 previous section. Note that the flaw distribution equations apply to any SGs (Westinghouse and 

24 CE) as long as the same tube material is used.

25

26 Each unit of Calvert Cliffs has two steam generators with the 8,471 Inconel 690 thermally 

27 treated tubes. There are, therefore, 16,942 tubes for each unit and 33,884 tubes for both units. 

28 The average number of flaws generated for the first 14 EFPYs of operation using the 
7-53

1 Inconel 690 flaw generation rate equation (first row, second column of Table 6-2) is about 

2 127 flaws per SG, or 253 flaws per unit. It is further assumed that the last periodic SG 

3 inspection occurred at the end of the 14 EFPY. All the large flaws, therefore, are assumed to 

4 have been plugged (approximately 12 plugged tubes per SG) before the EFPY of 15 begins. An 

5 additional 13 flaws are expected to be generated for each SG during the EFPY 15. Therefore, 

6 about 128 flawed tubes per SG (or 256 flaws per unit—2 SGs) were expected during EFPY 15, 

7 with an average of 2 large flaws that could need to be plugged at the end of the EFPY 15. The 

8 expected numbers of flaws (the expected flaw sample) is estimated to be about 125 flawed 

9 tubes per each SG (about 253 per each unit and 505 tubes for both units -- all four SGs). The 

10 number of flaws is rounded off to avoid fractional tubes. The expected sample flaw for one SG 

11 and one unit are shown in Tables 7-15 and 7-16, respectively.

12

13 Table 7-15 Expected Number of Flaws per Each SG That Belong to a Flaw Bin Defined by 

14 Depth and Length Range

15

Depth / 

Length 1 cm 2 cm 3 cm 4 cm 5 cm 6 cm Total

0.1 0 6 3 1 0 0 10

0.2 3 44 21 5 1 0 74

0.3 1 23 11 3 1 0 39

0.4 0 2 0 0 0 0 2

0.5 0 0 0 0 0 0 0

0.6 0 0 0 0 0 0 0

0.7 0 0 0 0 0 0 0

0.8 0 0 0 0 0 0 0

0.9 0 0 0 0 0 0 0

Total 4 75 35 9 2 0 125

16

17 Table 7-16 Expected Number of Flaws per Loop A and Loop B (one Unit; 2 SGs), That 

18 Belong to a Flaw Bin Defined by Depth and Length Range

19

Depth / 

Length 1 cm 2 cm 3 cm 4 cm 5 cm 6 cm Total

0.1 1 13 7 2 0 0 22

0.2 6 88 43 11 2 1 151

0.3 3 45 22 5 1 0 76

0.4 1 1 1 0 0 0 3

0.5 0 1 0 0 0 0 1

0.6 0 0 0 0 0 0 0

0.7 0 0 0 0 0 0 0

0.8 0 0 0 0 0 0 0

0.9 0 0 0 0 0 0 0

Total 10 148 73 18 3 1 253

20

21 The expected values of flaws in each bin are shown to illustrate the expected size distribution of 

22 flaws. The values shown in the tables also account for the flaws detected in previous cycles 

23 that they were large enough such that the affected tubes were plugged. The approximation 
7-54

1 used in these calculations plus the effect of rounding off the expected number of flaws per bin 

2 have generally resulted in slightly fewer flaws than expected. As an example, an expected set 

3 of 125 flaws per each SG is shown in Table 7-15, rather than the 128 flawed tubes (127 flaws in 

4 previous cycles, plus 13 flaws in the last cycle, and minus approximately 12 plugged tubes) 

5 estimated earlier.

6

7 For CE plants, TH results are different for the loop with pressurizer (loop A) and the loop without 

8 the pressurizer (loop B). Therefore, the probability of C-SGTR is calculated for each loop 

9 separately. Table 7-16 shows the expected number of flaws for the whole plants (i.e., two loops 

10 and two SGs). However, this flaw set is not used for the analysis, and it is only presented for 

11 consistency with W plant and as an illustrative example of a unit flaw set.

12

13 7.2.4 SGTR Probability Estimation Using Integrated Flaw Samples

14

15 An integrated plant-wise analysis would involve generating a large number of flaw samples for 

16 the hottest tube, hot tubes, and cold tubes for both loop A and B, and perform integrated 

17 C-SGTR calculator case runs to establish sufficient statistics to estimate C-SGTR probability 

18 and its uncertainty distribution. Because the C-SGTR software is not designed to accept 

19 different TH files for different loops and treat temperature distributions for the tubes (e.g., 

20 average hot, hottest, and cold), such an integrated analysis is impractical.

21

22 Short of performing an integrated analysis, the following steps were taken to obtain an estimate 

23 for C-SGTR using a sample of flaws:

24

25 (1) The 125 expected flaws per each SG as shown in Table 7-15 was considered for 

26 performing C-SGTR case runs.

27

28 (2) A C-SGTR case run was performed with the 125 expected flaws. A 0.25 probability was 

29 used for a flaw to be exposed to the average hot tube temperature. A probability of 0.75 

30 was used to indicate that a flawed tube is exposed to the average cold tube temperature.

31

32 (3) Step 2 was repeated for the hottest tubes with the 125 expected flaws. A probability of 

33 0.01 was assigned for a flawed tube (any of the 125 flaws) to be exposed to the hottest 

34 tube temperature.

35

36 (4) The distribution percentiles (5 percent to 95 percent) of SGTR cumulative leak areas 

37 estimated by C-SGTR code for each time step was transformed to the probability of a 

38 leak size at each time step for the average hot and the hottest tube for loop A. These 

39 leak area distributions were then added probabilistically (i.e., by convolution of leak 

40 distributions) at each time step to obtain the cumulative C-SGTR leak area distribution 

41 for loop A, from both average and the hottest tubes.

42

43 (5) The probability of RCS failure (i.e., HL or surge line failure) was also estimated for each 

44 time step for loop A.

45

46 (6) Steps 2 through 5 were repeated for loop B. The probability of HL failure was used as 

47 the probability of RCS failure for loop B.

48

49 (7) The integrated C-SGTR leak areas from loop A and loop B, then were probabilistically 

50 added (i.e., the two distributions were convolved at each time step). Similarly the 
7-55

1 probability of RCS failure was also estimated by aggregating the probabilities of RCS 

2 failure of loop A with loop B.

3

(8) For a critical SG leak area (i.e., 6 cm2 [0.93 in.2 4 ]), the probability of RCS survival was 

5 multiplied with the probability that the SG leak area distribution exceeds the critical C6 SGTR leak area for each time step. The resulting probability value is then integrated 

7 over all time steps to obtain the C-SGTR probability. This is shown in the equation 

8 below:

9

10 PPPPPPPP(CCCCCC CC) =

11 ∫ PPPPPPPP ( ssss ssssssss aa tt) ∗ PPPPPPPP�CCCCCC CC oooo bb bb tt aa aa (tt + )� ∗ (7.3)

12

13 Figures 7-22 and 7-23 show examples of graphical results generated from Steps 2 and 3 for 

14 short term SBO scenario for average hot and the hottest tubes. These graphs show the 

15 probability of RCS survival and the distributional percentiles of the SGTR leak areas as a 

16 function of time. The graphs also show that there is significantly more spread for leak area 

distribution associated with the hottest tube. For a leak area of 3 cm2 (0.46 in.2 17 ), the graphs 

18 show that the survival probability of RCS could vary from 0.03–0.17 for the average hot tube 

19 and from 0–0.43 for the hottest tubes.

20

21

22

23 Figure 7-22 The RCS survival probability and percentiles of SGTR leak areas for 

24 stsbo-a-average hot tubes

25

26 The graphical results from Steps 4 and 5 for loop B and loop A are presented in Figures 7-24

27 and 7-25 respectively. Figure 7-24 shows that at about 2,000 seconds, the probability of RCS 

survive is 0.5 and the probability that SGTR leak exceeds 3 cm2 (0.46 in.2 28 ) is approximately 0.4 

29 (1-0.6). Similarly, at 2,080 seconds, the probability that RCS has survived is 0.6 and the 

probability that SGTR leak exceeds 3 cm2 (0.46 in.2 30 ) is approximately 0.02 (1-0.98). The current 

31 method can generate similar graphs for any size of SGTR leak areas. An example is shown in 

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0

1

2

3

4

5

6

20000 21000 22000 23000 24000 25000

Leak area cm2

Time (s)

Am

A0.05

A0.25

A0.50

A0.75

A0.95

RCS Survival

Probability
7-56

Figure 7-26 showing the leak probability curves for both 3 and 6 cm2 (0.46 and 0.93 in.2 1 ) of 

2 SGTR leak area for stsbo-a-b-scf sequence.

3

4

5

6 Figure 7-23 The RCS survival probability and percentiles of SGTR leak areas for 

7 stsbo-a-hottest tubes

8

9 Figure 7-27 shows the graphical results from the Step 7 of the approach. It shows the 

10 probability of RCS integrity and the time dependent probability that SGTR leak area from both 

units is less than a predefined critical leak area criterion (i.e., 6 cm2 [0.93 in.2 11 ]).

12

13 A C-SGTR probability of about 0.2 was estimated for the stsbo-a sequence based on the 

14 procedure given in Step 8 of approach.

15

The results for the probability of SGTR exceeding 6 cm2 (0.93 in.2 16 ) for loop B before the failure 

17 of HL, is shown in Table 7-17. The results also support the choice of the factor 1.5 for the ratio 

of C-SGTR probability for ltsbo over stsbo;

3 18 however, it will not occur until at least 12 hours later 

19 (not a LERF issue as it will be discussed later). Figure 7-28 shows an example of calculations 

20 for loop B resulting from Step 6 of approach for the purpose of the comparison with the 

Figure 7-26. The comparative results for the probability of SGTR exceeding 3 or 6 cm2 21 (0.46 or 

0.93 in.2 22 ) for loop B before the failure of HL, is shown in Table 7-17.

23

 3 Both in Westinghouse and CE TH input files exhibit the following property when the SG tube temperatures reach the

 creep-rupture range, namely 600–700 degrees Celsius (1,112–1,292 degrees Fahrenheit): the temperature 

 difference between the HL and the average tube temperature is larger for the scenarios where AFW (TDP) fails at 

 T=0, compared to when the AFW fails at T = battery depletion. Thus, the C-SGTR probability is higher for the 

 sequences with “late” failure of AFW. This phenomena appears counter-intuitive. It should be noted that the 

 C-SGTR, if it occurs, occurs much later in the sequences with late AFW failure, compared to sequences where AFW 

 fails at T=0.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0

1

2

3

4

5

6

7

8

18000 19000 20000 21000 22000 23000 24000 25000

Leak Area (cm2)

Time (s)

Am

A0.05

A0.25

A0.50

A0.75

A0.95

RCS Survival

Probability
7-57

Figure 7-24 The RCS survival probability and the probability of SGTR with a leak area less than 

3 cm2 for stsbo-a-b, aggregated over average hot and hottest tubes

Figure 7-25 The RCS survival probability and the probability of SGTR with a leak area 

less than 3 cm2 for stsbo-a-a, aggregated over average hot and hottest tubes

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

18000 19000 20000 21000 22000 23000 24000

Probability

Time (s)

P(SGTR <

3 cm^2)

P(RCSSurvive)

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

18000 19000 20000 21000 22000 23000 24000 25000

Probability

Time (s)

P(SGTR

Leak<3

cm^2)

P(RCSSurvive)
7-58

1

2

3

4 Figure 7-26 The RCS survival probability and the probability of SGTR with a leak area less 

than 3 and 6 cm2 5 for stsbo-a-b-scf

6

7 The probability of C-SGTR for the selected CE plant is, therefore, 0.2 for SBO scenarios where 

8 the TDAFW pump(s) has failed initially and 0.3 when TDAFW pump(s) operates for at least 

9 4 hours. For these analyses, primary or secondary relief valves are assumed to reclose after 

10 opening and no failure to stick open is considered.

11

12 As in the Westinghouse case, it is observed that the conditional C-SGTR probability is higher for 

13 the severe accident sequences with late failure of AFW than those sequences with early failure 

14 of AFW. Both Westinghouse and CE TH input files exhibit the following property when the SG 

15 tube temperatures reach the creep-rupture range, namely 600–700 degrees Celsius 

16 (1,112–1,292 degrees Fahrenheit): the temperature difference between the HL and the average 

17 tube temperature is larger for the scenarios where AFW (TDP) fails at T=0, compared to when 

18 the AFW fails at T = battery depletion. This results in a higher likelihood for HL failure in the 

19 case with earlier AFW failure. Thus, the C-SGTR probability is higher for the sequences with 

20 “late” failure of AFW. This phenomenon is illustrated in Figures 7-15 and 7-16 for early AFW 

21 failure and Figures 7-18 and 7-19 for late AFW failure. It should be noted that the C-SGTR, if it 

22 occurs, occurs much later in the sequences with late AFW failure, compared to sequences 

23 where AFW fails at T=0.

24

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

18000 19000 20000 21000 22000 23000 24000

Probability

Time (s)

P(SGTR < 3

cm^2)

P(RCSSurvive)

P(SGTR<6

cm^2)
7-59

1

2

3 Figure 7-27 The RCS survival probability and the probability of SGTR with a leak area less 

than 6 cm2 4 for the whole plant for an SBO scenario with failure of TDAFW at time zero and 

5 no stuck open secondary relief valves (stsbo-a-scf)

6

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

18000 19000 20000 21000 22000 23000 24000

Probability

Time (s)

p(sgtr<6

cm^2)

P(RCSSURVIVE)
7-60

1

2

3 Figure 7-28 The RCS survival probability and the probability of SGTR with a leak area less 

than 3 and 6 cm2 4 for ltsbo-a-b-scf

5

6 Table 7-17 Comparison of C-SGTR probability for SBO

7

Case Run (Sequence) Contribution to P(CSGTR>6 cm2) from loop B

Short Term SBO 0.22

Long Term SBO 0.31

8

9 7.2.5 Level 2 Models for Containment Bypass Evaluation

10

11 The timing for the major events corresponding to the accident progression of a scenario of an 

12 SBO and early failure of TDAFWs is shown in Table 7-18. These timings are generated by a 

13 combination of MELCOR results and sensitivity case runs with C-SGTR software.

14

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

44000 44500 45000 45500 46000 46500 47000 47500 48000

Probability

Time (s)

P(SGTR<3 cm2)

P(SGTR<6 cm2)

P(RCS Survive)
7-61

1 Table 7-18 Timing of Major Events during an SBO with Early Failures of TDAFWs

2

Time Events for SBO with Early Failure of TDAFWs

0 SBO started

~ 14 minutes ECCS signal actuated

~ 4 hours DC assumed depleted a

~ 5 hours Onset of core uncovery, corresponding to 1200 °F

Between 5:30 minutes to 5:45 

minutes b

SGTR is expected with varying leak rates c

Between 5:21 minutes and before 

5:50 minutes

HL failure if the primary pressure remains around 2200 psi as 

estimated by C-SGTR software 

Between 5:08 minutes to 5:30 

minutes 

Gap release from rod groups 1 through 5

Around 5:54 minutes HL failure if the primary pressure remains around 1200 psi b (SG 

relief set point) after 65 hr 30 minutes 

Around 6 hours HL failure if the primary pressure is around 700 psi

Between 7 to 8 hours Core structure failures, multiple melting and quenching. Start of 

in-vessel releases 

~ 11 hours vessel breach, HL failure is not expected if primary is fully 

depressurized 

a Although MELCOR assumes dc is depleted in 4 hours for both early and late failure of TDAFWs, PRA considers 

dc would be available for longer time for the case when TDAFWs were not available at time zero. The 

availability of dc will facilitate SAMG activities such as depressurization of primary and secondary. b The ranges are defined based on 10 and 90 percentiles of the associated failure distribution. c These values were supported by sensitivity runs performed using C-SGTR software.

3

4 The following observations can be made based on an examination of the information shown on 

5 this table:

6

7 (1) For cases when C-SGTR occurs before HL failure but the primary pressure is 

8 maintained at the primary relief set point (approximately 15.2 MPa (2,200 psi)), the HL is 

9 expected to fail shortly after the occurrence of SGTR. The size of the SGTR leak for 

10 such cases is approximately equivalent to the area of a guillotine break of one tube. 

11 MELCOR runs show that this amount of SGTR leakage may not demand any cycling of 

12 the secondary relief valves. In general, no depressurization of primary system is 

13 expected. The releases are therefore limited to a fraction of the fuel gap release plus 

14 the radioactivity source term contained in the primary reactor system. These are 

15 categorized under negligible releases. Larger releases are possible only if the 

16 secondary-side relief valves sticks open during or before C-SGTR.

17

18 (2) For cases where the primary pressure equalizes with the secondary pressure and the 

19 pressure remains at the secondary relief set point (approximately 8.3 MPa (1,200 psi)) 

20 after the occurrence of C SGTR, the HL failure would be delayed but it occurs before the 

21 vessel breach. The status of SG relief valves (stick open or not) would determine the 

22 magnitude of release. It is expected that the larger the C-SGTR leak area, the larger 

23 would be the release magnitude. The releases are generally not categorized as LERF if 

24 no secondary relief sticks open.

25
7-62

1 (3) If one primary relief valve (e.g., PORVs or SRVs) is maintained open; either intentionally 

2 by the operator or due to failures, it is assumed that it would be sufficient to reduce the 

3 primary pressure to 4.8 MPa (700 psi). The accumulators are discharged in cases 

4 where primary pressure is reduced below 4.8 MPa (700 psi). As previously shown for 

5 Westinghouse plants, It is expected that the primary relief through at least two relief 

6 valves (PORVs or SRVs) would be needed to maintain a depressurized primary state 

7 after the accumulator discharge. If only one primary relief valve sticks open, 

8 repressurization is expected within the time frame of interest. For such cases, the failure 

9 of HL will be delayed and if one or more secondary relief paths have stuck open, there is 

10 a potential for some early releases. The releases however, will be limited since some 

11 fraction of releases will end up into the containment due to the stick open primary relief 

12 valve.

13

14 (4) For cases where the secondary relief valves stick open early in the accidents, the 

15 primary is expected to depressurize below the accumulator discharge set point. This will 

16 delay the failure of HL and the occurrence of SGTR. Higher delta P on the tubes, 

17 however, is expected because of lower secondary-side pressure, which can increase the 

18 probability of SGTR. For these cases, probability of C-SGTR is expected to increase 

19 and the releases are considered to be LERF because of a large containment bypass 

20 area provided by the stick open secondary relief valves. A specific set of MELCOR runs 

21 were performed for this case and there are discussed in more detail in Section 7.3.2.

22

23 (5) For cases where the primary and secondary are equalized and both are depressurized 

24 completely, the HL may not fail until vessel breach (approximately 11 hours) occurs. All 

25 in-vessel releases then should be considered as a part of the source term. This situation 

26 could occur if the operator has depressurized primary system for SAMG actions, but 

27 failed to flood the secondary side of the SG or the primary system. The primary 

28 depressurization could also take place by failures of multiple primary relief valves (stick 

29 open) under the harsh environment associated with post-core melt.

30

31 (6) Occurrence of very large C-SGTR leak area (because of loop seal clearing, or the failure 

32 of three or more tubes) is conservatively categorized as LERF. Such cases can demand 

33 secondary-side relief and multiple secondary-side relief paths could fail open. However, 

34 the release could be significantly reduced if the secondary side of SG is filled with fire 

35 water as a part of SAMG actions.

36

37 The above assumptions for the purpose of developing Level 2 PRA were made based on the 

38 engineering judgment and simple calculations and they are not yet fully supported by MELCOR 

39 runs. Other MELCOR runs may be needed to confirm the validity of these assumptions.

40

41 The timing for the progression of accidents for a scenario of an SBO and failures of TDAFWs 

42 after 4 hours is shown in Table 7-19. These timings are generated similarly from a combination 

43 of MELCOR results and sensitivity case runs with C-SGTR software. They follow very similar 

44 trends as those for the first scenario when TDAFW failed early. There are two differences 

45 between the accident progressions of an SBO with failures of TDAFWs after battery depletion 

46 and an SBO with the early failure of TDAFWs. These differences are found to be important for 

47 developing and quantifying the Level 2 models for C-SGTR:

48

49 (1) DC is expected to be depleted by 4 hours, so no operation of active components from 

50 the control room can be credited unless the power is recovered. If the offsite power is 

51 recovered, credits for successful SAMG actions can be provided.
7-63

1

2 (2) Extended DC could also be provided through portable generators and other means. 

3 This could also facilitate the long term availability of DC for SAMG actions or maintaining 

4 the operation of the TDAFWs. The success probability for such actions could be 

5 increased if they are initiated early after the occurrence of an SBO. This is a 

6 plant-specific PRA issue that cannot be generically addressed at this time.

7

8 Table 7-19 Timing of Major Events during an SBO with Failures of TDAFWs after 

9 Battery Depletion

10

Time Events for SBO with Early Failure of TDAFWs

0 SBO started

~ 14 minutes ECCS signal actuated

~ 4 hours DC assumed depleted

~ 12:05 minutes Onset of core uncovery, corresponding to 1200 °F

Between 12:45 minutes and 

13:05 minutes SGTR is expected with varying leak rates 

Between 12:30 minutes to 13:15 

minutes (average 12:55 

minutes)

HL failure if the primary pressure remains around 2200 psi as 

estimated by C-SGTR software 

Between 12:40 minutes to 

13:15 minutes Gap release from rod groups 1 through 5

Between 13 hour 20 minutes HL failure if the primary pressure remains around 1200 psi (SG 

relief set point) after the onset of core damage 

~ 13 hours 40 minutes HL failure if the primary pressure is around 700 psi

around 17 hours Core structure failures, multiple melting and quenching. Start of 

in-vessel releases 

~ 18 hours vessel breach, if primary fully depressurized

11

12 Similar to the discussion provided for the Westinghouse plant in the previous section for 

13 estimating the frequency of containment bypass and LERF because of C-SGTR, a five-factor 

14 formula was used. The fractions of containment bypass scenarios that can lead to LERF 

15 depend on the success probabilities of SAMG actions and effective evacuation. The SAMG 

16 actions for the CE plant is similar and comparable to that of the Westinghouse plant as 

17 discussed previously.

18

19 The emergency response timeline and the process for effective evacuation of the SBO scenario 

20 with early and late failure of TDAFW (e.g., after batteries are depleted) were discussed in 

21 Section 2.5. That discussion applies to both the Westinghouse and CE plants. It is assumed 

22 that for the CE plants similar to the Westinghouse, the evacuation is most likely effective for 

23 C-SGTR containment bypass events during SBO scenarios with late failures of TDAFW, and not 

24 effective for SBO scenarios with early failure of TDAFW. This assumption is valid despite the 

25 fact that the time to core damage for the CE plant was estimated to be somewhat longer than 

26 the Westinghouse plant.

27

28
7-64

1 7.2.6 Quantification of Probability of Containment Bypass due to C-SGTR

2

3 A simplified five-factor formula for LERF, as discussed in Section 2.5, was used. These factors 

4 are:

5

6 (1) frequency of severe accident sequences with potential for C-SGTR (fAC), as discussed in 

7 Section 7.2.2

8

9 (2) C-SGTR probability (PCSGTR), see discussion for estimating C-SGTR and containment 

10 bypass probability in Section 7.2.4

11

12 (3) conditional probability that the subsequent failures of RCS components including the 

13 stuck open primary relief valves do not occur (PNDEP)

14

15 (4) failure probability of all SAMG actions (PSAMG)

16

17 (5) probability that early effective evacuation is not successful (PEVAC)

18

19 The qualitative discussion provided in previous Section for estimating the parameters: PNDEP, 

20 PSAMG, and PEVAC are considered to be applicable here. Bounding values for each of these three 

21 parameters, similar to what was suggested in Section 7.1, were also used. These values for 

22 SBOs, with early or late failures of TDAFW are shown in Table 7-20.

23

24 Table 7-20 Conditional LERF Probabilities for an SBO with Early and Late Failures of 

25 TDAFW for Representative CE Plant

26

Factors Applicability LERF Factors 

(early, late)a b

PCSGTR Sequences with no stick open primary or secondary relief 

valves 

(0.2, 0.3)

Sequence with loop seal clearing (1.0,1.0)

PNDEP Sequence without loop seal clearing (1.0, 1.0)

Sequence with loop seal clearing (1.0, 1.0)

PSAMG Sequence without loop seal clearing (1.0, 1.0)

Sequence with loop seal clearing (1.0, 1.0)

PEVAC For all sequences (1.0, 0.0)

a The two numbers in parenthesis are for SBO scenarios with early and late failure of TDAFWs. b This value is considered to be conservative and it is used for screening purposes only.

27

28 It was shown earlier in Table 7-14 that more than 92 percent of the total SBO scenarios; from 

29 both internal and external events, resulted from the SBO scenarios with the failure of TDAFW 

30 after battery depletion for the selected plant (last row last column of Table 7-14). Moreover, the 

31 results for internal event models also showed that 87 percent of the total SBO scenarios 

32 resulted from the SBO scenarios with the failure of TDAFW after battery depletion for the 

33 selected plant (last column, first row after headings). The CDF from SBO sequences, 

34 considering all hazard categories, is about 3.3E-05/year, and for internal event, is about 

35 1.9E-07/year (obtained from Table 7-14). This CDF multiplied by the conditional probability of 

36 containment bypass (0.2), gives a bounding containment bypass frequency estimate of ~6.8E37 06/year for all hazard categories, and ~4.0E-08/year for internal events only. The overall LERF 
7-65

1 estimate from each unit is about 5.1E-07, since only the containment bypass resulting from the 

2 SBO scenarios with early failure of TDAFW (i.e., about 8 percent of total CDF) has a potential 

3 for LERF.

4

5 The relatively small values for LERF for the selected CE plant (i.e., Calvert Cliffs) are the result 

6 of the unique design feature of its AFW system. Calvert Cliffs is equipped with two TDAFW 

7 pumps that significantly reduce the core damage frequency resulting from the SBO scenarios 

8 with the early failure of TDAFWs. This design feature is not generally shared by other CE 

9 plants.

10

11 Detailed quantification of Level 2 PRA models considering the human reliability analysis

12 complexity of SAMG actions and the survivability of equipment post core melt is not currently 

13 employed in this study. It is expected that plant-specific features will play important roles in the 

14 detailed quantification of containment bypass probability.

15

16 7.2.7 Concluding Remarks

17

18 C-SGTR, containment bypass probability, and LERF are significantly influenced by the TH 

19 results obtained from various case studies. These TH results reflect the specific design, 

20 configuration, and geometry of the plant systems (specifically the SG design), and primary 

21 connections such as HL and surge line. They should not be interpreted as generic results for 

22 CE plants. The more important plant features that can affect the results are:

23

24 • SG flaws (i.e., number of flaws, type, depth, and sizes of the flaws)

25

26 • mixing in SG (deep or shallow SG inlet plenum)

27

28 • mixing in HL (physical characteristics such as length and diameter of HL )

29

30 • pressure drop in HL and SG tubes (i.e., an integral effect)

31

32 • heat transfer and heat losses from the HL walls (e.g., heat up and condition of the 

33 insulation around the HLs)

34

35 • reliability of primary and secondary relief valves pre/post onset of core damage

36

37 • operational procedures regarding the depressurization of the secondary side of SGs

38

39 • duration of DC availability including load shedding capabilities

40

41 • effectiveness and successful SAMG activities

42

43 • success of Flex and EDMG

44

45 The conclusions of this study based on the case studies performed for the selected CE plant as 

46 described in this chapter, are discussed below:

47

48 • The contribution of C-SGTR to LERF is expected to be about 5.1E-07/yr when all hazard 

49 categories applicable to the site are included.

50
7-66

1 • The contribution of C-SGTR to LERF is expected to be about 5.0E-09/yr when only 

2 internal event SBO core damage sequences are considered. This value is lower than 

3 the expected value for other CE plants, since the selected CE plant is equipped with two 

4 TDAFW trains.

5

6 • All the hazard models for the SBO scenarios considered for this study showed that the 

7 large fraction of core damage scenarios will involve both units (approximately 

8 86 percent). This issue may be considered further as a part of the integrated site PRA.

9

10 • There is significantly higher probability for C-SGTR for CE plants compared to 

11 Westinghouse—these conclusions focus too heavily on the unique PRA aspects of the 

12 reference plant—particularly that relatively shallow flaws can provide significant 

13 contribution to C-SGTR probability.

14

15 • This reference plant has unique safety features that may not be representative of the 

16 fleet of PRWs using similar SGs (for example 2 TDAFW pumps, as mentioned above: 

17 this feature is deemed to be an asset since it would make the failure of the TDAFW 

18 pumps less likely than a typical plant with only one TDAFW pump.)

19

20 The following observations were made considering the frequency of containment bypass, which 

21 may or may not result in LERF:

22

23 • For the selected CE plant, the contribution of C-SGTR to containment bypass could be 

24 as high as 6.8E-06, considering contributions from all hazard categories. If only internal 

25 events are considered, this contribution is expected to be about 4.0E-08.

26

27 • Based on the existing PRAs, C-SGTR appears to be the highest contributor to 

28 containment bypass scenarios.

29

30 • The containment bypass contribution occurs mainly from the scenarios where the 

31 TDAFW initially worked, but was later rendered inoperable after the depletion of 

32 batteries. This is mainly because the CDF contribution from the scenarios with failure of 

33 TDAFW (s) after battery depletion is much larger than the CDF from the SBO scenarios 

34 with the early failure of TDAFW(s). However, these scenarios are not considered to 

35 contribute to LERF, since evacuation is expected to be effective.

36

37 • Extending the battery life and operation of TDAFW beyond 12 hours, can reduce the 

38 frequency of containment bypass, by reducing the frequency of the core damage 

39 sequences that challenge the SG tubes. This also facilitates the use of additional 

40 equipment such as the existing EDMG or the future equipment in response to FLEX 

41 program.

42

43 7.3 Sensitivity Analyses for C-SGTR in Different SG Types

44

45 This section examines the robustness of the results and conclusions discussed earlier in 

46 Sections 7.1 and 7.2 under varying sets of assumptions. These sensitivity analyses are also 

47 designed to support development of Level 2 PRA models. Detailed discussion on the approach, 

48 assumptions, case runs, and the results of analysis is provided in Appendix D for both the

49 selected W and the CE plants.

50
7-67

1 Section 7.3.1 is devoted to the representative Westinghouse plant and summarizes the results 

2 and insights from a series of sensitivity analyses that are discussed in detail in Appendix D. 

3 Section 7.3.2 similarly summarizes the results and insights from different sets of sensitivity 

4 analyses for the representative CE plants. In some cases, the results of sensitivity analysis 

5 performed for one representative plant could also be applicable and provide insights for the 

6 other representative plant.

7

8 7.3.1 Summary of Sensitivity Analyses for Westinghouse Plant

9

10 The following sensitivity analyses were performed for the representative Westinghouse plant. 

11 The measure of comparison used for these sensitivity analyses was based on the time 

12 difference between the time when HL failure is imminent and the time when C-SGTR is

13 expected. The ratio of this time margin over the base time margin is used as a means of 

14 qualitatively ranking the impact of sensitivity results.

15

16 7.3.1.1 Uncertainty in Predicting the HL and SG Tube Temperature

17

18 The effect of uncertainties of TH prediction in terms of delta temperature between HL and 

19 average hot tube was studied in this sensitivity analysis. It is generally expected that if the 

20 difference between the HL temperature and SG tube temperature decreases, the probability of 

21 C-SGTR would increase. This is done by assuming that the delta-T between the HL and hot 

22 tube is only 50 percent as large as the base case. The results of the sensitivity analysis for the 

23 representative W plant showed that the time margin measure is reduced by 4 minutes. This is 

24 considered to be of low impact.

25

26 7.3.1.2 Sensitivity of HL Thickness

27

28 In this sensitivity case, the effect of an increase in HL thickness due to a weld overlay, on the 

29 margin is examined. For this purpose, the HL thickness of 6.35 cm (2.5 in.) in the base case is 

30 increased by 50 percent, to 9.5 cm (3.74 in.). This sensitivity analysis showed a reduction of 

31 2 minutes in the time margin, and it is, therefore, categorized as low impact.

32

33 7.3.1.3 Secondary Side Not Depressurized

34

35 In this sensitivity study, it is assumed that the secondary side will not be depressurized neither 

36 as a result of pre-existing leakage nor because of intentional opening or stick open failure of one 

37 or more secondary relief valve before and after the onset of core damage. The results of 

38 sensitivity analysis shows that the time margin actually increases, since HL failure time is not 

39 affected, but the tube flaw failure time is considerable delayed. This sensitivity analysis shows 

40 no impairment on C-SGTR probability.

41

42 7.3.1.4 Early Secondary-Side Depressurization

43

44 In this sensitivity analysis, the operator depressurizes SGs at 30 minutes by opening at least 

45 one SG Atmospheric Dump Valve (ADV) or SG PORV per SG drops the primary pressure below 

46 4.82 MPa (700 psi). This actuates the accumulator discharge. TDAFW will fail after the 

47 batteries are depleted. The results of this sensitivity analysis show that the time margin is 

48 increased by about 4 minutes, and furthermore, the onset of core damage is delayed 

49 significantly. This sensitivity analysis, therefore, shows no adverse impact on C-SGTR 

50 probability.

51
7-68

1 7.3.1.5 Tube Material; Comparison of Alloy 600 and 690 TT Tubes

2

3 This sensitivity analysis compared the Westinghouse SG types with TT600 and TT690 tube 

4 material. The results showed that the margin for TT690 is reduced by about 10 minutes for 

5 TT690, indicating that TT690 material with a “large” flaw will leak earlier than SG tubes with 

6 TT600 material with the same “large” flaw. However, it is shown that the number of flaws and 

7 the flaw sizes for TT690 are expected to be smaller than that of TT600. Therefore, TT690 is 

8 expected to perform similar to TT600 as far as C-SGTR is concerned. However, large flaws if 

9 detected in TT690 could be more prone to C-SGTR than similar flaws in TT600.

10

11 7.3.2 Summary of Sensitivity Analyses for Combustion Engineering Plant

12

13 The following sensitivity analyses were performed for the representative CE plant. The 

14 measure of comparison used for these sensitivity analyses was based on the reevaluation of 

15 C-SGTR probability for stsbo sequences where LERF is of concern. In some cases; the 

16 C-SGTR probability was only reevaluated for one loop rather than for the reactor unit (i.e., two 

17 loops; loop A and loop B). When the reevaluation for sensitivity analysis was limited to one 

18 loop, loop B was selected because of its higher contribution to C-SGTR. The difference 

19 between the revised C-SGTR probability and the base C-SGTR probability was used to 

20 prioritize the effect of the sensitivity results. The changes of less than 25 percent is assigned as 

21 low, 25 to 50 percent as moderate, 50 to 100 percent as high, and any increases above 

22 200 percent as significant.

23

24 7.3.2.1 Stick Open Failure of Secondary Relief Valves before SG Dryout

25

26 In SBO scenarios, before SG dryout the secondary-side relief valves (SG PORVs or MSSVs) 

27 could be demanded and fail to re-close. This could happen in either or both SGs. Stick open 

28 relief valves initially depressurize and cool the primary below the accumulator discharge 

29 setpoint. However, because of post accumulator discharge and dryout of SGs, the primary will 

30 repressurize and the onset of core damage will be reached, although slightly delayed. The 

31 probability of C-SGTR is expected to be higher because a lower secondary-side pressure. A 

32 bounding analysis of this scenario was evaluated using MELCOR package. This scenario is 

33 referred to as stsbo-as or ltsbo-as in Section 3. The overall C-SGTR was reevaluated for this 

34 scenario. The results show that the failure of secondary-side relief valve early during the 

35 sequence can have significant impact on LERF contribution due to C-SGTR. Table 7-21 below 

36 shows the results of this re-evaluation.

37

38 Table 7-21 Sensitivity Results for Early Stick Open Failures of the Secondary 

39 Relief Valves

40

Case Runs Loop b 

C-SGTR>3 cm2

Loop a 

C-SGTR>3 cm2

C-SGTR> 6 cm2

Short Term SBO - Base 0.45 0.227 0.20

Short Term SBO [Stuck open secondary 

relief valve]

0.999 0.997 0.990

41

42 7.3.2.2 Opening of Secondary Relief Valves after SG Dryout

43

44 The operators are guided to depressurize the SGs by opening the secondary relief valves in 

45 anticipation of using an alternate source of water to refill the SGs as a part of SAMGs. This 
7-69

1 sensitivity analysis examines the effect of intentional opening of the secondary relief after the 

2 onset of core damage when the operators fail to refill the SGs. This sensitivity analysis was 

3 performed by setting the secondary-side pressure to 1.0E+05 Pascal after the hot gas 

4 temperature reaches about 640 degrees C (1,184 degrees F). The effects on primary pressure 

5 or temperature are not expected to be significant. The results show that the opening of 

6 secondary-side relief valve after SG dry out and the onset of core damage can increase LERF 

7 contribution because of C-SGTR by about 65 percent (from 0.2 to 0.33) for stsbo-a scenarios. 

8 Table 7-22 below shows the results of this re-evaluation.

9

10 Table 7-22 Sensitivity Results for Opening the Secondary Relief Valves after SG Dryout

11

Case Runs Loop b C-SGTR > 

3 cm2

Loop a C-SGTR > 

3 cm2

C-SGTR > 

6 cm2

Short term SBO – Base (Stsbo-a) 0.450 0.217 0.20

Short Term SBO [Stuck open 

secondary relief valve - after SG 

dryout] (Stsbo-a)

0.591 0.262 0.33

12

13 7.3.2.3 Critical C-SGTR Leak Area

14

The critical area equivalent to Guillotine break of one tube (approximately 6 cm2 [0.93 in.2 15 ]) was 

16 chosen as a sufficient leakage area that can be considered to be a LERF if the secondary-side 

17 relief valves are open. Some MELCOR analyses showed that this size of leakage may not be 

18 sufficient to depressurize the primary or pressurize the secondary, such that SG relief valves 

19 are demanded. These analyses, however, assumed that there is a pre-existing secondary 

leakage area of 3.2 cm2 (0.5 in.

2 20 ) from the starting point of the sequence. To ensure that the 

21 secondary relief valves are demanded and primary can be depressurized, a larger critical 

C-SGTR leak area needs to be considered. For a critical C-SGTR leak area of 12 cm2 22

(1.86 in.2

) instead of 6 cm2 (0.93 in.2 23 ) the probability of C-SGTR was reduced from 0.2 to 0.06. 

24 The effect is therefore considered to be high. The Figure 7-29 shows the results for stsbo-a 

25 sequence. Similar graphs can be generated for any size of critical leak area and they generally 

26 follow the trend shown in Figure 7-29.

27
7-70

1

2

Figure 7-29 The sensitivity results for (stsbo-a) for C-SGTR leak area of 12 cm2 and 6 cm2 3

4

5 7.4 Case Studies for Pressure-Induced C-SGTR Scenarios

6

7 The sequences of interest for design-basis accident events that could establish a delta pressure 

8 across the SG tube walls, and therefore, potentially challenge the integrity of the tubes due to 

9 pressure-induced failures, were summarized in Section 2.1. A limited effort was devoted to 

10 evaluate the bounding contribution of C-SGTR to CDF and LERF as a result of these 

11 sequences.

12

13 For the purpose of these evaluations, two bounding scenarios represented by stylized TH inputs 

14 for the C-SGTR software were considered. This eliminated the need for performing specific 

15 MELCOR or RELAP runs for these case studies. Furthermore, theses bounding analyses apply 

16 to both Westinghouse and CE plants.

17

18 The two TH scenarios and the corresponding accident conditions including the bounding 

19 estimates in terms of increase in CDF and LERF are summarized below. Additional supporting 

20 analyses can be found in Appendices C and F.

21

22 7.4.1 C-SGTR during Anticipated Transients without Scram (ATWS)

23

24 The loss of main feed water ATWS event is selected for evaluation for this bounding scenario. 

25 The termination of feed water flow to the steam generators results in a large imbalance in the 

26 heat source/sink relationship. This heat buildup in the primary system also raises the RCS 

27 temperature and pressure. In general, the availability of main feed water for ATWS events 

28 results in a less severe power mismatch between the heat source and the heat sink; therefore,

29 the peak pressure attained in the primary system will not exceed the ASME stress Level C limit 

30 for components in the RCS.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

18000 19000 20000 21000 22000 23000 24000

Probability

Time (s)

P(SGTR<6cm^2)

P(RCS-SURVIVE)

P(SGTR<12 cm^2)
7-71

1

2 If the RPS failure is not because of the failure to insert sufficient rods (mechanical rod failures), 

3 manual actions to trip the reactor and the backup to the reactor trip system (RTS) provided by 

4 the ATWS Mitigation System Actuation Circuitry (AMSAC) can be credited to eventually scram 

5 the reactors. However, such actions are not fast enough to prevent the formation of early 

6 primary pressure peak, which can induce a C-SGTR. If C-SGTR occurs and subsequently the 

7 reactor scram is successful, the event would behave similar to that of SGTR with the failure of 

8 main feedwater (MFW) system. However, if C-SGTR occurs in ATWS scenarios because of the 

9 mechanical failure of the rods, or in the unlikely event that the backup manual scram actions are 

10 not successful, the accident progression may differ from the traditional SGTR scenario. In most 

11 PRAs, such scenarios are considered as eventual core damage because of the following 

12 issues:

13

14 • A C-SGTR following an ATWS could result in an uncontrolled cool down of the primary 

15 system unless the faulted SGs are isolated. Such cool down and its reactivity feedback 

16 could render emergency boration (EB) ineffective.

17

18 • A C-SGTR following an ATWS could reduce the boron concentration in the primary 

19 system through primary to secondary leakage.

20

21 The effect of C-SGTR on the reactivity feedback and the effectiveness of EB would depend on 

22 the size of the primary to secondary leakage. This study considers the leakages greater than 

23 an equivalent guillotine break of one tube to be of a sufficient size to influence the effectiveness 

24 of EB.

25

26 ATWS scenarios will expose all SGs to a higher pressure; therefore, C-SGTR can occur at any 

27 of the SGs. The analysis in Appendix F conservatively concludes that a flaw of about 3 cm 

28 (1.2 in.) or more in length, and 70 percent or more in depth could fail under ATWS conditions. 

29 This translated to a C-SGTR probability of 0.01 for the representative Westinghouse plant with 

30 four SGs, and 8.0E-03 for the representative CE plant with 2 SGs, for the 15th cycle of 

31 operation.

32

33 Simplified PRA calculations were performed for the two ATWS scenarios of concern using a 

34 PWR SPAR model (Shearon Harris plant). These two cases are discussed below.

35

36 7.4.1.1 ATWS with Successful Manual Scram but Occurrence of C-SGTR

37

38 For all ATWS scenarios, where the failure of RPS is not caused by the inability to insert 

39 sufficient number of rods and subsequent manual/backup scram through AMSAC are 

40 successful, the C-SGTR accident progression will proceed as if the SGTR was the initiator. The 

41 probability of ATWS because of electrical RPS failure is generally set at about 1.5E-5 per 

42 demand, assuming that there is about 1 transient per year demanding RPS system. The main 

43 contributors are given in Table 7-23 below:

44
7-72

1 Table 7-23 Contributors to Electrical RPS Failures Which Do Not Impact Manual Scram

2

Basic Event Name Failure 

Probability Description

RPS-UVL-CF-UVDAB 1.040E-5 CCF UV DRIVERS TRAINS A AND B (2 OF 2)

RPS-TXX-CF-6OF8 2.700E-6 CCF 6 BISTABLES IN 3 OF 4 CHANNELS

RPS-CCX-CF-6OF8 1.830E-6 CCF 6 ANALOG PROCESS LOGIC MODULES IN 

3 OF 4 CHANNELS

RPS-BME-CF-RTBAB 1.610E-6 CCF OF RTB-A AND RTB-B (MECHANICAL)

3

4 The probability of electrical ATWS and C-SGTR is about 1.5E-7 per year. This scenario has a 

5 frequency that is about 4 orders of magnitude smaller than the frequency of SGTR initiator, 

6 which is about 2.0E-3 per year. The C-SGTR initiator and these scenarios will progress 

7 similarly if the manual scram is successful.

8

9 7.4.1.2 Nonrecoverable ATWS Followed by C-SGTR

10

11 The probability of ATWS because of mechanical failures to insert sufficient number of rods is 

12 estimated to be about 1.2E-6, if one transient per year is assumed. The main contributor for this 

13 event as reported by SPAR model is specified below.

14

Basic Event Name Failure Probability Description

RPS-ROD-CF-RCCAS 1.2E-6 CCF 10 OR MORE RCCAS FAIL TO DROP

15

16 The probability of Mechanical ATWS and C-SGTR is about 1.2E-8 per year.

17

18 7.4.2 C-SGTR during Steam Line Break Scenarios

19

20 Several sequences identified earlier in Table 2-1 can be bounded by an unisolable main steam 

21 line break. These sequences could also include spurious opening of one or more SG relief 

22 valves in addition to main steam line breaks (MSLBs). The TH behavior of these scenarios can 

23 be bounded by high primary pressure at about 15.5 MPa (2,250 psi) and a low atmospheric 

24 secondary pressure. The primary temperature is generally expected to be sub-cooled. A 

25 temperature of 300 degrees C (572 degrees F) is used since the saturated primary temperature 

26 at 15.5 MPa (2,250 psi) is about 345 degrees C (653 degrees F). Atmospheric pressure is also 

27 considered for the secondary-side pressure at the faulted SG. It was also considered that the 

28 MSIV on all nonaffected SGs will close; therefore, blowing the steam out of only one SG and 

29 eliminating the potential for pressurized thermal shock (PTS) sequences because of excessive 

30 overcooling. This was considered as the bounding TH behavior for these sequences when 

31 evaluating the potential pressure induced C-SGTR. In such a scenario, tubes in all SGs will be 

32 initially exposed to high delta pressure with a potential for C-SGTR. However, after the closure 

33 of MSIV, only one faulted SG would remain un-isolated. The C-SGTR probability of the faulted 

34 SG is used for the PRA evaluation since the CDF and LERF contributions results mainly from 

35 the unisolated SG.

36

37 Appendix F conservatively considers that a threshold for large flaw with some potential for 

38 causing C-SGTR during steam line break (SLB) scenarios should have a depth greater than 

39 70 percent and a length of 3 cm (1.2 in.) and more. This threshold flaw, when considered for 

40 occurrence of C-SGTR in the specific SG affected by SLB scenarios, is translated to a 
7-73

1 probability of 2.5E-03 for the representative Westinghouse plant and a probability of 4.0E-03 for 

2 the representative CE plant for the 15th cycle of the operation.

3

4 The initiating event (IE) frequency for the different types of SLB accidents could vary amongst 

5 the plants. The information provided in NUREG/CR-5750 (Ref. 6) is mainly used for 

6 establishing the IE frequency for bounding analysis. NUREG/CR-6928 (Ref. 7) was used when 

7 more recent updates were reported. The following summarizes the impact on accident 

8 progression for each of these initiating events, when a C-SGTR occurs.

9

10 7.4.2.1 SLB inside containment (SLBIC)

11

12 SLBIC has an approximate IE frequency of about 1.0E-3 per reactor year as reported in 

13 NUREG/CR-5750. If this initiating event induces a C-SGTR, all releases will remain inside the 

14 containment; therefore, they will not contribute to LERF due to containment bypass. However, 

15 they will contribute to CDF. It is also assumed that the MSIV on all nonaffected SGs will close; 

16 therefore, eliminating the potential for PTS sequences because of excessive overcooling.

17

18 When SLBIC is followed by C-SGTR, the PRA models should be integrated by transferring the 

19 SLBIC event tree branch that includes C-SGTR, to the SGTR event tree discussed in Chapter 2 

20 and shown in Figure 2-1. However, some of the C-SGTR branches will be affected through this 

21 transfer. They are summarized below:

22

23 • It would be more difficult to diagnose the SGTR at the faulted SG because the operator 

24 should mainly rely on high secondary-side activity (high radiation alarm) rather than on a 

25 high uncontrollable level in the affected SG. The operator may terminate the high 

26 pressure injection in response to SLBIC, if he/she is not able to diagnose C-SGTR in 

27 early stages. However, the operator could re-establish the high head injection after a 

28 short period due to a low pressurizer level. The failure rate for high head injection 

29 should be increased to account for the potential of operator failure to diagnose the 

30 occurrence of C-SGTR in time.

31

32 • It will not be possible to isolate the faulted SG because of SLBIC, although the feed 

33 water to the faulted SG will be isolated. The conditional core damage probability for 

34 C-SGTR should be re-evaluated without any credit for isolation.

35

36 The release of radioactivity because of potential core damage scenario involving SLBIC and 

37 induced C-SGTR is mainly to the containment therefore not considered to be LERF contributor. 

38 The SLBIC initiating event is also an order of magnitude lower than SLBOC initiating event. The 

39 SLBIC scenarios are not considered any further, since they are not expected to contribute to 

40 LERF.

41

42 7.4.2.2 Spurious Opening of SG-PORVs or Stuck Open MSSVs (SGR)

43

44 The spurious opening of SG-PORV because of fire and nonfire events, and the potential for one 

45 or more MSSVs to stick open after a demand are included in this initiating event. Spurious 

46 opening of SG-PORV could be mitigated by closing the block valves, whereas the spurious 

47 opening of MSSVs cannot be recovered. The frequency of the initiating event for spurious 

48 openings (and subsequently to stick/remain open) of one or more SG relief valves is taken to be 

49 3.0E-3 per reactor year from NUREG/CR-6928 which was an update to NUREG/CR-5750. This 

50 value in NUREG/CR-6928 is generically applicable for safety/relief valves both for primary and 

51 secondary. It should be noted that failure of one MSSV can cause severe overcooling transient 
7-74

1 with primary depressurization if feeding to the SG is maintained (not a C-SGTR concern). The 

2 scenario of interest for C-SGTR, however, assumes that the operator will terminate feed water

3 to the affected SG and thereby letting the SG go dry and depressurized. This scenario is only 

4 applicable to one specific SG and does not affect others. Therefore, the appropriate estimated 

5 C-SGTR probability of one steam generator is to be used for the PRA estimations (i.e., C-SGTR 

6 probability of 2.5E-3 for the representative Westinghouse and 4.0E-3 for the representative CE 

7 plant).

8

9 When spurious opening of one or more SG relief valves is followed by the occurrence of 

10 C-SGTR, the accident will progress similar to SLBIC with C-SGTR. However, the latter could 

11 result in containment bypass and LERF since the releases will be made outside the 

12 containment.

13

14 7.4.2.3 SLB outside containment (SLBOC)

15

16 SLBOC has an approximate IE frequency of about 1.0E-2 per reactor year. This initiating event 

17 can expose the tubes in all SGs to a higher delta pressure, therefore, with some likelihood of C18 SGTR. Sequences where only one MSIV fails to fully close were considered; therefore, 

19 eliminating the potential for PTS (Pressurized Thermal Shock) sequences due to excessive 

20 overcooling in this scenario. The probability of one out of the four MSIVs to fail to close is 

21 estimated to be about 4.0E-3 per demand. This estimate uses the MSIV failure probability of 

22 9.51E-4 per demand from the Shearon Harris SPAR event MSS-AOV-00-SGMSIV 

23 (i.e., 4X9.51E-4 about 4.0E-03). The IE frequency of an un-isolable SLBOC, is therefore, 

24 estimated at about 4.0E-5 per year.

25

26 When an unisolable SLBOC is followed by C-SGTR, the impact on SGTR branches will be the 

27 same as when the SLBIC is followed by C-SGTR. The core damage that results when an un28 isolable SLBOC is followed by C-SGTR will also bypass containment, and should be considered 

29 as LERF.

30

31 7.4.3 C-SGTR during High Pressure Feed-and-Bleed Operation

32

33 Some of the U.S. PWRs have high-pressure emergency core cooling system (ECCS) pumps 

34 supporting feed-and-bleed operation with shut off pressure above the primary pressure relief set 

35 points. For all initiating events, which involve loss of main feed water system followed by the 

36 failure of AFW system, there could be a possibility of C-SGTR. For these scenarios, the 

37 secondary sides of SGs are assumed to be dry and depressurized. Small leakages of less than 

3.2 cm2 (0.5 in.

2 38 ) are sufficient to depressurize the SGs during the feed-and-bleed operation. 

39 The occurrence of C-SGTR during such events is not expected to increase the core damage 

40 frequency because high-pressure injection (HPI) is assumed to be injecting make up flow due to 

41 the success of the initial phase of feed and bleed operation. However, the occurrence of 

42 C-SGTR will affect the LERF contribution since all core damages past successful feed and 

43 bleed operation will involve containment bypass.

44

45 The IE frequency that can put the plant in a condition where feed-and-bleed operation is 

46 initiated, was estimated based on Shearon Harris SPAR model. This was done by adding the 

47 frequency of transients where MFW is lost (e.g., IE-LOCHS, IE-LOIA, IE-LOMFW, and IE48 LONSW). A bounding value of 0.2 per year was assigned to the IE frequency. This initiating 

49 event frequency must then be multiplied by the probability that AFW system is not available. 

50 The base nominal failure probability of AFW is 2.0E-5 per SPAR model. However, the specific 

51 value of AFW failure probability would be different for different initiators. A bounding value of 
7-75

1 1.0E-4 for generic AFW failure probability was used. The bounding IE frequency for this 

2 category of pressure induced C-SGTR sequences is therefore estimated to be about 2.0E-5 per 

3 reactor year.

4

5 All SGs will be exposed to an environment conducive to C-SGTR during high pressure feed and 

6 bleed operation. The C-SGTR probability, is therefore, bounded by 0.01 for the representative 

7 Westinghouse plant and 8.0E-3 for the representative CE plant at 15th cycle of the operation.

8

9 7.4.4 LERF and Core Damage Contribution of Pressure Induced C-SGTR

10

11 The contribution of pressure-induced C-SGTR to CDF and LERF is estimated by the following 

12 equations:

13

14 PP(CCCC ) = ff(IIII) ∗ PP(CCCCCC CC|IIII) ∗ PP(CCCC|IIII, CCCCCC CC) (7.4)

15

16 PP(LL ) = ff(IIII) ∗ PP(CCCCCC CC|IIII) ∗ PP(CCCC|IIII, CCCCCC CC) ∗ PP(LL |IIII, CCCCCC CC, CCCC) (7.5)

17

18 The estimates for f (IE), P (C-SGTR|IE), and P (LERF|IE, C-SGTR, CD) were discussed for 

19 each sequence separately. P (CD|IE, C-SGTR) is estimated using SPAR model for Shearon 

20 Harris PRA. This conditional probability is estimated by modifying the probability of the 

21 appropriate event tree branches to reflect the impact of the sequence. As an example for 

22 ATWS scenarios, the branch heading associated with EB is set to true.

23

24 For SLB sequences, two other branches should be modified. The HPI branch should reflect that 

25 there is a possibility for the operator to terminate the HPI in response to SLB, not knowing that 

26 C-SGTR has occurred. Operators should also fail to recognize the need to re-establish HPI flow 

27 even after pressurizer low level is indicated. The event tree branch for isolating the faulted SG 

28 should also be set to true.

29

30 The probability that the operator fails to diagnose the occurrence of C-SGTR after SLB scenario 

31 was estimated using the SPAR-H worksheet to be around 2.5E-2. The following adjustments 

32 were made to the nominal values of SPAR-H worksheet for diagnosis:

33

34 (1) Available time: The radiation alarms in secondary side and low pressurizer level 

35 indication will alert the operator of the possibility of C-SGTR at least an hour before the 

36 onset of core damage. Extra time, is therefore, assigned with a PSF (Performance 

37 Shaping factor) of 0.1.

38

39 (2) Extreme stress condition is expected to be present in SLB combined with C-SGTR 

40 scenarios since such events are uncommon and the changes in plant parameters will be 

41 rapid. A PSF of 5 is assigned.

42

43 (3) Procedures are available for SLB and SLB with C-SGTR. However, the transition 

44 between the two procedures and the required monitoring would be difficult. A PSF of 5 

45 is assigned.

46

47 (4) All other PSF values were considered to be nominal.

48

49 The conditional core damage probability for high pressure feed-and-bleed scenarios were 

50 estimated by using the MFW event tree, and setting the failure of both the initiator and the 

51 failure of AFW to true.
7-76

1

2 The conditional core damage probabilities then were estimated using the SPAR model for 

3 Shearon Harris PRA and the proposed changes. Tables 7-24 and 7-25 summarize the results 

4 of these analyses for the representative Westinghouse and CE plants, respectively.

5

6 Table 7-24 Changes in Core Damage Frequency and LERF as a Result of Pressure 

7 Induced C-SGTR for the Representative Westinghouse Plant

8

IE f(IE)

per year

P(CSGTR|

IE)

P(CD|IE,

CSGTR)

P(LERF|

IE,CSGTR,

CD)

Δ-CDF

per year

Δ-LERF

per year

ATWS-Electrical 1.5E-5 0.01 1.6E-4 1 <1.0E-9 <1.0E-9

ATWS-Failure of rods 1.2E-6 0.01 1 1 1.2E-8 1.2E-8

SLBIC 1.0E-3 2.50E-3 3.2E-2 0 8.0E-8 0

Spurious opening of SG 

relief valves

3.0E-3 2.50E-3 3.2E-2 1 2.4E-7 2.4E-7

SLBOC 4.0E-5 2.50E-3 3.2E-2 1 3.2E-9 3.2E-9

High Pressure Feed 

and Bleed Scenarios

2.0E-5 0.01 2.5E-2 1 5.0E-9 5.0E-9

All IES – Total 

Contribution

3.4E-7 2.6E-7

9

10 These bounding values are deemed to be acceptable. Maintaining a low probability for a large 

11 flaw to develop during operation via adequate periodic surveillance program will help to control 

12 this risk contributor. For example, for a PWR with a total CDF of 2E-05 per year and LERF of 

13 1.0E-06, the additional CDF and LERF of 5.3E-07 and 4.0E-7 would add less than 3 percent to 

14 CDF and 40 percent to LERF. LERF contribution is expected to be an order of magnitude lower 

15 if SAMGs are considered as a part of the PRA analysis. The results indicate that the CDF and 

16 LERF contribution of pressure induced C-SGTR cannot be considered negligible although they 

17 are within the acceptable ranges based on these bounding estimations for a generic U.S. PWR.

18

19 Table 7-25 Changes in Core Damage Frequency and LERF as a Result of Pressure 

20 Induced C-SGTR for the Representative CE Plant

21

IE f(IE)

per year

P(CSGTR|

IE)

P(CD|IE,

CSGTR)

P(LERF|

IE,CSGTR,

CD)

Δ-CDF

per year

Δ-LERF

per year

ATWS-Electrical 1.5E-5 8.0E-3 1.6E-4 1 <1.0E-9 <1.0E-9

ATWS-Failure of rods 1.2E-6 8.0E-3 1 1 9.6E-9 9.6E-9

SLBIC 1.0E-3 4.0E-3 3.2E-2 0 1.3E-7 0

Spurious opening of SG 

relief valves

3.0E-3 4.0E-3 3.2E-2 1 3.8E-7 3.8E-7

SLBOC 4.0E-5 4.0E-3 3.2E-2 1 5.1E-9 5.1E-9

High Pressure Feed 

and Bleed Scenarios

2.0E-5 8.0E-3 2.5E-2 1 4.0E-9 4.0E-9

All IES – Total 

Contribution

5.3E-7 4.0E-7

22
7-77

1 7.5 References

2

3 1. U.S. Nuclear Regulatory Commission, “SCDAP/RELAP5 Thermal-Hydraulic Evaluations 

4 of the Potential for Containment Bypass during Extended Station Blackout Severe 

5 Accident Sequences in a Westinghouse Four-Loop PWR,” NUREG/CR-6995, 

6 March 2010, Agencywide Documents Access and Management System (ADAMS) 

7 Accession No. ML101130544.

8 2. U.S. Nuclear Regulatory Commission, “State-of-the-Art Reactor Consequence Analyses 

9 (SOARCA) Report,” NUREG-1935, November 2012, ADAMS Accession 

10 No. ML12332A057.

11 3. U.S. Nuclear Regulatory Commission, “Review and Evaluation of Zion Probabilistic 

12 Safety Study: Plant Analysis,” NUREG/CR-3300, May 1984, ADAMS Accession 

13 No. ML091540533.

14 4. U.S. Nuclear Regulatory Commission, “Analysis of Core Damage Frequency: Internal 

15 Events Methodology,” Vol. 1, Rev. 1, NUREG/CR-4550, SAND86-2084, January 1990.

16 5. U.S. Nuclear Regulatory Commission, “Evaluation of Severe Accident Risks: 

17 Methodology for the Containment, Source Term, Consequence, Risk Integrations 

18 Analyses,” NUREG/CR-4551, December 1993, ADAMS Accession No. ML072710062.

19 6. U.S. Nuclear Regulatory Commission, “Risk Assessment of Severe Accident-Induced 

20 Steam Generator Tube Rupture,” NUREG-1570, March 1998, ADAMS Accession 

21 Number ML070570094.

22 7. U.S. Nuclear Regulatory Commission, “Industry-Average Performance for Components 

23 and Initiating Events at U.S. Commercial Nuclear Power Plants,” NUREG/CR-6928, 

24 February 2007, ADAMS Accession No. ML070650650.

25

8-1

1 8. PRA CONCLUSIONS AND RECOMMENDATIONS

2

3

4 The conclusions in this section are based on the probabilistic risk assessment (PRA) analysis of 

5 Section 7. For additional analyses discussed in Section 3 for fission product release, and in 

6 Section 4 for other reactor coolant system (RCS) components failure, insights are summarized 

7 in Section 9. 

8

9 This report documents a method for a quantitative risk assessment of consequential steam 

10 generator tube rupture during a severe accident after the onset of core damage, and during a 

11 design-basis accident event before the onset of core damage. The method is illustrated with 

12 applications to plants containing replacement steam generators with thermally treated Inconel 

13 Alloy 600 and 690 tubes. In addition, an illustrative example of risk assessment of the

14 consequential steam generator tube rupture using an existing internal event PRA model 

15 is summarized in Appendix L.

16

17 The focus of this study is on estimating the probability of large early release because of 

18 consequential steam generator tube rupture (C-SGTR) and containment bypass. The simplified 

19 methods are applied to two selected pressurized-water reactor (PWR) plants: a Westinghouse 

20 and a Combustion Engineering (CE) design. In addition, the generic stylized models were used 

21 to address C-SGTR related to pressure-induced C-SGTRs as discussed in Section 7.4.3 and 

22 Appendix C. The insights and observations obtained for these applications are provided in 

23 Section 8.1.

24

25 The study used the latest available thermal-hydraulics (TH) for both plants, updated flaw 

26 statistics pertinent to current reactors, and used the latest available models and software for 

27 estimating the failure probability/timings of other steam generator (SG) tubes, and RCS 

28 components (i.e., HL and surge line).

29

30 The scope of this study is limited to estimating the probability of containment bypass because of 

31 C-SGTR, and a bounding assessment of the fraction of containment bypass that constitutes 

32 large early release frequency (LERF). The scope does not include the development of Level 1 

33 PRA, although full Level 1 PRA for internal and external events were used to obtain the 

34 frequency of the sequences related to the C-SGTR.

35

36 This study used the existing results from other related research as input. No attempt was made 

37 to conduct additional research or develop new models. The study is, therefore, limited by the 

38 available supporting analyses and models. These are referred to as, limitations of supporting 

39 analyses for PRA models, and they are discussed in Section 8.2.

40

41 8.1 Insights and Observations

42

43 This study concluded that the overall contribution of C-SGTR scenarios to containment bypass 

44 is about a factor or 10 larger for the selected CE plant than the Westinghouse plant. It further 

45 illustrated that the contribution of C-SGTR to containment bypass is negligible for the selected 

46 Westinghouse plant. The study also showed that the sizes of C-SGTR leaks that contribute the 

47 most to LERF is equivalent to the area of at least the guillotine breaks of one tube. Moreover, 

48 the study has concluded that the cleared loop seal, which causes the failure of multiple tubes, 

49 could be a contributor to C-SGTR for the selected Westinghouse plants. For CE plants, multiple 

50 tube failures could occur even if loop seal is not cleared.
8-2

1

2 This study generally found that the flaw sizes that do not meet the integrity performance criteria 

(e.g., safety factor of 3)1 3 have a low probability of survival during severe accident scenarios 

4 discussed in this report. This was shown earlier in Table 7-7 for the C-SGTR probability for 

5 Westinghouse plant. The Table showed that the C-SGTR probability for large flaws greater 

6 than 0.7 through-wall depth is about 80 percent. Similar tables for CE plant (not included in the 

7 report) show a probability close to 1.0.

8

9 The estimated frequency of containment bypass was further adjusted to estimate the fraction of 

10 all containment bypass scenarios that can contribute to LERF. This was done by examining the 

11 timing of the accident progression for each type of the accident scenarios to determine if the 

12 effective evacuation can be credited. Those containment bypass scenarios where the releases 

13 were expected to occur after an effective evacuation (i.e., late releases) were not included in the 

14 LERF. The SAMG activities that could arrest the core melt or reduce the release magnitude 

15 were also identified and discussed although not credited in further reducing the LERF.

16

17 High-level quantitative conclusions of the study are summarized in Table 8-1 for both 

18 containment bypass (Cont.-Bypass) and LERF. These results are taken from Sections 7.1.8 

19 and 7.2.6, and are further discussed below.

20

21 Note that the estimates for the frequency of the containment bypass because of C-SGTR and 

22 LERF as shown in Tables 8-1a and 8.1b are for all-hazards core damage frequency (CDF)

23 sequences, which include both the internal events and all external event CDF sequences 

24 leading to C-SGTR. Although the all-hazards sequence CDF estimates might not be as robust 

25 as those for internal events, consideration of all-hazards CDF as a measure for comparisons 

26 could provide further insights due to the following reasons:

27

28 • Accident sequences for hazard categories other than internal events may have a higher 

29 contribution to multi-unit station blackouts (SBOs), on sites with multiple units.

30

31 • The evacuation times for accident sequences for other-hazard categories could be 

32 considerably longer than those for internal events.

33

34 • Some important recovery actions credited in internal event sequences may not be 

35 feasible, or may be seriously delayed for other hazard categories.

36

37 Section 7.1 discussed and quantified the LERF Scenarios for the representative Westinghouse

38 plant. The conditional C-SGTR (i.e., containment bypass) probability for SBOs with early or late 

39 failures of turbine-driven auxiliary feedwater (TDAFW) pumps, excluding the scenarios involving 

40 the clearing of the loop seals, was approximately estimated at 0.02. This conditional 

41 containment bypass probability when multiplied by the CDF of SBO with early or late failure of 

TDAFW pump results in a frequency of 1.5×10-07 42 per reactor year for both SBO scenarios. The 

43 more precise estimates of the containment bypass frequency are shown in Table 8-1. These 

44 estimates include the contributions of the scenarios in which the loop seals have been cleared. 

45 The containment bypass frequencies estimated and shown in Table 8-1 are 2.3E-07 for Inconel 

46 600 and 1.6E-07 for Inconel 690, considering the internal event initiators.

47

 1 Letter transmitting TSTF-449 Revision 4, “Steam Generator Tube Integrity,” April 14, 2005 (ADAMS Accession No. 

 ML051090200).
8-3

1 Table 8-1 Summary of the Frequency Estimates for Containment-Bypass and LERF

2

SG 

TYPE

Tube 

Material

#of 

SGs

EFPY Hazard 

Category

SBO CDF 

Frequency 

(per RY)

Cont.-

Bypass 

Frequency

per year

LERF

Fraction 

(%)

LERF

(per RY)

CE 690 2 15 All a 3.3E-5 b 1.0E-5 b 5.6% b 5.7E-7

CE 690 2 15 Internal 1.9E-7 5.7E-8 9.5% 5.4E-9

W 600 4 15 All 2.0E-5 c 8.8E-7 3.7% 3.2E-8

W 600 4 15 Internal 5.2E-6 2.3E-7 3.6% 8.4E-9

W 690 4 15 All 2.0E-5 6.3E-7 3.5% 2.2E-8

W 690 4 15 Internal 5.2E-6 1.6E-7 3.5% 5.8E-9

a The All refers to contribution of CDF from internal events, internal flood, fire, and seismic PRA. b From Table 7.2-2 the CDF for stsbo and ltsbo from all hazards models are ~2.6E-6/RY and 3.1E-5/RY 

respectively. The total containment bypass probability is estimated by [(2.6E-6*.22+3.1E-5*.31) = [5.72E7+9.61E-5] =1.02E-5. The LERF contribution is from the stsbo. It is estimated at 5.7E-7 or about 5.6%. c Per discussion provided in Section 7.1.5, the probability of C-SGTR is about 1.3E-2 for stsbo with Inconel 600 

materials and 8.9E-3 for Inconel 690. The probability of C-SGTR caused by a cleared loop seal due to reactor 

coolant pump seal failures was also estimated at 2.5E-03. The overall probability of C-SGTR is estimated to be 

about 1.6E-2 and 1.1E-2 for stsbo and for Inconel 600 and 690, and 2.85E-2 and 2.0E-2 for ltsbo and for Inconel 

600 and 690.

3

4 The conditional probability of C-SGTR calculated as the base cases studied are summarized in 

5 Table 8-2.

6

7 Table 8-2 Summary Table for Conditional Probability of C-SGTR Studied as Base Cases

8

Conditional Probability of C-SGTR

SG Type SBO with AFW TDP 

failure at time = 0

SBO with AFW failure 

at battery depletion

Inconel Material

CE 2.2E-1 3.1E-01 690

Westinghouse 1.3E-2 (*) 600

Westinghouse 8.9E-3 (*) 690

* This sequence is not studied as a base case.

9

10 Section 7.1 discussed and quantified the LERF Scenarios for the representative Westinghouse 

11 plant. The following observations were made for Westinghouse plants:

12

13 • For Westinghouse plants, the contribution of C-SGTR to containment bypass could be 

as high as 9×10-07 14 per year, considering all hazard categories. If only internal events are 

15 considered, this value would be 2E-07 per year or lower.

16

17 • Based on the existing PRAs, C-SGTR does not appear to be a major contributor to 

18 LERF.

19

20 • The containment bypass contribution is mainly from the scenarios where the TDAFW 

21 initially worked, but was later rendered inoperable after the depletion of batteries. Such 

22 scenarios are not generally considered as LERF.

23
8-4

1 • It is generally concluded that in Westinghouse plants, the C-SGTR and the associated 

2 LERF do not make any significant contribution, unless there exist large and deep flaws 

3 in one or more SGs.

4

5 This study focused on a four-loop Westinghouse plant and used the design parameters and 

6 measurement of original Westinghouse Model 51 SGs. Many of current operating 

7 Westinghouse plants are equipped with replacement SGs with different design features and 

8 measurements. The conclusions and results noted above, therefore, should be tempered with 

9 the specific design of SGs.

10

11 Section 7.2 discussed and quantified the LERF Scenarios for the representative CE plant. The 

12 conditional containment bypass probabilities due to C-SGTR for SBOs with early or late failures 

13 of TDAFW were about 0.22 and 0.31 respectively. These conditional probabilities of 

14 containment bypass when multiplied by the frequency of the entry conditions (i.e., SBO with 

early or late failure of TDAFWs (Table 7-14)) approximately resulted in a frequency of 1.1×10-05 15

per reactor year for both SBO scenarios (i.e., 9.5×10-06 16 for SBO scenarios with failures of 

TDAFW pumps after battery depletion, and 5.7×10-07 17 for SBO scenarios with early failure of 

18 TDAFW pumps). The LERF contribution is from those scenarios where early failures of TDAFW 

19 pumps have occurred. The following observations were made for CE plants:

20

21 • For CE plants, the contribution of C-SGTR to containment bypass could be as high as 

22 1.0E-05, considering contributions from all hazard categories. If only internal events are 

considered, this contribution is expected to be about 5.65×10-08 23 .

24

25 • Based on the existing PRAs, C-SGTR appears to be the highest contributor to LERF for 

26 all hazard models.

27

28 • The containment bypass contribution mainly results from the scenarios where the 

29 TDAFW initially worked, but was later rendered inoperable after the depletion of 

30 batteries. Such scenarios are not generally considered as LERF.

31

32 • Extending the battery life and operation of TDAFW can reduce the frequency of 

33 containment bypass. This also facilitates the SAMG operation and use of additional 

34 equipment such as the existing EDMG or the future equipment in response to FLEX 

35 program.

36

37 8.2 Limitation of Supporting Analyses for PRA Models

38

39 This PRA study relied on the existing models and analyses in the following areas. These were:

40

41 • representing the variations in tube temperatures by average hot tube and the hottest 

42 tube

43

44 • TH evaluation of accident sequences

45

46 • severe accident analysis

47

48 • creep rupture and fracture mechanic models for failure of flawed and pristine tubes

49

50 • leak area models for failed tubes
8-5

1

2 • creep rupture models and data for HL and surge line

3

4 • surveillance data from SG periodic inspection

5

6 • material properties at high temperature

7

8 The status of each of the above elements and their limitations are summarized below.

9

10 8.2.1 Variations in Tube Temperatures by Average Hot Tube and the Hottest Tube

11

12 The tube temperature varies across the tubes and within a tube (along the tube length). This 

13 temperature profile is varying in a continuous manner. It may be represented with a set of 

14 temperature bins to capture temperature variations among the tubes and within a tube. The 

15 larger the number of bins or the higher the bin resolutions, the more calculations and increased 

16 code capabilities are required. This study currently uses two temperature-bins, reflecting the 

17 average tube temperature and the hottest temperature. Small uncertainties (approximately 

18 0.3 percent) are built into the code to capture slight temperature variations within a bin.

19

20 8.2.2 TH Evaluation of Accident Sequences

21

22 TH analyses were performed using RELAP code for Westinghouse plants and MELCOR for CE 

23 plants. Consistent use of either MELCOR or RELAP for both CE and Westinghouse plants, will 

24 provide a better basis for comparing the results, and will help to better characterize the 

25 uncertainties.

26

27 8.2.3 Severe Accident Analysis

28

29 A limited number of MELCOR analyses of severe accidents were available for CE plants to 

30 address Level 2 PRA issues, for example the magnitude of releases. These are in addition to 

31 and independent of the simple LERF model used in the PRA analysis. Additional MELCOR 

32 runs informed by PRA assumptions will be needed to develop the Level 2 PRA for C-SGTR for 

33 both CE and Westinghouse plants.

34

35 8.2.4 Creep Rupture and Fracture Mechanic Models

36

37 The creep rupture and pressure-induced fracture mechanic models for tube failures are only 

38 available for tubes with a crack flaw. Wear flaws are the dominant flaw mechanisms for 

39 replaced SGs. The models for crack flaws do not necessarily apply to wear flaws. This study 

40 used tube thinning model to approximate the failure probability of a tube with a wear flaw. 

41 Fracture mechanics and creep rupture models for wear flaws, when available; can improve the 

42 results of this study. For the pristine tubes, fracture mechanic models are available to predict 

43 the tube failures but not the resulting leak rates.

44

45 8.2.5 Leak Area Models for Failed Tubes

46

47 The models to predict the resulting leak area from a failed tube is available for a tube with a 

48 crack flaw. Leak models, however, are not available for failed pristine tubes. The leak areas 

49 estimated from these models have relatively large uncertainties. The models used to predict 

50 failures from wear flaws have not yet been studied at the same level as the failure models for 

51 the cracked flaws. This could result in additional uncertainties. The more enhanced models to 
8-6

1 estimate leak areas for a wear flaw can reduce the uncertainties associated with the quantitative 

2 results.

3

4 8.2.6 Creep Rupture Models and Data for HL and Surge Line

5

6 EPRI models were used for predicting the failures of HLs and surge line due to creep rupture in 

7 the PRA analysis. Failures were assumed to be catastrophic, resulting in a very large leak area. 

8 This study neither performed, nor found any reference to confirm the EPRI correlations. 

9 However, the more detailed analyses performed for HL failures as discussed in Section 4 

10 showed consistent results.

11

12 8.2.7 Surveillance Data from SG Periodic Inspection

13

14 This study used the most recent data from periodic surveillance inspection to better represent 

15 the flaw generation rate and their characteristics. However, the number of plants with available 

16 data was quite limited, and it is suspected that the data on flaw size may not be representative. 

17 Updating flaw characteristics on a periodic basis will not only help the PRA quantification 

18 process, but will also help the U.S. Nuclear Regulatory Commission oversight program on SGs.

19

20 8.2.8 Material Properties at High Temperature

21

22 The primary circuits, including the SG tubes, are expected to be exposed to high temperatures 

23 because of severe accidents (post core damage). The material properties of interest were 

24 obtained from various sources. Additional work for the same materials for nuclear application 

25 could improve the prediction of fracture mechanic models.
9-1

1 9. OVERALL SUMMARY

2

3

4 The work documented in this report has been performed over multiple years by different 

5 disciplines, and has evolved into its current scope and form during those years because of

6 technical and project-related constraints. The main thrust of the report is on estimating the 

7 potential consequential steam generator tube rupture (C-SGTR) risk in different types of steam 

8 generators (SGs), using quantitative probabilistic risk assessment (PRA) methods. In parallel to 

9 this PRA work, two other types of analyses were performed: thermal-hydraulic (TH) analyses, 

10 and structural analyses. Thus, these three types of independent analyses make up the report 

11 contents.

12

13 The objective of this section is to summarize the nature and conclusions of the three types of 

14 analyses mentioned above. The conclusions are already presented in their respective sections 

15 and are merely summarized here. These sections are:

16

17 • Sections 7 and 8 for PRA

18 • Section 3 for T&H using MELCOR for a Combustion Engineering (CE) plant

19 • Section 4 for Structural analyses of “other reactor coolant system (RCS)” components

20

21 Before summarizing the conclusions of these three analyses at the end of this section, first 

22 some of the modeling aspects are discussed.

23

24 Section 2 defines three basic modeling pieces to define and focus the scope of PRA work:

25

26 • accident sequences to be modeled,

27 • “critical tube leak size” for PRA purposes, and

28 • a large early release frequency (LERF) model for PRA purposes.

29

30 In Section 3, MELCOR software is used to model key accident sequences for a CE plant. This 

31 work is new and is done specifically for this project. The work done in this section can be 

32 viewed in terms of two parts:

33

34 (1) generation of accident sequence TH parameters (e.g., pressure and temperature as a 

35 function of time)

36

37 (2) estimation of fission product release characteristics for these sequences

38

39 The results of the first part are used as input into the PRA model, which is documented in 

40 Section 7. As it is expected, PRA and MELCOR models have different approaches and 

41 assumptions in calculating fission product release characteristics. Among other factors, this is 

42 due to:

43

44 • use of a more advanced flawed tube model in the PRA model whereas tube flaws were 

45 modeled in MELCOR using stress multiplication factors

46

47 • definition of what constitutes a C-SGTR (critical size, failure of other RCS components)

48

49 • definition of a LERF model in PRA as a surrogate to model fission product release

50
9-2

1 In PRA analysis, accident sequence TH parameters for the Westinghouse plant studied are 

2 taken from NUREG/CR-6995, which used SCDAP/RELAP5 for analysis. The accident 

3 sequence TH parameters for the CE plant studied are taken from Section 3, and are generated 

4 by MELCOR.

5

6 Conclusions about fission product release characteristics for a CE plant, as discussed in 

7 Section 3 versus those in Sections 7 and 8 should be viewed in light of the independent 

8 modeling assumptions for MELCOR analyses and PRA models.

9

10 The PRA model includes credit for failure of another RCS component before the failure of SG 

11 tubes, thus resulting in a lesser release consequence. The PRA model uses the HL/surge line 

12 failure model existing in the early stages of the project. Later confirmatory work done in 

13 structural analysis using more state-of-the art modeling on Westinghouse sequences is given in 

14 Section 4. It should be noted that the PRA calculations did not include the confirmatory work 

15 models and their results discussed in Section 4.

16

17 Although the PRA models focused on the “temperature induced” C-SGTR sequences (after 

18 occurrence of core damage) due to creep rupture, two types of tube failure correlations were 

19 modeled:

20

21 (1) high-pressure, low temperature (e.g., below creep rupture range) correlation

22 (2) high temperature correlation for temperature in the creep rupture range

23

24 It is deemed that the second correlation might underestimate failure at lower temperature with 

25 high pressure. Risk estimates for potential pressure-induced C-SGTR sequences (such as 

26 anticipated transients without scram (ATWS) and large steam line breaks) were also performed 

27 and discussed in Section 7.4. Such sequences might generate additional core damage 

28 frequency, as opposed to temperature-induced C-SGTR sequences which are initiated by 

29 already identified core damage sequences. It is estimated that very large pressure differences 

30 across the SG tubes at “lower” temperatures are needed for failure of flawed tubes; and that the 

31 contribution of pressure-induced sequences to plant CDF is not expected to be significant.

32

33 Another new analysis in the report is generation of tube flaw distributions for thermally treated 

34 Alloy 600 and 690 material used in replacement SGs of the current fleet of plants. These 

35 distributions are generated from a limited set of SG inspection reports submitted to the NRC. 

36 The work is presented in Section 6 of the report. The results indicated that with these tube 

37 materials:

38

39 • Mostly “wear” (volumetric) type flaws are observed (as opposed to circumferential and 

40 axial flaws observed in the previous generation of SG tubes).

41

42 • The number of flaws of all types started to appear around the 15th effective full power 

43 year of operation.

44

45 The PRA model uses the 15-year flaw distribution as the base criteria to make estimates and 

46 comparisons. For SG tubes with lesser number of years, the estimates will be more favorable, 

47 and vice versa.

48

49 A software referred to as the C-SGTR Calculator has been developed to support the work in this 

50 report. The calculator is used to estimate failure times and leak sizes of SG tubes with different 

51 types of flaws. The software also has built in models for failure of HL (HL) and surge line 
9-3

1 because of creep rupture failure mechanism and estimates failure times and probabilities of HL 

2 and surge line. The scope of the models currently includes new SG tube materials and the 

3 associated property data for both thermally treated Inconel 600 and 690. This calculator is 

4 briefly discussed in Appendix B of the report.

5

6 PRA Conclusion

7

8 The main PRA conclusion is that the lower SG geometry and the fluid flow rates in different SG 

9 designs may affect the potential likelihood of C-SGTR following core damage sequences, where 

10 the SG tubes are challenged. It appears that the type of SGs, with tube plates located lower 

11 (such as in CE plants) than other SG designs (such as in Westinghouse plants), may have a 

12 larger fraction of C-SGTR following core damage and failure of primary and secondary cooling. 

13 Thus, higher LERF fractions may result in the first type of SGs.

14

15 Previous conclusions on the effect of “loop seal clearing” are not changed; for any of the SGs 

16 geometries, if loop seal clearing occurs in an accident sequence (such as the one caused by a 

17 large reactor coolant pump (RCP) seal leak), the tube failures are expected to happen early. 

18 TH analysis reported in NUREG/CR-6995 indicated that the probability that the loop seal is 

19 cleared is almost certain if the RCP leakage is about 1,700 liters per minute (Lpm) (450 gpm). 

20 For RCP seal leakage of 1,135 Lpm (300 gpm), the TH analysis predicted no possibility that the 

21 loop seal is cleared.

22

23 Other RCS Components Conclusion (from Section 4)

24

25 The analyses presented in Section 4.4 indicate that the upper half of the HL will fail much earlier 

26 than the other RCS regions. The failure times predicted by the various analyses considered in 

27 Section 4.4 are summarized in Table 4.4. The predicted failure times for all the cases 

28 considered are below the median failure time of 12,600 s, estimated by C-SGTR calculator, but 

29 not excessively so. Therefore, the C-SGTR calculator provides a reasonable estimation of HL

30 failure.

31

32 MELCOR Conclusions for CE Plant

33

34 Additional scrutiny is given to CE plants with replacement steam generators because their 

35 geometry is more susceptible to C-SGTR than the Westinghouse designs. The short HL length36 to-diameter ratio and relatively shallow SG inlet plena in some replacement steam generators 

37 results in high temperature gas reaching the steam generator tubes during closed-loop-seal 

38 natural circulation conditions. Hotter gases reaching the steam generator tube reduce the time 

39 before tube failure which increases the likelihood of containment bypass. A station blackout 

40 (SBO) is the situation in which thermally induced C-SGTR is expected to occur. A few aspects 

41 of the scenario are of interest for the purpose of determining fission product (FP) releases to the 

42 environment: (1) whether a steam generator tube or some other part of the RCS pressure 

43 boundary fails first, and (2) whether tube failure results in sufficient and rapid enough RCS 

44 depressurization to prevent rupture of some other part of the RCS boundary. In the 

45 Westinghouse analysis the presence of a flaw is required for the prediction of tube failure before 

46 other RCS component failure. This behavior results in the prediction of failure of a single tube 

47 which results does not depressurize the primary at a rate sufficient to prevent subsequent failure 

48 of other RCS components. Unlike for other analyzed designs unflawed tubes exposed to the 

49 relatively unmixed hot gases that reach the SG tubes in CE designs with shallow-inlet-plenum 

50 replacement steam generators can also fail. This consists of a qualitative change in system 

51 behavior because multiple tubes can fail depressurizing the RCS sufficiently to prevent the 
9-4

1 creep rupture failure of other components thus leaving the containment bypass pathway as the 

2 sole release path of FPs from the reactor.

3

4 The MELCOR analyses performed independently with their own set of assumptions are 

5 summarized in the report as follows.

6

7 The relatively shallow inlet plenum design of the replacement steam generator under 

8 consideration for the CE plant has an impact on the results of the computational fluid dynamics

9 predictions. The shallow design limits the mixing of the hot gases which enter the steam 

10 generator which creates a higher thermal load on the tubes.

11

12 The following conclusions are also obtained:

13

14 • Even if an SGTR rupture occurs first, without an assumption of secondary-side breach, 

15 by failure or opening by human error, no or minimal releases will occur.

16

17 • For a high pressure secondary side (high-dry-high situation), a HL will fail before an 

18 unflawed tube thus preventing tube rupture in the absence of tube flaws.
A-1

1 APPENDIX A

2

3 HIGH TEMPERATURE DEFORMATION AND DAMAGE OF RCS 

4 MATERIALS

5

6

7 A.1 Material Properties Used in Section 4

8

9 A literature search was conducted for high-temperature material properties data that are needed 

10 to carry out the analyses. The collected materials properties data are given in Appendix A-2. 

11 Table A-1 lists the various components in the Zion Nuclear Power Plant (ZNPP) that were 

12 analyzed, the materials, and the range of temperatures for which high-temperature tensile and 

13 creep properties were initially collected. The table identifies gaps in the required database. To 

14 partially fill the gap in the material properties database, a materials testing program was 

15 conducted at Argonne National Laboratory (ANL) during the follow-on program funded by the 

16 U.S. Nuclear Regulatory Commission (NRC) obtain high-temperature tensile and creep 

17 properties of materials identified in Table A-1. The details of the test results are given in 

18 Appendix A-1-2. The base materials tested were:

19

20 • SA 516 Grade 70 carbon steel

21 • SA 240 Grade 316 stainless steel

22 • SA 351 Grade CF8M cast stainless steel

23 • SA 193 B7 bolt material

24

25 In addition, the following weldments were tested:

26

27 • stainless (SA-240 Grade 316) steel plate to carbon steel (SA-516 Grade 70) plate 

28 weldment

29

30 • wrought stainless (SA-240 Grade 316) plate to cast stainless steel (SA-351 Grade 

31 CF8M) plate weldment

32

33 • stainless (SA-240 Grade 316) steel plate to stainless (SA-240 Grade 316) steel plate 

34 weldment

35

36 The temperature range over which the various tests were conducted are given in Table A-2.

37
A-2

Table A-1 Range of Temperatures (°C) for which High-Temperature Material Properties 1

Data Are/Are Not Available 2

3

RCS 

Component Material

Tensile Properties Creep Properties

Stress–

Strain 

Curves

Tensile 

Strengths

Creep Rate Rupture 

Time

Piping, 

RTD Body

PORV plug

SA 240 Grade 

Type 316 SS 400–982 400–1093 538–816 427–1093

HL Elbow SA 351 Grade

CF8M 400–871 538–649 454–1000

Surge Line to 

HL Nozzle

SA 182

F316 Not found 400–538 Not found 549–699

Weld 308 SS 565 482–593 593 454–704

RV Nozzle A–508 Class 2 Not found 400–727 627–752 627–95

SG and PZR 

Nozzles

SA 216

WCC Not found 400–538 Not found Not found

Manway 

Cover

SA 533 A1

(SA 533 B1)

Not found

(649–1200)

400–538

(400–1200)

Not found

(400–1100)

Not found

(400–1100)

Manway Insert Type 304 SS 700–1100 400–1100 427–1077 538–1077

Manway Bolts A 193 (B7) Not found Not found Not found Not found

PORV Cage

SA 564 

(17–4PH) 

H1100

Not found 400–538 Not found Not found

4

Table A-2 Materials and Temperature Ranges (°C) over which Materials Properties Data 5

Were Generated by ANL 6

7

Material

Tensile Properties Creep Properties

Stress–

Strain 

Curves

Tensile 

Strengths

Creep 

Rate

Rupture 

Time

SA 240 Grade Type 316 SS 700–1100 700–1100 700–1100 700–1100

SA 351 Grade

CF8M 700–1000 700–1000 700–1000 700–1000

SA 516 Grade 70

Carbon steel 500–800 500–800 500–800 500–800

SA 193 B7 Bolts 450–650 450–650 450–650 450–650

SA 240 Grade 316 to SA516 

Grade 70 weldment 700–1000 700–1000 700–1000 700–1000

SA 240 Grade 316 to SA240 

Grade 316 weldment 700–1000 700–1000

SA 240 Grade 316 to SA 351 

Grade CF8M weldment 700–1000 700–1000

8
A-3

1 A.2 High Temperature Creep Rupture Test Data

2

3 Bolt Material (SA 193 B7)

4

5 A summary of all of the bolt creep tests, which were run in duplicate, are listed in Table A-3. 

6 Because our interest is in station blackout (SBO) severe accidents, which last several hours, 

7 tests that did not fail by 100 h were interrupted. Creep curves at 450, 550, and 650 degrees C 

8 (842, 1,022, and 1,202 degrees F) are given in Figures A-1a to A-1c, respectively. Note that 

9 although the tests at 450 and 550 degrees C (842 and 1,022 degrees F) experienced primary 

10 creep, those at 650 degrees C (1,202 degrees F) did not.

11

Table A-3 Summary of Creep Data for SA 193 B7 Bolt Material 12

13

Specimen 

No.

Temperature 

°C (°F)

Stress

ksi (MPa)

Rupture 

Time (h)

% 

Elongation

%

RA

Minimum 

Creep Rate 

(%/h)

B-4 450 (842) 40 (276) * 100 - - 0.0031

B-5 450 (842) 40 (276) * 100 - - 0.0026

B-22 450 (842) 30 (207) * 100 - - 0.0013

B-7 450 (842) 30 (207) * 100 - - 0.0013

B-8 450 (842) 20 (138) * 100 - - 0.0007

B-9 450 (842) 20 (138) * 100 - - 0.0004

B-10 550 (1022) 30 (207) 57.9 49.4 78.2 0.2923

B-11 550 (1022) 30 (207) 53.1 48.2 78.8 0.3071

B-12 550 (1022) 20 (138) * 100 - - 0.0354

B-13 550 (1022) 20 (138) * 100 - - 0.0377

B-14 550 (1022) 10 (69) * 100 - - 0.0033

B-15 550 (1022) 10 (69) * 100 - - 0.0043

B-16 650 (1202) 20 (138) 0.8 73.1 89.3 -

B-17 650 (1202) 20 (138) 0.8 56.9 87.6 27.0500

B-18 650 (1202) 10 (69) 17.5 96.8 89.8 1.6283

B-19 650 (1202) 10 (69) 17.7 85.8 89.1 1.6456

B-20 650 (1202) 7.5 (52) 40.2 87.7 91.9 0.8178

B-21 650 (1202) 7.5 (52) 45.4 91.3 88.1 0.7560

* Test interrupted

14
A-4

(a) (b)

(c)

1

2 Figure A-1 Creep curves for SA 193 B7 material at (a) 450, (b) 550, (c) 650 °C

3

4 The built-in equation for the creep strain rate in the finite-element program ABAQUS can be 

5 either in the time-hardening form, that is,

6

7 (0a)

8

9 or in the strain-hardening form, that is,

10

11 (1b)

12

13 where A, n, and m are functions of temperature, σ is stress, is creep strain, is creep strain 

14 rate, and t is time. An integrated version of the creep rate equation is

15

16 (0a)

17
A-5

1 where . Writing Eq. 2 in an Arrhenius form,

2

3 (2b)

4

5 where T is absolute temperature, Q is a fitting parameter, and B = B0exp(Q/T). Equation 2b 

6 was used to determine the parameters B, m, Q, and n from the creep tests. The best-fit 

7 parameters are tabulated in Table A-4, with creep strain εc in m/m, stress σ in kilopounds per 

8 square inch (ksi), time t in h, and absolute temperature T in K. The fitted creep curves are 

9 compared with the test curves in Figures A-2 to A-4. Except for a few tests, the fit in the first 2 

10 h, which is of interest for SBO severe accidents, is reasonable.

11

Table A-4 Best-Fit Values of the Parameters B, m, Q and n of SA 193 B7 As Determined 12

from the Creep Tests 13

14

T (°C) B m Q A N

450 16800 -0.501 17300 3.45E-7 1.80

550 16600 -0.363 19700 6.5E-7 2.60

650 26000 -0.187 18700 3.19E-5 2.78

15
A-6

(a) (b)

(c)

1

2 Figure A-2 Comparison of fitted and test variation of creep strain vs. time for creep tests 

3 conducted on SA 193 B7 at 450 °C at (a) 20, (b) 30, and (c) 40 ksi

4
A-7

(a) (b)

(c)

1

2 Figure A-3 Comparison of fitted and test variation of creep strain vs. time for creep tests 

3 conducted on SA 193 B7 at 550 °C at (a) 10, (b) 20, and (c) 30 ksi

4
A-8

(a) (b)

(c)

1

2 Figure A-4 Comparison of fitted and test variation of creep strain vs. time for creep tests 

3 conducted on SA 193 B7 at 650 °C at (a) 7.5, (b) 10, and (c) 20 ksi

4

5 SA 240 Grade 316 Stainless Steel

6

7 A summary of all the creep tests, all of which were run in duplicate, is shown in Table A-5. 

8 Representative creep strain vs. time curves at 700, 800, 1,000, and 1,100 °C (1,292, 1,472, 

9 1,832, and 2012 degrees F) are plotted in Figures A-4 to A-6. In most cases, primary creep is 

10 absent and the tests show either a steady state creep behavior or a steady state followed by 

11 tertiary creep behavior. All available U.S. creep rate data were fitted to Eq. 1a to obtain the 

12 parameters A, n, and m at various temperatures, as listed in Table A-6. The fitted creep rates 

13 are plotted against the test creep rates in Figure A-7, which shows that the bulk of the creep 

14 rate data can be predicted to within a factor of 4.8 and the ANL data fall within the scatter band 

15 of the much larger database.

16
A-9

Table A-5 Summary of Creep Data for SA 240 Grade 316 Stainless Steel 1

2

Specimen 

No.

Temperature 

°C (°F)

Stress

ksi (MPa)

Rupture 

Time (h)

% 

Elongation

%

RA

Minimum 

Creep Rate 

(%/h)

O-4 700 (1292) 30 (207) 7.2 49.5 80.9 -

O-5 700 (1292) 30 (207) 7.0 51.5 81.7 2.99

O-10 700 (1292) 28 (193) 12.3 61.2 81.2 2.40

O-11 700 (1292) 28 (193) 14.5 48.4 84.0 1.25

O-16 700 (1292) 26 (179) 31.3 51.6 76.8 0.70

O-17 700 (1292) 26 (179) 28.6 54.1 80.9 0.73

O-6 800 (1472) 19.0 (131) 2.4 64.7 89.0 -

O-7 800 (1472) 19.0 (131) 2.4 61.0 88.4 -

O-12 800 (1472) 15.0 (103) 14.2 67.0 86.8 1.44

O-13 800 (1472) 15.0 (103) 12.9 70.3 89.1 1.68

O-18 800 (1472) 13.0 (90) 35.4 82.9 89.4 0.73

O-19 800 (1472) 13.0 (90) 30.6 84.0 89.7 0.85

O-14 1000 (1832) 4.0 (28) 11.5 75.7 88.2 0.70

O-15 1000 (1832) 4.0 (28) 10.3 76.6 89.8 1.11

O-20 1100 (2012) 2.0 (14) *100 - - 0.079

O-21 1100 (2012) 2.0 (14) *100 - - 0.079

O-8 1100 (2012) 4.0 (28) 0.5 75.6 91.3 -

O-9 1100 (2012) 4.0 (28) 0.6 82.7 90.8 -

* Test interrupted

3

(a) (b)

4

5 Figure A-5 Creep strain vs. time curves of SA-240 Grade 316 stainless steel at 700 °C 

6 (a) 26 ksi (179 MPa) and (b) 28 ksi (193 MPa) and 30 ksi (207 MPa)

7
A-10

(a) (b)

1

2 Figure A-6 Creep strain vs. time curves of SA-240 Grade 316 stainless steel at 800 °C 

3 (a) 13 ksi (90 MPa) and (b) 15 ksi (103 MPa)

4

Table A-6 Creep Rate Parameters for Available Data on Type 316 Stainless Steel 5

6 Mean and ±95% confidence bounds at various temperatures

7 (stress in ksi and creep rate in 1/h)

8

T (°C) m N A (mean) A(-95%) A (+95%)

350 0 9.35 4.4925E-30 9.3594E-31 2.1564E-29

450 0 9.35 1.1269E-24 2.3478E-25 5.4093E-24

500 0 9.35 1.6894E-22 3.5195E-23 8.1090E-22

550 0 9.35 1.3778E-20 2.8703E-21 6.6133E-20

600 0 9.35 6.7869E-19 1.4139E-19 3.2577E-18

650 0 9.35 2.1918E-17 4.5663E-18 1.0521E-16

675 0 8.80 9.8651E-16 2.0552E-16 4.7352E-15

700 0 7.20 2.7813E-13 5.7945E-14 1.3350E-12

750 0 6.52 3.9794E-11 8.2904E-12 1.9101E-10

800 0 6.52 3.8282E-10 7.9755E-11 1.8376E-09

850 0 6.52 3.3115E-09 6.8990E-10 1.5895E-08

900 0 6.52 2.3829E-08 4.9643E-09 1.1438E-07

1000 0 6.52 7.4218E-07 1.5462E-07 3.5625E-06

1100 0 6.52 1.2748E-05 2.6558E-06 6.1190E-05

9
A-11

(a) (b)

1

2 Figure A-7 Creep strain vs. time curves of SA-240 Grade 316 stainless steel at (a) 

3 1,000 °C, 4 ksi (28 MPa) and (b) 1,100 °C, 2 ksi (14 MPa)

4

5

6

7 Figure A-8 Predicted vs. test minimum creep rate of SA 240 Grade 316 stainless steel

8

9 The available time to stress rupture U.S. data for Grade 316 stainless steel were fitted with a 

10 Larson-Miller parameter, as shown in Figure A-9. In equation form the Larson-Miller plot is 

11 given by

12
A-12

1 (A0)

2

3 and the time to rupture tR in h is given by

4

5 (A0)

6

7 where T = temperature in K. Figure A-9 also shows the parameter values for ±95 percent 

8 confidence limits. The predicted times to rupture are plotted against test rupture times in 

9 Figure A-10, which shows that the bulk of the data can be predicted to within a factor of 6.

10

11

12

13 Figure A-9 Larson-Miller parameter plot for time to stress rupture of SA 240 Grade 316 

14 stainless steel at 538–1,100 °C

15

16 The steady state creep ductility, defined as the product of the steady state (or minimum) creep 

17 rate and the time to rupture, is plotted as a function of stress and temperature in Figures A-11 to 

18 A-14. There is significant scatter in the data but no definite trend as a function of stress. 

19 However, the steady state ductility shows an increase with increasing temperature and leveling 

20 off at high temperature, as shown in Figure A-15.

21
A-13

1

2

3 Figure A-10 Predicted vs. test time to stress rupture of SA 240 Grade 316 stainless steel 

4 at 538–1,100 °C

5

(a) (b)

6

7 Figure A-11 Steady state creep ductility vs. stress of SA 240 Grade 316 stainless steel at 

8 (a) 538 and (b) 566 °C

9
A-14

(a) (b)

1

2 Figure A-12 Steady state creep ductility vs. stress of SA 240 Grade 316 stainless steel at 

3 (a) 593 and (b) 649 °C

4

(a) (b)

5

6 Figure A-13 Steady state creep ductility vs. stress of SA 240 Grade 316 stainless steel at 

7 (a) 700 and (b) 760 °C

8
A-15

1

2

3 Figure A-14 Steady state creep ductility vs. stress of SA 240 Grade 316 stainless steel at 

4 800 °C

5

6

7

8 Figure A-15 Estimate mean, upper and lower bounds to the steady state creep ductility of 

9 SA 240 Grade 316 stainless steel

10

11 SA 351 Grade CF8M Cast Stainless Steel

12

13 A summary of the creep tests conducted at ANL are shown in Table A-7. Representative creep 

14 strain vs. time curves at 700, 800, and 1,000 °C are plotted in Figures A-16 to A-18. In many 

15 cases, primary creep is absent and the tests show either a steady state creep behavior or a 

16 steady state followed by tertiary creep behavior. The available creep database for CF8M cast 

17 stainless steel is rather limited. Harada in Japan has reported creep data on CF8M cast 

18 stainless steel. The combined creep rate data base were fitted to Eq. 1a to obtain the 

19 parameters A, n, and m at various temperatures, as listed in Table A-8. The fitted creep rates 

20 are plotted against the test creep rates in Figure A-19a, which shows that the bulk of the creep 

21 rate data can be predicted to within a factor of 10.7. The uncertainty is larger than SA-240 

22 Grade 316 stainless steel because of the much more limited data base available for SA-351 

23 Grade CF8M cast stainless steel. Note that the ANL data fall within the scatter band of the 

24 combined data base.
A-16

1

Table A-7 Summary of Creep Data for SA 351 Grade CF8M Cast Stainless Steel 2

3

Specimen 

No.

Temperature 

°C (°F)

Stress

ksi (MPa)

Rupture 

Time (h)

% 

Elongation

%

RA

Minimum 

Creep Rate 

(%/h)

ATLAS-4 700 (1292) 15 (103) 60.9 8.4 24.3 7.46E-02

ATLAS-5 700 (1292) 15 (103) * 100.0 - - 9.04E-02

ATLAS-10 700 (1292) 17 (117) 8.0 5.7 18.9 1.67E-01

ATLAS-13 700 (1292) 17 (117) 7.5 3.4 7.9 2.49E-01

ATLAS-14 700 (1292) 16 (110) 0.5 3.5 14.3 -

ATLAS-15 700 (1292) 16 (110) 29.2 8.4 18.3 1.40E-01

ATLAS-6 800 (1472) 14 (97) 2.1 13.5 19.7 3.88E+00

ATLAS-7 800 (1472) 14 (97) 1.3 10.4 30.8 4.32E+00

ATLAS-11 800 (1472) 12 (83) 1.3 5.2 10.0 2.20E+00

ATLAS-16 800 (1472) 12 (83) 0.7 10.0 18.3 -

ATLAS-17 800 (1472) 10 (69) 0.9 5.3 8.6 -

ATLAS-18 800 (1472) 10 (69) 7.4 12.5 23.0 8.81E-01

ATLAS-8 1000 (1832) 6 (41) 0.1 13.1 29.9 -

ATLAS-9 1000 (1832) 6 (41) 0.1 8.9 16.4 -

ATLAS-12 1000 (1832) 3 (21) 13.3 19.1 26.9 1.19E+00

ATLAS-19 1000 (1832) 3 (21) 0.9 9.1 17.0 1.96E+00

ATLAS-20 1000 (1832) 2 (14) * 100.0 - - 9.96E-02

ATLAS-21 1000 (1832) 2 (14) 14.1 5.8 12.8 2.58E-01

* Test interrupted

4

(a) (b)

5

6 Figure A-16 Creep strain vs. time curves of SA-351 Grade CF8M cast stainless steel at 

7 700 °C (a) 15–16 ksi (103–110 MPa) and (b) 17 ksi (117 MPa)

8
A-17

(a) (b)

1

2 Figure A-17 Creep strain vs. time curves of SA-351 Grade CF8M cast stainless steel at 

3 800 °C (a) 12 and 14 ksi (83–97 MPa) and (b) 10 ksi (69 MPa)

4

(a) (b)

5

6 Figure A-18 Creep strain vs. time curves of SA-351 Grade CF8M cast stainless steel at 

7 1,000 °C (a) 3 ksi (21 MPa) and (b) 2 ksi (14 MPa)

8
A-18

Table A-8 Mean and ±95% Confidence Bounds of Creep Rate Parameters for Combined 1

ANL and Japanese Data on SA-351 Grade CF8M Cast Stainless Steel at Various 2

Temperatures (stress in ksi and creep rate in 1/h) 3

4

T (°C) m n A (mean) A(-95%) A (+95%)

350 0 9.5 5.233E-25 5.599E-24 4.891E-26

450 0 9.5 5.866E-21 6.276E-20 5.482E-22

500 0 9.5 2.513E-19 2.689E-18 2.349E-20

550 0 9.5 6.820E-18 7.297E-17 6.374E-19

600 0 9.5 1.268E-16 1.357E-15 1.185E-17

650 0 9.5 6.919E-16 7.403E-15 6.466E-17

700 0 9.5 3.585E-15 3.836E-14 3.351E-16

750 0 8.7 2.661E-13 2.847E-12 2.487E-14

800 0 5.0 2.003E-08 2.143E-07 1.872E-09

850 0 5.0 4.609E-07 4.932E-06 4.308E-08

900 0 5.0 3.357E-06 3.592E-05 3.137E-07

950 0 5.0 2.281E-05 2.441E-04 2.132E-06

1000 0 5.0 1.143E-04 1.223E-03 1.068E-05

1050 0 5.0 6.393E-04 6.841E-03 5.975E-05

1100 0 5.0 3.156E-03 3.376E-02 2.949E-04

5

6 The available time to stress rupture for the combined Japanese and U.S. data for SA-351 Grade 

7 CF8M cast stainless steel were fitted with a Larson-Miller parameter, as shown in Figure A-19b. 

8 In equation form the Larson-Miller plot is given by

9

10 (A0)

11

12 where stress σ is in ksi and the time to rupture tR in h is given by

13

14 (A0)

15

16 where T = temperature in K. Figure A-19b also shows the parameter values for ±95 percent

17 confidence limits. The predicted times to rupture are plotted against test rupture times in 

18 Figure A-20, which shows that the bulk of the combined data can be predicted to within a factor 

19 of 4.8.

20

21 The steady state ductility of the ANL CF8M specimens is considerably less than that of the 

22 Japanese CF8M heat (Figure A-21a) and also much less than that of the SA-240 Grade 316 

23 stainless steel (Figure A-15). The total elongation of the U.S. CF8M heat is comparable to the 

24 steady state ductility of the Japanese CF8M heat (Figure A-21b).

25
A-19

(a) (b)

1

2 Figure A-19 Confidence bounds for the prediction of (a) creep rate and (b) Larson-Miller 

3 parameter for time to rupture of SA-351 Grade CF8M cast stainless steel based on ANL 

4 and Japanese data

5

6

7

8 Figure A-20 Predicted vs. observed time to stress rupture of SA-351 Grade CF8M cast 

9 stainless steel

10
A-20

(a) (b)

1

2 Figure A-21 Variation of (a) steady state ductility of U.S. and Japanese CF8M heats and 

3 (b) total elongation of U.S. CF8M heat with stress

4

5 SA 516 Grade 70 Carbon Steel

6

7 A summary of the creep rupture tests conducted at ANL is presented in Table A-9. The creep 

8 curves at 500, 650, and 800 degrees C (932, 1,202, and 1,472 degrees F) are plotted in 

9 Figures A-22a to A-22c, respectively. The ANL data for SA-516 Grade 70 were combined with 

10 available data for SA-216 Grade WCC from the literature and the combined data fitted to Eq. 1a 

11 to obtain the parameters A, n, and m at various temperatures, as listed in Table A-10. Figure 

12 A-23a shows that the combined creep rate data can be predicted to within a factor of 3 by using 

13 Eq. 1a and the parameters listed in Table A-10. Although the data sets are limited, both fall 

14 within the same scatter band.

15

16 The available time to stress rupture for the combined ANL data for SA-516 Grade 70 and 

17 literature data on SA-216 Grade WCC carbon steels were fitted with a Larson-Miller parameter, 

18 as shown in Figure A-23b. In equation form the Larson-Miller plot is given by

19

20 (A0)

21

22 where stress σ is in ksi and the time to rupture tR in h is given by

23

24 , (A0)

25

26 where T = temperature in K. Figure A-23b also shows the parameter values for ±95 percent

27 confidence limits. The predicted times to rupture are plotted against test rupture times in 

28 Figure A-24a, which shows that the bulk of the combined data can be predicted to within a 

29 factor of 4.9. The steady state creep ductility of SA-216 is 2–5 percent at 500 degrees C

30 (932 degrees F), but increases with temperature to greater than 10 percent at 650 and 

31 800 degrees C (1,202 and 1,472 degrees F) (Figure A-24b).

32
A-21

Table A-9 Summary of Creep Data for SA 516 Grade 70 Carbon Steel 1

2

Specimen 

No.

Temperature °C (°F)Stress

ksi (MPa)

Rupture 

Time (h)

% Elongation%

RA

Minimum 

Creep Rate 

(%/h)

6-4 500 (932) 40 (276) 4.70 17.20 37.40 1.01

6-5 500 (932) 40 (276) 5.90 21.00 42.00 0.81

6-10 500 (932) 38 (262) 8.70 24.90 44.00 0.49

6-13 500 (932) 38 (262) 7.40 16.20 41.50 0.50

6-14 500 (932) 35 (241) 15.90 22.20 44.00 0.17

6-15 500 (932) 35 (241) 11.10 23.50 47.00 0.18

6-6 650 (1202) 18.5 (128) 0.20 60.90 77.50 -

6-7 650 (1202) 18.5 (128) 0.10 69.90 79.30 -

6-11 650 (1202) 15.5 (107) 0.50 69.40 77.00 28.23

6-16 650 (1202) 14 (97) 1.60 59.50 78.00 5.36

6-17 650 (1202) 12 (83) 3.60 65.00 77.60 3.21

6-19 650 (1202) 10 (69) 9.10 76.70 17.00 1.02

6-8 800 (1472) 9 (62) 0.20 42.80 41.50 -

6-9 800 (1472) 9 (62) 0.10 43.70 29.90 -

6-12 800 (1472) 7 (48) 0.60 45.90 16.40 36.40

6-18 800 (1472) 5 (34) 3.30 48.50 26.90 4.81

6-20 800 (1472) 5 (34) 3.10 46.20 - 5.72

6-21 800 (1472) 4 (28) 6.40 50.10 12.80 1.94

3
A-22

(a) (b)

(c)

.

1

2 Figure A-22 Creep curves for SA-516 Grade 70 carbon steel at (a) 500, (b) 650, and 

3 (c) 800 °C

4
A-23

Table A-10 Creep Rate Parameters for Combined ANL and Literature Data on 1

SA-216 Grade 70 and SA-216 Grade WCC Carbon Steels 2

3 Mean and ±95% confidence bounds at various temperatures

4 (stress in ksi and creep rate in 1/h).

5

T (°C) m n A (mean) A(-95%) A (+95%)

300 0 5.439 4.844E-19 1.615E-19 1.453E-18

400 0 5.439 8.654E-15 2.885E-15 2.596E-14

500 0 5.439 1.228E-11 4.092E-12 3.683E-11

550 0 5.439 2.387E-10 7.955E-11 7.159E-10

600 0 5.439 3.303E-09 1.101E-09 9.907E-09

650 0 5.439 3.438E-08 1.146E-08 1.031E-07

700 0 5.439 2.813E-07 9.377E-08 8.439E-07

750 0 5.439 1.874E-06 6.248E-07 5.623E-06

800 0 5.439 1.046E-05 3.488E-06 3.139E-05

850 0 5.439 5.013E-05 1.671E-05 1.504E-04

900 0 5.439 2.101E-04 7.004E-05 6.304E-04

950 0 5.439 7.834E-04 2.611E-04 2.350E-03

1,000 0 5.439 2.634E-03 8.779E-04 7.901E-03

6

(a) (b)

7

8 Figure A-23(a) Predicted vs. observed creep rates

9 Figure A-23(b) Larson-Miller plot for time to stress rupture of SA-516 Grade 70 and 

10 SA-216 Grade WCC

11
A-24

(a) (b)

1

2 Figure A-24(a) Predicted vs. observed time to stress rupture

3 Figure A-24(b) Variation of steady state ductility with stress and temperature of 

4 carbon steels

5

6 SA 240 Grade 316/SA 516 Grade 70 Weldment

7

8 A summary of the creep tests conducted on SA-240 stainless steel/SA-516 carbon steel is given 

9 in Table A-11. Since the strain distribution in the gauge length is nonuniform, the strain and 

10 minimum creep rate data reported in the table represent average values over the entire gauge 

11 length, with significantly more strain occurring in the carbon steel than in the stainless steel half. 

12 The primary purpose of these tests was to determine the loss of ductility and time to rupture of 

13 the weldment relative to the base metals. At 700 degrees C (1,292 degrees F), most of the 

14 failure occurred in the weaker SA-516 carbon steel by ductile necking away from the weld. 

15 Even in the single specimen (6W-14) in which failure occurred at the weld interface, necking is 

16 visible in the carbon steel away from the weld. At 800 degrees C (1,472 degrees F), all of the 

17 failure occurred by shear at the SA-516/weld interface at a significantly reduced ductility. At 900 

18 and 1,000 degrees C (1,652 and 1,832 degrees F), failure occurred in the middle of the weld 

19 either by shear or flat fracture and the overall ductility of the specimens was significantly 

20 reduced compared to that at 700 degrees C (1,292 degrees F). Necking was not observed in 

21 any of the tests conducted at 800–1,000 degrees C (1,472–1,832 degrees F).

22
A-25

Table A-11 Summary of Creep Data for SA 240 Grade 316 /SA 516 Grade 70 Weldment 1

2

Spec. 

No.

Temp 

°C (°F)

Stress 

ksi 

(MPa)

Rupture 

Time 

(h)

% Elongation% RA Min. 

Creep 

Rate 

(%/h)

Failure Location

6W-6 700 (1292) 13 (90) 0.2 29.2 77.8 3.07 necking of SA 516

6W-7 700 (1292) 13 (90) 0.1 29.1 81.0 5.16 necking of SA 516

6W-8 700 (1292) 17 (117) F.O.L. 24.5 65.9 1.61 necking of SA 516

6W-9 700 (1292) 17 (117) F.O.L. 21.8 76.3 1.28 necking of SA 516

6W-14 700 (1292) 10 (69) 0.6 22.4 52.6 0.36

shear at weld 

(SA 516 side)

6W-17 700 (1292) 6 (41) 9.0 29.0 69.5 necking of SA 516

6W-10 800 (1472) 8 (55) 0.2 8.3 14.3

shear at weld 

(SA 516 side)

6W-11 800 (1472) 8 (55) 0.2 7.2 14.4

shear at weld 

(SA 516 side)

6W-12 800 (1472) 10 (69) F.O.L. 5.4 8.4

shear at weld 

(SA 516 side)

6W-13 800 (1472) 10 (69) F.O.L. 7.5 12.9 1.29

shear at weld 

(SA 516 side)

6W-15 800 (1472) 4 (28) 2.5 4.5 13.2

shear at weld 

(SA 516 side)

6W-18 800 (1472) 2 (14) 30.3 6.0 ***

shear at weld 

(SA 516 side)

6W-19 900 (1472) 2 (14) 33.1 8.4 *** Flat fracture at weld

6W-20 900 (1472) 1 (7) 100** -

Flat fracture at weld 

(middle)

6W-16 1000 (1832) 2 (14) 7.0 8.1 14.2

Shear at weld

(middle)

6W-21 1000 (1832) 1 37.2 6.0 6.6

Flat fracture at weld 

(middle)

3

B-1

1 APPENDIX B

2

3 C-SGTR CALCULATOR

4

5

6 Software referred to as the C-SGTR calculator has been developed to support the work in this 

7 report. The calculator is used to estimate failure times and leak sizes of steam generator (SG)

8 tubes with different types of flaws. The software also has built in models for failure of HL (HL)

9 and surge line (SL) because of creep rupture failure mechanism and estimates failure times and 

10 probabilities of HL and surge line. The scope of the models currently includes new SG tube 

11 materials and the associated property data for both thermally treated Inconel 600 and 690 

12 (TT600 and TT690).

13

14 The calculator user manual and basis report are stored in Reference B-1. The same document 

15 also contains results of a review of the basis report by the Argonne National Laboratory (ANL).

16

17 It is emphasized that the software does not directly calculate a “C-SGTR probability.” This 

18 probability can be calculated after a case run by using the information from two output files, and 

19 the probabilities assigned to the set of input flaws. However, the user can observe from the 

20 output files whether the HL (or surge line) fails before a specified integrated tube leak size 

21 (defined as critical leak size in the report) is reached or not.

22

23 Section B-1 provides a short discussion of software input-output with an example case. Section

24 B-2 has comments on the uncertainty modeling. For more information, refer to Reference B-1.

25

26 B.1 Example Case

27

28 This software is designed to support the probabilistic risk assessments that address the risk 

29 associated with steam generator tube rupture (SGTR) scenarios; as an initiator, as a 

30 consequence of plant transients (design-basis accident scenarios), and because of core 

31 damage sequences (consequential SGTR). Plant-specific material properties, plant-specific SG 

32 tube flaw data, and scenario specific thermal-hydraulic (TH) input are required for use of this 

33 software to support PRA analysis.

34

35 An event sequence (scenario) can be defined as the input to the calculator. To define a 

36 scenario, the calculator expects five input files:

37

38 (1) plant information file

39 (2) time, temperature, pressure profile of the SG tubes, SL, and HL (TH) file

40 (3) SG tube flaws file

41 (4) material properties file (e.g., TT600 or TT690)

42 (5) calculation parameters file

43

44 The underlying calculations made are deterministic. The calculation parameters file is used to 

45 apply a probability and to sample the information that comes from the flaw and TH files. This 

46 provides probabilistic results. For those characteristics of the scenario that go into the 

47 calculations without uncertainty parameters, no sampling is done; thus they do not contribute to 

48 the probability calculations.

49
B-2

1 The software produces three output files named such as:

2

3 (1) CumulativeLeakAreaFile-XXXX.txt

4 (2) CSGTRProbabilityFile-XXXX.txt

5 (3) IntermediateFile-TH-XXXX.txt

6

7 An example Table B-1 of some key inputs and outputs is given in this appendix, with 

8 annotations. Additional example cases can be found in the later appendices of this report.

9

10 The output in Table B-1 allows for the calculation of a “margin,” which is defined as the number 

11 of minutes between the failure of HL (or SL, whichever occurs first) and the failure of more than 

one-tube guillotine break equivalent of SG tubes (6 square centimeters (cm2 12 ) [0.93 square inch

(in.2 13 )] for this example). For example, from Table B-1, a margin M of

14

15 M = 221 – 235 = -14 minutes

16

17 can be determined. A negative margin is favorable since further tube failures and release to the 

18 atmosphere of fission products would be limited or avoided.

19

20 Some noteworthy aspects of the software are listed below:

21

22 • Axial, circumferential and wear type SG tube flaws are modeled.

23

24 • HL and surge line failure probabilities are also estimated. Caution: in this estimation, 

25 the effect of SG tube failures on the HL and SL failures is not considered. Each of the 

26 three types of failures, HL, SL, and SG tube are calculated independent of each other.

27

28 • Two types of correlations are used for estimating SG tube leakage; one for low 

29 temperature (e.g., much lower than creep rupture region), but potentially high pressure 

30 cases; the other for temperatures in the creep rupture range. The threshold temperature 

31 for switchover to creep rupture correlation is a software input: the default is set to 

32 600 degrees C (1,112 degrees F) (ThresholdCreepRupture 600.0, in the calculation 

33 parameters file).

34

35 Comments for Table B-1:

36

37 • Columns A, F-J are input. Columns B-E are output.

38

• If one tube has a guillotine break, the total leak area would be 6 cm2 [0.93 in.2 39 ].

40

41 • At 238 minutes into this core damage event, the total expected leak area from multiple 

partial breaks is 28 cm2 (4.34 in.

2 42 ), which is equivalent to about 5 guillotine tube breaks.

43

44 • At 95-percent confidence level, total expected leak area from multiple partial breaks is 

37 cm2

,(5.7 in.

2 45 ), which is equivalent to about 6 guillotine tube breaks.

46

47 • HL fails around 220 minutes.

48

49 • Surge line failure probability is 68 percent at 238 minutes.

50
B-3

1 • HL and surge line failure probabilities are calculated without considering SG tube 

failures. A substantial failure of SG tubes (greater than 6 cm2 [0.93 in.

2 2 ] total leakage 

3 area) would reduce the RCS pressure and could delay HL and surge line failures.

4

5 • In this example, multiple wear flaws with different sizes and depth are postulated.

6

7 • The tube material is thermally treated Alloy 600.

8

9 • The event is core damage from station blackout with no recovery and early loss of 

10 turbine driven auxiliary feedwater (AFW) pump in a PWR.

11

12 B.2 Uncertainty Parameters

13

14 The software uses a set of input uncertainty parameters to sample from distributions that apply 

15 to various key inputs. These inputs and their uncertainty parameters are defined in Table A-2 of 

16 Reference B-1. This table is titled “Statistical parameters in the Calculation.Properties Input file. 

17 If an input parameter is not in this table, then the software does not sample for that parameters, 

18 but uses the expected value provided.

19

20 B.3 References

21

22 B-1. Information Systems Laboratories, “Technical Basis and Software User Guide for SGTR 

23 Probability,” ISL-NSAD-TR-10-13, December 2014, Agencywide Documents Access and 

24 Management System (ADAMS) Accession No. ML15054A495.
B-4

1

Table B-1 Example Input-Output (Condensed and Processed)

A B C D E F G H 

Time 

(min)

Amean

(cm2)

A0.95 

(cm sq) HL % Surge Line %

Surge 

Line 

Temp C

HL Temp 

C

Average 

Hot Tube 

Temp C

A

210 0.027 0.18 0.000 0.000 621 713 574 

210 0.027 0.18 0.000 0.000 617 715 581 

211 0.030 0.18 0.000 0.000 619 722 588 

212 0.034 0.18 0.002 0.000 622 730 593 

213 0.037 0.19 0.013 0.000 626 738 597 

214 0.039 0.20 0.041 0.000 629 746 601 

215 0.039 0.20 0.104 0.000 633 755 606 

216 0.039 0.20 0.267 0.000 637 764 611 

217 0.039 0.20 0.511 0.000 641 772 615 

218 0.039 0.20 0.795 0.000 672 786 613 

219 0.039 0.20 0.884 0.000 661 791 619 

219 0.039 0.20 0.945 0.000 661 797 626 

220 0.039 0.20 0.987 0.000 666 809 634 

221 0.039 0.20 1.000 0.000 671 822 640 

222 0.039 0.20 1.000 0.000 678 836 646 

223 0.039 0.20 1.000 0.000 685 854 654 

224 0.039 0.20 1.000 0.000 716 868 648 

224 0.039 0.20 1.000 0.000 711 879 658 

225 0.039 0.20 1.000 0.000 727 925 673 

225 0.039 0.20 1.000 0.000 855 1057 679 

226 0.039 0.20 1.000 0.000 826 1097 710 

226 0.043 0.20 1.000 0.000 839 1137 725 

227 0.051 0.68 1.000 0.000 855 1162 728 

227 0.061 0.83 1.000 0.000 916 1193 719 
B-5

Table B-1 Example Input-Output (Condensed and Processed)

A B C D E F G H 

Time 

(min)

Amean

(cm2)

A0.95 

(cm sq) HL % Surge Line %

Surge 

Line 

Temp C

HL Temp 

C

Average 

Hot Tube 

Temp C

A

228 0.082 0.89 1.000 0.000 905 1209 733 

228 0.119 0.90 1.000 0.000 908 1,233 745 

229 0.186 0.91 1.000 0.002 917 1,261 756 

229 0.267 0.91 1.000 0.006 925 1,281 764 

230 0.353 0.91 1.000 0.025 954 1,304 772 

230 0.423 0.91 1.000 0.067 973 1,314 766 

231 0.480 0.91 1.000 0.100 965 1,319 776 

232 0.589 0.91 1.000 0.183 969 1,332 787 

233 1.080 3.55 1.000 0.312 977 1,343 797 

235 3.462 7.36 1.000 0.430 985 1,354 808 

236 11.535 17.04 1.000 0.571 994 1,368 819 

238 28.206 36.86 1.000 0.681 1002 1,374 827 

1

C-1

1 APPENDIX C

2

3 CONSIDERATIONS FOR PRESSURE-INDUCED C-SGTR

4

5

6 C.1 Introduction

7

8 In the past studies (like NUREG-1570), two types of potential consequential steam generator 

9 tube rupture (C-SGTR) challenges were discussed:

10

11 Type-I. temperature-induced C-SGTR (mainly driven by creep rupture at higher 

12 temperatures) and

13

14 Type-II. pressure-induced C-SGTR (mainly driven by the pressure difference across the 

15 SG tube boundary, rather than the temperature).

16

17 Later studies, benefiting from the probabilistic risk assessments (PRAs), identified 

18 risk-significant core damage sequences, such as Unrecovered Station Blackout, to be Type-I 

19 challenges. Thus, the analyses were focused on Type-I C-SGTR challenges with good reason. 

20 Note that the Type-I challenges thus analyzed occur after core damage, which is the cause of 

21 the high steam generator (SG) tube temperatures. Type-I C-SGTRs do not increase the plant 

22 core damage frequency (CDF), but may affect the fission product release.

23

24 In this section, Type-II C-SGTR challenges are discussed. The discussion does not claim to be 

25 exhaustive. However, the insights discussed and overall results are applicable in a larger 

26 context, since the assumptions used are prudently conservative.

27

28 Initiating events cause Type-II C-SGTR challenges. No core damage exists, until additional 

29 failures occur as the event proceeds. In earlier studies, it appeared that the main concern for 

30 Type-II C-SGTRs was that it could complicate the original event in progress, and may affect the 

31 operator response and operator success probability. Type-II C-SGTRs could increase the 

32 already calculated plant CDF, if they are added to a PRA model which does not originally 

33 consider them.

34

35 Potential pressure-induced C-SGTRs, following an initiating event and before core damage, are 

36 of interest for some initiating events, including large secondary side breaks (SSB), spurious 

37 opening of multiple turbine bypass valves and anticipated transients without scram (ATWS)

38 scenarios. The initiating events other than ATWS are collectively named as L-SSBs. In these 

39 initiating events, a pressure spike in the primary side, or a sudden pressure drop on the 

40 secondary, or a combination of both could provide high pressure differences across the SG tube 

41 boundary.

42

43 In PRA studies, once the reactor coolant system (RCS) pressure reaches 22–22.7 megapascals 

44 (MPa) (3,200–3,300 pounds per square in [psi]) (design pressure of the primary side), core 

45 damage is postulated (see ATWS event tree modeling further down in this section). Assuming 

46 that the operating primary and secondary-side pressure difference is about 6.9 MPa (1,000 psi), 

47 the range of interest for analysis of Type-II C-SGTR PRA scenarios is 6.9–33.7 MPa 

48 (1,000–3,300 psi) across the tube boundary.

49
C-2

1 For a pristine tube (no flaw) made of Alloy 600, the burst pressure varies as a function of tube 

2 temperature. It is typically about 65 MPa (9.4 kilopounds per square inch [ksi]) at room 

3 temperature and about 58.7 MPa (8.5 ksi) at 500 degrees C (932 degrees F). Therefore, there 

4 is generally no concern about the burst probability of a flawless tube due to the various pressure 

5 induced scenarios identified by probabilistic risk assessments. However, the tube failure and 

6 burst pressure drops when there are one or more flaws on the tube wall. There are many 

7 different degradation mechanisms that could generate flaws. As the degradation mechanism for 

8 a type of flaw is better understood, indebted to information generated from the surveillance 

9 program in operating reactors, enhancements are identified and implemented to limit the 

10 number of flaws from that degradation mechanism. This in the past has resulted in changes in 

11 plant operational practices, introduction of new tube materials, and other design modifications 

12 that have been implemented to alleviate the identified issues. In fact, many plants have already 

13 replaced their SGs with either Inconel 690 or thermally treated Inconel 600, improved their 

14 surveillance program, and have enhanced controlling their water chemistry. According to a 

15 licensee event report (LER) search; there have been no SG tube leaks in the past 6 years since 

the 2004 event at Palo Verde, excluding the 2012 SONGS 1 16 event.

17

18 Temperature-induced correlations, which are perfectly adequate for Type-I challenges, are 

19 deemed to underestimate the magnitude of the potential failure of a flaw when the SG tubes are 

20 subjected to relatively low (e.g., at the order of normal operating) temperatures with high 

21 pressure differences across the tube boundary (from the RCS side to the secondary side). At 

22 temperatures well below the creep-rupture range, The C-SGTR calculator uses the 

23 pressure-induced correlations, to accommodate the effect of Type-II challenges. The software 

24 switches to thermally induced correlations when a user specified transition temperature is 

25 reached in the scenario of interest. The region of temperature where creep rupture starts to 

26 become effective is 600–800 degrees C (1,112–1,472 degrees F). The value of 600 degrees C 

27 (1,112 degrees F) is used as the transition between the pressure-induced to creep-rupture tube 

28 failure models. The default user input for the transition temperature is given as 600 degrees C

29 (1,112 degrees F).

30

31 C.2 Events of Interest

32

33 Some initiating event categories that included both in design basis accident analyses in PRAs 

34 are candidates for potentially causing consequential Type-2 SG tube failures. These failures 

35 may be designated as “leaks’ (less than the equivalent leak area of a single guillotine tube 

36 break). For most of the leak sizes, the RCS inventory can be maintained by the normal capacity 

37 of the CVS system. Other larger failures can be designated as leakage from one or more tubes, 

38 with a total leak area equal or greater than the equivalent size of one-tube guillotine break. 

39 Such larger failures will be designated as C-SGTR for the purposes of the discussion in this 

40 section. In such magnitude of failures (in the small LOCA range), further injection capacity of 

41 the safety injection systems would be needed to maintain the RCS inventory. Also, such 

42 failures would have caused reactor trip by themselves, if the originating initiating event did not 

43 already cause the reactor or turbine trip.

44

 1 As identified in the San Onofre Nuclear Generating Stationroot cause analysis, the cause of the steam generator 

 degradation was tube-to-tube wear caused by in-plane fluid-elastic instability of the tube ubends. A design error 

 resulted in the actual steam generators having more severe thermal-hydraulic conditions than expected, which 

 contributed, along with other factors, to the rapid steam generator tube wall degradation.
C-3

1 The following initiating events that can potentially create pressure differences considerably 

2 exceeding normal operating pressure across the SG tube boundaries are discussed in this 

3 section:

4

5 (1) ATWS

6 (2) Large SSB (secondary side break)

7

8 There are several other scenarios that could cause pressure differences across SG tubes 

9 exceeding normal operating pressure. SBO scenarios would demand frequent lifting of main 

10 steam safety valves (MSSVs), which could follow with one of them sticking open. Such 

11 scenarios are bounded for pressure induced part under Large SSB with significantly smaller 

12 occurrence probabilities.

13

14 C.2.1 ATWS Event

15

16 Given the failure of the reactor protection system to trip the reactor, the RCS system pressure is 

17 questioned to ensure that the reactor vessel is not pressurized greater than the design 

18 pressure. If the RCS pressure exceeds design pressure, core damage is assumed.

19

20 The ATWS event tree has the following events arranged in the approximate order in which they 

21 would be expected to occur after a failure to scram the reactor given a transient event. Refer to 

22 Figure C-1 for a partial ATWS event tree developed to discuss the Type-II C-SGTR issues. A

23 transient event is used in this example as the initiator; other initiating events of lesser 

24 frequencies could also be followed by ATWS scenarios.

25

26 1. IE-TRANS

27

28 The first top event refers to the initiating event that creates the demand for a reactor trip (in this 

29 case, a transient).

30

31 2. RPS

32

33 This top event signifies that a transient occurred and the reactor protection system failed to trip 

34 the reactor. Credit can be taken for manual trip in a short time, say within a minute, but not 

35 before the pressure peak has been realized. There are several options for manual trip which 

36 can be effective for all ATWS scenarios except those caused by mechanical failures of sufficient 

37 number of rods to inset. There is high likelihood of success for the operators to perform manual 

38 scram after observing compelling alarms and signals in the main control room.

39

40 3. PR-REL

41

42 This top event represents success or failure of the reactor pressure vessel. Success implies 

43 that the ATWS event did not increase the RCS pressure above the reactor vessel design 

44 pressure boundary. Success also implies that the RCS relief valves opened to relieve RCS 

45 pressure.

46

47 Success requires that the RCS pressure be limited to less than 22 MPa (3,200 psi). This 

48 implies favorable moderator temperature coefficient. Above this pressure, unpredictable 

49 pressure boundary and component failures are assumed to occur. Success also requires 

50 three-of-three SRVs and two-of-two power-operated relief valves (PORVs) to open and relieve 

51 RCS pressure.
C-4

1

2 Event Tree Nodes 4 and 5 are intended to help calculate the probability of getting a leak or a 

3 C-SGTR consequence, given that ATWS pressure relief was successful, but the pressure 

4 difference across SG tubes exceeded the normal operational values; namely it was in the range 

5 of ΔP = (6.89–20.6 MPa (1,000–3,300 psi). The upper values of this pressure range could only 

6 be reached if the secondary side is also depressurized. That scenario would be highly unlikely, 

7 since the heat removal is done through SGs with auxiliary feedwater (AFW) pumps operating. 

8 The highest ΔP of interest is therefore 15.2 MPa (2,200 psi) unless failure of AFW is also 

9 assumed.
C-5

C-5

IE-TRANS RPS PR-REL FL-DPT P-L/R CCDP En

1 2 3 4 5 6 7 

Success 1 No ATW

Small 2 No lea

Yes. 2,200 < P< 3,300 Medium 3 CD-Le

Occurs

Large 4 CD-C-

Fails

No. P >3,300 5 CD

1

Figure C-1 ATWS event tree top events to address Type-II C-SGTR 2

3
C-6

1 The nature of these two event three nodes is dictated by how the conditional C-SGTR 

2 probabilities are calculated for Type-II challenges and how the results are binned. Appendix F 

3 provides detail discussion of these calculations which are also summarized in Section C-3.

4

5 See Section C-3 for estimation of some values for these event tree nodes.

6

7 4. FL-DPT

8

9 This node represents the probability of getting a “small,” or a “medium,” or a “large” flaw depth, 

10 given a flaw is originated since the last refueling outage. Any flaws of depth 40 percent or less 

11 are assumed identified and their tubes are plugged, if they have occurred before the last 

12 outage.

13

14 5. P-L/R

15

16 This node represents the probability of leak or C-SGTR given that a flaw with depth specified in 

17 the FL-DPT node exists. No credit is taken for this event tree node in the current calculations 

18 (e.g., set equal to 1.0 when the critical size Ac is reached).

19

20 6. CCDP

21

22 This is the conditional core damage probability (CCDP) assigned to the sequence defined so far 

23 with Nodes 1 through 5 in the event tree. This CCDP represents the additional failures needed 

24 to reach core damage end state, given that the sequence in question has progressed to the 

25 point defined by Nodes 1 through 5.

26

27 The event tree Sequences 3 and 4 in column 7 of the figure are the new potential core damage 

28 sequences associated with the Type-II C-SGTR challenges. Sequence 4 represents a 

29 sequence with a C-SGTR end state, in which an integrated tube break size equivalent to a full 

30 guillotine break of one or more tubes is created by the Type-II challenge. The CCDP for this 

31 sequence is estimated by crediting manual scram but failing the emergency boration (EB). It is 

32 conservatively assumed that the operation of EB cannot be ensured post C-SGTR, so a 

33 bounding failure rate of one is assigned for EB. Sequence 3 represents integrated tube break 

34 sizes less than the above, in which CVCS would be able to make up the RCS inventory.

35

36 Using the values in Section C-3, Sequences 3 and 4 are quantified (their CDF values are 

37 estimated), as shown in Figure C-2.
C-7

IE-TRANS RPS PR-REL FL-DPT P-L/R CCDP End Sta

1 2 3 4 5 6 7 8 

Success 1 No ATW

1.0

Small 2 No leak

0.95

Yes. 2,200 < P < 3,300 Medium 3 CD-Leak 

Occurs 0.95 0.04 1 1E-03

1 Large 4 CD-C-SG

Fails 0.01 1 0.1

5E-06

No. P >3,300 5 CD

0.05

Figure C-2 ATWS event tree top events to address Type-II C-SGTR—example quantifica
C-8

1 C.2.2 Large Secondary-Side Break Event

2

3 Given an initiating event like a large steam line break or stuck open secondary-side valves, 

4 which are collectively named as large secondary-side break events (L-SSB). It is possible that 

5 a large delta P across the SG tubes is generated. This pressure difference can be as high as 

6 15.9 MPa (2,300 psi), assuming that the secondary-side pressure drops to zero at once, and the 

7 primary pressure is at 15.9 MPa (2,300 psi) initially. It is expected that the primary pressure will 

8 start dropping due to the rapid cooldown.

9

10 Note that the size of the SSB, large, that would cause a significant increase in delta P across 

11 the SG tubes is not specified. In fact, a cursory examination of main steam line events reported 

12 in LERs point out that almost all such events have small steam leaks that do not even cause 

13 reactor trip, but eventually may end up with manual trip.

14

15 The L-SSB event tree has the following events arranged in the approximate order in which they 

16 would be expected to occur. Refer to Figure C-3 for a partial L-SSB event tree developed to 

17 discuss the Type-II C-SGTR issues.

18

IE-LSSB RPS Large dP FL-DPT P-L/R CCDP End State

1 2 3 4 5 6 7 8

No. dP = 1,000 psi 1 L-SLB

Success Small 2 No leak

Yes. dP = 2,300 

psi Medium 3 CD-Leak

Occurs

Large 4 CD-C-SGTR

Fails 5 ATWS

19

20 Figure C-3 L-SSB event tree top events to address Type-II C-SGTR

21

22 1. IE-L-SSB

23

24 The first top event refers to the initiating event of a large SSB, such as a large steam line break 

25 or stuck open secondary-side valves.

26

27 2. RPS

28

29 This top event addresses the need for a reactor trip. Failure of RPS would lead to an ATWS 

30 event, which is already discussed in the previous section and is not pursued here any further.

31
C-9

1 3. LARGE-DP

2

3 This top event addresses if a large pressure difference is created by the event across the SG 

4 tubes. For the purposes of this section, it is postulated that a large DP in the range of 

5 6.9–15.9 MPa (1,000–2,300 psi) is created by the nature of the event.

6

7 Event Tree Nodes 4 and 5 are intended to help calculate the probability of getting a leak or a 

8 C-SGTR consequence, given that a Type-II challenge is created.

9

10 See Section C.3 for estimation of some values for these event tree nodes.

11

12 4. FL-DPT

13

14 This node represents the probability of getting a “small,” or a “medium,” or a “large” flaw depth, 

15 given a flaw is originated since the last refueling outage. Any flaws of depth 40 percent or less 

16 are assumed identified and their tubes are plugged, if they have occurred before the last 

17 outage.

18

19 5. P-L/R

20

21 This node represents the probability of leak or C-SGTR given that a flaw with depth specified in 

22 the FL-DPT node exists. No credit is taken for this event tree node in the current calculations 

23 (e.g., set equal to 1.0 when the critical size Ac is reached).

24

25 6. CCDP

26

27 This is the CCDP assigned to the sequence defined so far with Node 1 through 5 in the event 

28 tree. This CCDP represents the additional failures needed to reach core damage end state, 

29 given that the sequence in question has progressed to the point defined by Nodes 1 through 5.

30

31 The event tree Sequences 3 and 4 in column 7 of the figure are the new potential core damage 

32 sequences associated with the Type-II C-SGTR challenges. Sequence 4 represents a 

33 sequence with a C-SGTR end state, in which an integrated tube break size equivalent to a full 

34 guillotine break of one or more tubes is created by the Type-II challenge. In such sequences 

35 the CCDP accounts for two additional possible failures. These are:

36

37 1. a higher probability for failure of HPI accounting for possible termination of injection if the 

38 operators do not recognize the occurrence of C-SGTR and

39

40 2. a higher probability to isolate the affected SG because main stem isolation valves

41 (MSIVs) might have failed to close as indicated by the initiator.

42

43 Sequence 3 represents integrated tube break sizes less than the above, in which CVCS would 

44 be able to make up the RCS inventory.

45

46 Using the values in Section C.3, Sequences 3 and 4 are quantified (their CDF values are 

47 estimated), as shown in Figure C-4.
C-10

IE-L-SSB RPS Large dP FL-DPT P-L/R CCDP End State CDF

1 2 3 4 5 6 7 8 9

No. dP = 1,000 psi 1 L-SSB

Success Small 2 No leak

1.0 0.95

Yes. dP = 2,300 

psi Medium 3 CD-Leak 1E-07

Occurs 1 0.04 1 1E-03

0.003 Large 4 CD-C-SGTR 4E-08

0.01 1 1.3E-03

Fails 5 ATWS

1E-05

1

2 Figure C-4 L-SSB event tree top events to address Type-II C-SGTR SGTR—

3 example quantification

4

5 C.3 Example for Estimating CDF from Type-II C-SGTR Challenges

6

7 The event tree models described in Figures C-1 and C-3 can be quantified to illustrate the 

8 model usage and the resulting C-SGTR frequencies. Although these C-SGTR frequencies are 

9 for illustration purposes and apply to the cases studied, their values are deemed to be 

10 representative of similar plant specific sequence, as long as the specific plant in question is not 

11 an outlier for the event tree nodes considered in the models.

12

13 The following data is used to quantify the two event trees mentioned above:

14

15 1. Initiating event frequency

16

17 For the ATWS event, a transient initiating event frequency of 1 per year is used. The current 

18 standardized plant analysis risk (SPAR) model frequency is 0.69 events per year. Other 

19 transients have considerably lower frequencies.

20

21 For the large secondary-side break event, a frequency of 0.001 per year is generally used. 

22 SPAR models do not have a frequency for such an event. Considering the more than 

23 3,000 plant years of PWR experience for U.S. domestic and similar French plants, postulating 

24 one such event per 1,000 years of operation is deemed reasonable for this illustration. The 

25 location of a steam line break (SLB) could be inside or outside the containment. Breaks inside 

26 the containment do not contribute to containment bypass probability, and breakers outside 

27 containment could be isolated via MSIVs. Bounding calculations in Section 7.4 also shows that 

28 the SLB scenarios followed by pressure induced C-SGTR do not contribute to large early 

29 release frequency (LERF) and has small contribution to CDF. Other events, however, such as 

30 spurious opening followed by sticking of MSSVs or SG PORVs could also contribute to transient 

31 with rapid secondary depressurization. It should be noted that the SG PORVs could be 

32 isolated; by manually closing the block valves if available. Although, the closure of block valves 

33 may not occur in time to prevent C-SGTR but it could be credited for isolation of the faulted SG 

34 after C-SGTR occurred. Considering these other events a bounding frequency of 3E-3/yr from 

35 information available in NUREG/CR-6928 is assigned to this class of initiators.
C-11

1

2 2. RPS success/failure

3

4 The failure of the RPS system, from all failure mechanisms, is assigned a probability of 5E-05 

5 per demand. This includes potential credit for the operator action to trip the reactor early on 

6 based on the early symptoms of transient and before the scram signal is initiated. The early 

7 symptoms generally include applicable alarms and cues that are observed in the main control 

8 room. SPAR model probability for this failure is generally lower than this value.

9

10 3. Failure of RCS pressure relief (thus avoiding high delta P across the SG tube 

11 boundary)

12

13 For L-SSB, a failure probability of 1 is used, since the nature of the initiating event causes the 

14 high delta P.

15

16 4. and 5. Probability of having at least one (large) SG tube subject to C-SGTR or leak, and 

17 Probability of C-SGTR or leak, given such a tube is present and high delta occurs

18

19 These probabilities are calculated for the example case discussed in Appendix F. They are 

20 summarized in Sections F-2 for C-SGTR and Section F-3 for SGTR-Leak of Appendix F. The 

21 highest probability for C-SGTR and SGTR-Leak for ATWS or L-SSB scenarios is estimated to 

22 be 0.01 and 0.043 respectively. This is the probability estimated based on the representative 

23 Westinghouse plant at the cycle 15 of operation.

24

25 6. Sequence CCDP for C-SGTR (or for SG leak sequence), given high delta P and 

26 large flaws

27

28 For ATWS event, a screening CCDP of 0.1 is used, given C-SGTR.

29

30 The CCDP value for L-SSB events given C-SGTR is taken as 1.3E-03. This value is an order of 

magnitude higher than those in SPAR models (with SGTR event CCDPs in the range of 10-4 31

and 10-5 32 ). This order of magnitude increase in CCDP is postulated to allow for presumed 

33 complications in the sequence, potentially increasing operator failure probabilities.

34

35 For an SG leak sequence, which is considerably more benign and can be coped with CVCS 

36 system, a slightly lower CCDP of 1E-03 is used.

37

38 These values are placed in the ET model to obtain C-SGTR (and SG leak) sequence 

39 frequencies for the events studied. The quantification results are shown in Figures C-2 and C-4.

40

41 These results are deemed to be prudently conservative. See Section C.4 for conclusions about 

42 Type-II challenges to the SG tubes based on these illustrative examples.

43

44
C-12

1 C.4 Conclusions

2

3 The pressure-induced C-SGTR challenges (Type-II C-SGTR challenges) are examined in this 

4 section by referring to specific examples. The examples cover two main Type-II challenge 

5 sources:

6

7 (1) Sudden pressure spike in the primary side, exemplified by an ATWS event.

8

9 (2) Sudden pressure drop on the secondary side, exemplified by large secondary-side 

10 breaks (L-SSB).

11

12 By referring to Figure C-2, one concludes that C-SGTR frequencies for ATWS events are not 

13 risk significant for the cases studied in this example. Furthermore, it is deemed that this 

14 conclusion may be expanded to state that C-SGTR because of ATWS events are not risk 

15 significant to PWRs, unless a specific plant characteristic is not covered (or bounded) by the 

16 assumptions used in the ATWS case of this section.

17

18 As for the L-SSB event, referring to Figure C-4, one observes that with the prudently 

19 conservative assumptions used, the C-SGTR CDF frequency is at the order of 4E-08/year. For 

20 example, for a PWR with a total CDF of 2E-05 per year and LERF of 1E-06, the additional CDF 

21 and LERF would add about 2 percent to CDF and 40 percent to LERF. The additional CDF 

22 contribution is low, and the additional LERF contribution is about 4 percent. The actual LERF 

23 contribution may be even lower if credit is given for severe-accident management guidelines

24 (SAMGs). However, there is also possible core damage (CD) contribution from those 

25 sequences defined with the end state “CD-leak.” A simple estimation of CD frequency of such 

26 lesser magnitude SG tube leaks is more dependent on plant specific modeling and thus is more 

27 elusive.

28

29 Further fine tuning to reduce some of the conservativeness may lower this value, but then it 

30 could reduce the generic applicability of the conclusions, considering large uncertainties and 

31 variations. For example, one obvious possibility of reduction is to recognize that the “length” of 

32 a typical flaw is about 1.1 centimeter, or 0.43 inch (for the TT600 and TT690 flaw distributions 

33 discussed in Appendices B and C). According to the models in the C-SGTR calculator, such a 

34 flaw cannot produce more than a leak, and cannot reach the critical size of 6 square centimeters

35 (0.93 square inch) assigned to declare a tube failure as a C-SGTR. This could reduce the 

36 above CDF frequency for L-SSB CDF sequence by a factor of 10. But, on the other hand, it 

37 would require consideration of multiple smaller tube flaws whose integrated failure area could 

38 reach or exceed the critical size. To avoid an explosion of analysis cases and details, further 

39 attempts to reduce the above bounding value at this time are not carried out or are 

40 recommended.
D-1

1

2 APPENDIX D

3

4 UNCERTAINTY AND SENSITIVITY ANALYSIS

5

6

7 The basic tool used to generate steam generator (SG) tube leak area estimates, HL (HL) and 

8 surge line (SL) failure probabilities is the consequential steam generator tube rupture (C-SGTR)

9 calculator. The correlations used for these calculations are basically deterministic and would 

10 provide nonprobabilistic results unless uncertainty distributions are assigned to certain input 

11 parameters. The calculator samples the input parameters for which uncertainty distributions are 

12 specified and generates N cases (trials) for each of which, outputs like integrated tube leak 

13 area (A), HL and surge line failure times are calculated. These results are then ordered to 

14 provide estimates for Am, A95, etc. In such estimates, no underlying distribution is assumed. No 

15 sampling is done for all parameters for which distributions are not specified.

16

17 A set of sensitivity analysis designed to evaluate the impact of changing the main assumptions 

18 or input data in the base case evaluations were also performed. The results of these sensitivity 

19 analyses could also support development of the Level 2 PRA models. A detailed discussion on 

20 the approach, assumptions, case runs, and the results of the analyses is provided in this 

21 appendix for both the selected Westinghouse (W) and the Combustion Engineering (CE) plants.

22

23 D.1 Sensitivity Analyses for the Selected W Plant

24

25 The following sensitivity analyses were performed for the representative W plant. The measure 

26 of comparison used for these sensitivity analyses was based on the time difference between the 

27 time when HL failure is imminent and the time when C-SGTR is expected. The ratio of this time 

28 margin over the base time margin is used as a means of qualitatively ranking the impact of 

29 sensitivity results.

30

31 D.1.1 Base Case Evaluation and the Uncertainties Calculated

32

33 For the purposes of this uncertainty discussion in this section, the following base case is used:

34

35 (1) ZION with thermally treated Inconel 600 SG tubes;

36

37 (2) Wnewbase; station blackout (SBO) with early failure of turbine driven auxiliary feed 

38 water pump without recovery of alternating current power, resulting in core damage is 

39 considered. The input file has provides the relevant temperatures and pressure for a 

40 time window of 300 minutes, starting from the reactor trip and SBO. Figure D-1 

41 summarizes the main parameters of the base case. Note that the secondary side is 

42 depressurized.

43

44 (3) A wear type flaw of 4 centimeters (cm) (1.6 inches [in.]) in “length” and 40 percent in 

45 depth was considered. Such a flaw would require tube plugging when identified at the 

46 end of the cycle.

47

48 (4) 2,000 trials were used with the calculator.

49
D-2

(5) “Critical Area” (Ac) is taken as 6 square centimeters (cm2

) (0.93 square inch [in.2 1 ]), which 

2 is equivalent to a guillotine break of a single tube in this SG. The above flaw is capable 

3 of generating an equivalent leak area to Ac.

4

5 (6) In this sequence, the main driver of the SG tube failure is the creep-rupture failure, 

6 induced by the high temperature at the flaw location.

7

8

9

10 Figure D-1 Temperature and pressure profile of the base case (at the flaw location)

11

12 The analyses associated with such a sequence have already been discussed in detail in this 

13 report. Here, the focus is mainly on the uncertainty aspects of the results.

14

15 When the above case is studied, two types of output of interest are generated:

16

17 (1) Estimates of integrated SG Tube Leak Area (A)

18

19 For this output, Am, A05, A50, A70, A95, and Asd (standard deviation) are reported. Figure D-2 

20 shows the output. Note that, although the time window of the sequence is 300 minutes, the 

21 tube failure develops in a relatively narrow time window of 230–240 minutes into the event. This 

22 is the time window shown in the figure. The relevant input-output data is shown in Table D-1.

0

500

1000

1500

2000

2500

3000

0.00 50.00 100.00 150.00 200.00 250.00 300.00 350.00

time in Minutes

delta P in psi

Avr. Hot Tube Temp C HT
D-3

725 C 766 C 819 C 845 C (Hot tube temp 

1

Figure D-2 Leak area of the base case (4 cm wear flaw with 40% depth) 2

-1

7

6

5

4

3

2

1

0

225 230 235 240 245

Time in minutes

Series1 Series2

Series3 Series4

Series5 Series6
D-4

1

Table D-1 Output for the Total Leak Area in the Base Case

Time in 

Minutes

Am in 

C A0.05 A0.25 A0.50 A0.75 A0.95 Asd

HL

Failure 

Prob.

Surge 

Line 

Failure 

Prob.

Avr. Hot 

Tube 

Temp C 

T

230 0.00 0.00 0.00 0.00 0.00 0.00 0.14 1 0.02 772 

230 0.00 0.00 0.00 0.00 0.00 0.00 0.14 1 0.07 766 

231 0.01 0.00 0.00 0.00 0.00 0.00 0.16 1 0.10 776 

232 0.08 0.00 0.00 0.00 0.00 0.00 0.65 1 0.19 787 

233 0.90 0.00 0.00 0.00 0.00 6.08 2.10 1 0.33 797 

235 2.88 0.00 0.00 3.51 5.94 6.11 2.71 1 0.47 808 

236 4.82 0.00 4.08 6.01 6.08 6.13 1.92 1 0.59 819 

238 5.71 3.17 5.92 6.06 6.1 6.14 0.97 1 0.70 827 

239 5.94 5.31 5.98 6.06 6.1 6.14 0.37 1 0.78 836 

241 5.96 5.34 6.00 6.06 6.1 6.14 0.29 1 0.86 845 

243 5.96 5.34 6.00 6.07 6.1 6.14 0.28 1 0.91 855 

245 5.96 5.34 6.00 6.07 6.1 6.14 0.29 1 0.94 862 

247 5.96 5.39 6.00 6.07 6.1 6.14 0.29 1 0.95 869 

250 5.96 5.39 6.00 6.07 6.1 6.14 0.30 1 0.97 879 

252 5.96 5.39 6.00 6.07 6.1 6.14 0.30 1 0.97 886 

255 5.96 5.39 6.00 6.07 6.1 6.14 0.29 1 0.98 894 

257 5.96 5.39 6.00 6.07 6.1 6.14 0.29 1 0.98 898 

260 5.96 5.39 6.00 6.07 6.1 6.14 0.29 1 0.99 907 

263 5.96 5.39 6.00 6.07 6.1 6.14 0.30 1 0.99 915 

266 5.96 5.39 6.00 6.07 6.1 6.14 0.29 1 0.99 922 

270 5.96 5.39 6.00 6.07 6.1 6.14 0.29 1 0.99 932 

273 5.97 5.39 6.00 6.07 6.1 6.14 0.28 1 0.99 941 

277 5.97 5.39 6.00 6.07 6.1 6.14 0.28 1 0.99 950 

280 5.97 5.39 6.00 6.07 6.1 6.14 0.29 1 0.99 958 

284 5.97 5.39 6.00 6.07 6.1 6.14 0.29 1 0.99 967 
D-5

Table D-1 Output for the Total Leak Area in the Base Case

Time in 

Minutes

Am in 

C A0.05 A0.25 A0.50 A0.75 A0.95 Asd

HL

Failure 

Prob.

Surge 

Line 

Failure 

Prob.

Avr. Hot 

Tube 

Temp C 

T

288 5.97 5.39 6.00 6.07 6.1 6.14 0.29 1 1.00 975 

292 5.97 5.39 6.00 6.07 6.1 6.14 0.29 1 1.00 982 

296 5.97 5.39 6.00 6.07 6.1 6.14 0.29 1 1.00 990 

300 5.97 5.39 6.00 6.07 6.1 6.14 0.29 1 1.00 997 

1
D-6

1 (2) Estimates of HL and Surge Line Failure Probabilities

2

3 The calculator also provides estimates of HL and surge line failure probabilities as a function of 

4 time, without reporting uncertainties. For this base case, these probabilities are shown in 

5 Figure D-3 and also in Table D-2. Also reported are the ratios of the average tube leak area to 

6 the critical leak area (Am / Ac).

7

8 Because HL failure occurs earlier than the surge line failure in this case, from now on, it will be 

9 used for further discussions.

10

11 The above two sets of estimates of tubes and HL failure are done independently. As long as 

12 the leak area is small (less than the critical area), the reactor coolant system (RCS) is deemed 

13 to not depressurize sufficiently to affect the temperature and pressures experienced by other 

14 parts of the RCS; thus this independence assumption is valid in this “small” range of integrated 

15 SG leaks (from one or more flaws).

16

17 One can define a simple measure of comparison between the HL failure time and the tube 

18 failure time. This measure is called the Margin in minutes and is defined as:

19

20 Margin = {time in minutes of failure of HL when its failure probability reaches 1} -

21 {time in minutes of integrated SG tube leak area reaches Ac: Am/Ac=1}

22

23 For this base case, the margin is -18 minutes (221–239 = 18 minutes), as reported in Table D-3. 

24 Large, negative margin is considered as favorable, because it would arrest or reduce SG tube 

25 leak area generation or fission product release from it. It should be noted that Table D-2 shows 

26 that there is a period of about 20 minutes when a nonzero probability of HL is estimated. 

27 Therefore, any negative margin value greater than 20 minutes will be indicative of zero 

28 probability of C-SGTR.

29

30 Figure D-2 also shows that the spread in the time of tube failure is very narrow, although the 

leak size has a range of 0–6 cm2

(0–0.93 in.

2 31 ), which reaches Ac. It is also to be noted that:

32

33 • No uncertainty distributions is provided for the thermal-hydraulic (TH) input file.

34 • No uncertainty results are reported for HL and surge line failures.

35

36 Thus, deriving robust uncertainty insights solely based on the calculator should not be expected. 

37 Sensitivity analyses on what is deemed as other parameters of significance could be and should 

38 be done.

39

40 Because the margin as defined above is a simple yet important indicator of avoidance of early 

41 and large fission product releases, some sensitivity analysis are offered in this section, to 

42 determine the uncertainty spread in the margin.

43
D-7

1

2

3 Figure D-3 Probabilities of HL and surge line failure

-0.2

0

0.2

0.4

0.6

0.8

1

1.2

210 220 230 240 250 260 270 280 290

Time in minutes

Hot Leg failure prob.

Surge Line Failure prob.

Am / Ac
D-8

Table D-2 Probabilities of HL and Surge Line

Time (m) HL Failure Prob. Surge Line Failure Prob. Am / Ac

211 0.00 0.000 0.000

212 0.00 0.000 0.000

213 0.01 0.000 0.000

214 0.04 0.000 0.000

215 0.13 0.000 0.000

216 0.31 0.000 0.000

217 0.52 0.000 0.000

218 0.79 0.000 0.000

219 0.87 0.000 0.000

219 0.93 0.000 0.000

220 0.99 0.000 0.000

221 1.00 0.000 0.000

222 1.00 0.000 0.000

223 1.00 0.000 0.000

224 1.00 0.000 0.000

224 1.00 0.000 0.000

225 1.00 0.000 0.000

225 1.00 0.000 0.000

226 1.00 0.000 0.000

226 1.00 0.000 0.000

227 1.00 0.000 0.000

227 1.00 0.000 0.000

228 1.00 0.000 0.000

228 1.00 0.002 0.000

229 1.00 0.003 0.000

229 1.00 0.008 0.000

230 1.00 0.024 0.001

230 1.00 0.070 0.001

231 1.00 0.100 0.001

232 1.00 0.190 0.013

233 1.00 0.330 0.150

235 1.00 0.470 0.480

236 1.00 0.590 0.800

238 1.00 0.700 0.950

239 1.00 0.780 0.990

241 1.00 0.860 0.990

243 1.00 0.910 0.990

245 1.00 0.940 0.990

247 1.00 0.950 0.990

250 1.00 0.970 0.990
D-9

Table D-2 Probabilities of HL and Surge Line

Time (m) HL Failure Prob. Surge Line Failure Prob. Am / Ac

252 1.00 0.970 0.990

255 1.00 0.980 0.990

257 1.00 0.980 0.990

260 1.00 0.990 0.990

263 1.00 0.990 0.990

266 1.00 0.990 0.990

270 1.00 0.990 0.990

273 1.00 0.990 0.990

277 1.00 0.990 0.990

280 1.00 0.990 0.990

284 1.00 0.990 0.990

288 1.00 1.000 0.990

292 1.00 1.000 0.990

296 1.00 1.000 0.990

300 1.00 1.000 0.990

1
D-10

Table D-3 Calculation of Margin for the Base Case 1

2

Time in Minutes

NUREG/

CR-6995 Calculator Comment

1 Event Starts 000 000

2 SGs dryout 100

3 Evacuation Start 120

4 HL fails 13% 215

5 First Fuel Rod Clad Rupture 217

6 HL fails 52% 217

7 HL fails 100% 221

8 HL 1 fails by Creep Rupture 227

9 SL fails 18% 232

10 Hottest tube creep rupture failure 233

11 SL fails 59% 236

12 Hot tube fails 6 cm2 (1 tube equivalent) 239

13 Hot tube fails xx cm2 (n tube equivalent)

14 Hot tube fails max 6 cm2 (1 tube equivalent) 239

15 SL fails 100 % 280

16 Evacuation ends for internal events 360

17 Evacuation ends for external events 600

Margin = HL fails 100% - Hot tube fails 6 cm2 -18

3

4 The definition of margin is based on the crucial TH assumption that a full break of a single SG tube 

(6 cm2 [0.93 in.2 5 ]) would not depressurize the RCS to prevent RCS failure elsewhere.

6

7 Hot tube fraction = 1.0 (all flaws are assumed to be on the hot tubes)

8

9 NUREG/CR-6995 (RELAP 2010)

10

11

12 The following sensitivity calculations are done to seek some insights into these questions:

13

14 Case-1: Sensitivity on delta-T (between HL and hot tube)

15

16 Assume that the delta-T between the HL and hot tube temperatures is only 50 percent as large 

17 as the base case. Make a run where at each time step, the base case delta-T is cut in half by 

18 reducing the HL temperature.

19

20 Case-2: Sensitivity to HL thickness (assessing the potential effect of an overlay)

21

22 Although placement of weld overlays at the HL safe-ends may provide a safety enhancement 

23 against potential cracks and resulting RCS leaks at those locations, an undesirable side effect 
D-11

1 may be to delay the expected earlier failure of HL, thus reducing the margin. To estimate effect 

2 of an overlay on the margin, the HL thickness is increased in this case.

3

4 The results of these cases are given below.

5

6 Throughout this report, it is deemed that, in temperature challenges, where core damage has 

7 already occurred, the secondary side is depressurized. A small pre-existing leak area of 

3.22 cm2 (0.5 in.2 8 ) is shown in previous TH analyses to be sufficient to depressurize the 

9 secondary side. Another sensitivity case run was made and reported below to examine “what 

10 would be the effect on the margin if the secondary side is not depressurized?”

11

12 Case-3: Secondary side not depressurized (see Section D.1.4)

13

14 This case is not made to address uncertainty, but to illustrate the effect of secondary side being 

15 pressurized on the margin.

16

17 Additional sensitivity cases with multiple tube flaws are provided in Appendix E.

18

19 D.1.2 Sensitivity on Temperature Difference between HL and Hot Tube

20

21 The TH input file for this case is a modified version of the wbasenew-short, where the HL

22 temperature at each time step is reduced so that the difference between it and the hot tube 

23 temperature is only 50 percent of the difference in the base case.

24

25 The resulting margin calculation is given in Table D-4. The margin for this case is -14 minutes, 

26 reduced by 4 minutes due to a significant reduction in the delta T. Thus, even if the initial TH 

27 analysis is off by a factor of 2 in estimating the temperature difference between HL and hot tube, 

28 where the flaw is located, the margin is not significantly affected.
D-12

Table D-4 Margin with Smaller Temperature Difference between HL and Hot Tube 1

2

Time in Minutes

NUREG/

CR-6995 Calculator Comment

1 Event Starts 000 000

2 SGs dryout 100

3 Evacuation Start 120

4 HL fails 12% 224

5 First Fuel Rod Clad Rupture 217

6 HL fails 56% 225

7 HL fails 100% 225

8 HL 1 fails by Creep Rupture 227

9 SL fails 17% 232

10 Hottest tube creep rupture failure 233

11 SL fails 57% 236

12 Hot tube fails 6 cm2 (1 tube equivalent) 239

13 Hot tube fails xx cm2 (n tube equivalent)

14 Hot tube fails max 6 cm2 (1 tube equivalent) 239

15 SL fails 100 % 280

16 Evacuation ends for internal events 360

17 Evacuation ends for external events 600

Margin = HL fails 100% - Hot tube fails 6 cm2 -14

3

4 The definition of margin is based on the crucial TH assumption that a full break of a single SG tube 

(6 cm2 [0.93 in.2 5 ]) would not depressurize the RCS to prevent RCS failure elsewhere.

6

7 Hot tube fraction = 1.0 (all flaws are assumed to be on the hot tubes)

8

9 NUREG/CR-6995 (RELAP 2010)

10

11

12 D.1.3 Sensitivity to HL Thickness (potential effect of an overlay)

13

14 In this sensitivity case, the effect of an increase in HL thickness due to a weld overlay, on the 

15 margin is examined. For this purpose, the HL thickness of 6.35 cm in the base case is 

16 increased by 50 percent, to 9.5 cm (3.74 in.). This increase is deemed to be a fair 

17 representation of what a weld overlay would provide.

18

19 The resulting margin calculation is given in Table D-5. The margin for this case is -16 minutes, 

20 reduced by 2 minutes due to a significant increase in HL thickness, which is presumed to delay 

21 HL failure. Thus, even if the HL contains weld overlay, which increases its thickness by 

22 50 percent, the margin is not significantly affected.
D-13

Table D-5 Margin with Thicker HL 1

2

Time in Minutes

NUREG/

CR-6995 Calculator Comment

1 Event Starts 000 000

2 SGs dryout 100

3 Evacuation Start 120

4 HL fails 18% 219

5 First Fuel Rod Clad Rupture 217

6 HL fails 61% 220

7 HL fails 100% 223

8 HL 1 fails by Creep Rupture 227

9 SL fails 19% 232

10 Hottest tube creep rupture failure 233

11 SL fails 58% 236

12 Hot tube fails 6 cm2 (1 tube equivalent) 239

13 Hot tube fails xx cm2 (n tube equivalent)

14 Hot tube fails max 6 cm2 (1 tube equivalent) 239

15 SL fails 100 % 288

16 Evacuation ends for internal events 360

17 Evacuation ends for external events 600

Margin = HL fails 100% - Hot tube fails 6 cm2 -16

3

4 The definition of margin is based on the crucial TH assumption that a full break of a single SG tube 

(6 cm2 [0.93 in.2 5 ]) would not depressurize the RCS to prevent RCS failure elsewhere.

6

7 Hot tube fraction = 1.0 (all flaws are assumed to be on the hot tubes)

8

9 NUREG/CR-6995 (RELAP 2010)

10

11

12 D.1.4 Secondary Side Not Depressurized

13

14 To assess the effect of the secondary side not being depressurized, the TH input file is modified 

15 to have the secondary pressure set at 7.6 megapascals (MPa) (1,100 pounds per square inch 

16 [psi]), the remaining input values being the same as the base case. Figure D-4 summarizes the 

17 main parameters of this case. The TH input file for this case is labeled as 

18 TH-wnewbase-short-1100psi.txt.

19

20 The output of the case is summarized in Table D-6. The margin is calculated to be 45 minutes. 

21 This large margin seems to indicate that the tube is more sensitive to pressure reduction at the 

22 creep rupture failure temperature range, than the HL. In fact, as seen in the table below, the HL

23 failure time is not affected, but the tube flaw failure time is considerably delayed.

24
D-14

1

2

3 Figure D-4 Temperature and pressure profile of the case where secondary side is 

4 not depressurized

5

0

200

400

600

800

1000

1200

1400

1600

1800

0.00 50.00 100.00 150.00 200.00 250.00 300.00 350.00

time in Minutes

delta P in psi

Avr. Hot Tube Temp C HT
D-15

Table D-6 Margin with Secondary Side NOT Depressurized (at 1100 psi) 1

2

Time in Minutes

NUREG/

CR-6995 Calculator Comment

1 Event Starts 000 000

2 SGs dryout 100

3 Evacuation Start 120

4 HL fails 13% 215

5 First Fuel Rod Clad Rupture 217

6 HL fails 55% 217

7 HL fails 100% 221

8 HL 1 fails by Creep Rupture 227

9 SL fails 16% 232

10 Hottest tube creep rupture failure 233

11 SL fails 55% 236

12 Hot tube fails 6 cm2 (1 tube equivalent) 266

13 Hot tube fails xx cm2 (n tube equivalent)

14 Hot tube fails max 6 cm2 (1 tube equivalent) 266

15 SL fails 100 % 280

16 Evacuation ends for internal events 360

17 Evacuation ends for external events 600

Margin = HL fails 100% - Hot tube fails 6 cm2 -45

3

4 The definition of margin is based on the crucial TH assumption that a full break of a single SG tube 

(6 cm2 [0.93 in2 5 ]) would not depressurize the RCS to prevent RCS failure elsewhere.

6

7 Hot tube fraction = 1.0 (all flaws are assumed to be on the hot tubes)

8

9 NUREG/CR-6995 (RELAP 2010)

10

11

12 The margins are as follows:

13

Case Name Margin T HL – T Hot Tube

Base Case -18 minutes 221 - 239

Secondary NOT depressurized -45 minutes 221 - 266

14

15 D.1.5 Late Failure of Turbine Driven AFW Pump

16

17 This case study is performed for the Westinghouse SBO scenario named 153:

18

19 Station Blackout with Failure of TDAFW after Battery Depletion: TDAFW is initially 

20 considered available but it fails a short time after battery depletion due to loss of dc. 
D-16

1 Normal reactor coolant pump seal leakage of 79.5 liters per minute (21 gpm) per pump is 

2 modeled. Operator action to depressurize SGs at 30 minutes by opening at least one SG 

3 Atmospheric Dump Valve (ADV) or SG PORV per SG drops the primary pressure below 

4 4.82 MPa (700 psi). This actuates the accumulator discharge.

5

6 Input TH parameters taken from the file named 153short-end are shown in Table D-7. Other 

7 input files used are:

8

9 • ZION- TT600

10 • Flaw-W4-40.txt.

11

12 The results are summarized in Table D-8. As shown in this table, the margin is -22 minutes, 

13 which is close to the base case margin of -18 minutes. However, both the HL failure and 

14 C-SGTR occur much later than the base case: in about 13 hours into the SBO event. For the 

15 base case, this time was 4 hours into the SBO event. The additional 7 hours gained could allow 

16 for implementation of evacuation, even for the SBOs that may follow seismic or external flooding 

17 events.

18
D-17

1

Table D-7 T&H Input Parameters for Case 153

Time 

in 

Minutes

Primary 

Pressure 

(Pa)

Surge line 

temperature 

(C)

HL

temperature 

(C)

Hot tube 

temperature 

- C

Cold tube 

temperature 

(C)

Secondary 

pressure 

(Pa)

Primary 

Pressure 

in psi

Secondary 

Pressure in 

psi

600 11187857 317 309 316 316 1816161 1622 263 

604 11953517 321 318 323 323 1562022 1733 226 

608 12497496 320 314 321 321 1321353 1812 192 

612 13511729 320 317 320 320 1114784 1959 162 

616 14437555 320 320 321 321 937642 2093 136 

620 15378100 320 324 321 321 787000 2230 114 

624 15935722 322 336 331 331 659257 2311 96 

628 16616382 333 333 344 344 558371 2409 81 

632 16439831 332 334 343 343 465514 2384 67 

636 17106500 332 335 342 342 388108 2480 56 

640 17552148 332 337 341 341 323280 2545 47 

644 16971320 345 342 343 343 268863 2461 39 

648 17878938 349 350 353 353 224552 2592 33 

652 16650259 351 350 351 351 186259 2414 27 

656 16952404 352 352 352 352 157992 2458 23 

660 16895284 352 351 352 352 139242 2450 20 

664 17016836 352 352 352 352 125068 2467 18 

666 17627418 355 353 355 355 119016 2556 17 

667 16689429 353 351 352 351 116987 2420 17 

668 16922776 352 351 352 352 115081 2454 17 

668 17383652 353 352 354 354 113502 2521 16 

669 17783698 355 354 356 356 112031 2579 16 

670 16704144 357 353 353 351 110248 2422 16 

671 17124176 354 356 359 354 109030 2483 16 

672 17433450 355 358 360 356 107944 2528 16 

672 17725334 356 361 363 358 106925 2570 16 

673 16603548 364 359 356 353 105650 2408 15 
D-18

Table D-7 T&H Input Parameters for Case 153

Time 

in 

Minutes

Primary 

Pressure 

(Pa)

Surge line 

temperature 

(C)

HL

temperature 

(C)

Hot tube 

temperature 

- C

Cold tube 

temperature 

(C)

Secondary 

pressure 

(Pa)

Primary 

Pressure 

in psi

Secondary 

Pressure in 

psi

674 16998104 358 362 364 356 104833 2465 15 

675 17214120 354 365 364 359 104169 2496 15 

676 17420130 355 367 367 361 103625 2526 15 

676 17613248 355 369 370 363 103102 2554 15 

678 16692531 368 370 364 360 101998 2420 15 

679 16964364 361 374 375 364 101783 2460 15 

680 17130560 354 376 375 366 101655 2484 15 

680 17302764 354 379 378 368 101566 2509 15 

682 17598950 358 384 384 373 101468 2552 15 

683 16488133 403 384 381 372 101305 2391 15 

684 16850458 372 389 388 373 101385 2443 15 

685 17014836 363 392 392 377 101427 2467 15 

687 17269158 363 398 396 381 101449 2504 15 

688 17473758 359 404 401 386 101438 2534 15 

690 17651938 358 410 407 390 101434 2560 15 

691 16515044 427 410 405 390 101328 2395 15 

692 16806486 382 416 408 389 101380 2437 15 

693 16980630 370 419 417 394 101419 2462 15 

695 17173498 366 426 420 398 101443 2490 15 

696 17335400 364 432 425 403 101437 2514 15 

697 17415656 356 435 427 405 101434 2525 15 

699 17610018 356 441 432 409 101431 2553 15 

700 17541364 400 445 437 413 101424 2543 15 

701 16712065 392 447 427 408 101365 2423 15 

702 16932056 375 451 442 412 101406 2455 15 

703 17060404 355 454 444 415 101422 2474 15 

704 17304860 355 460 447 419 101434 2509 15 

706 17532364 355 466 451 423 101427 2542 15 
D-19

Table D-7 T&H Input Parameters for Case 153

Time 

in 

Minutes

Primary 

Pressure 

(Pa)

Surge line 

temperature 

(C)

HL

temperature 

(C)

Hot tube 

temperature 

- C

Cold tube 

temperature 

(C)

Secondary 

pressure 

(Pa)

Primary 

Pressure 

in psi

Secondary 

Pressure in 

psi

707 17742650 355 472 456 427 101421 2573 15 

708 16541230 419 471 445 423 101337 2398 15 

709 16814356 380 476 455 425 101387 2438 15 

710 16960858 364 479 463 429 101407 2459 15 

710 17093302 354 482 465 431 101417 2479 15 

712 17346446 355 488 467 435 101425 2515 15 

714 17562786 364 495 471 439 101418 2547 15 

714 17644584 373 499 475 441 101417 2558 15 

715 17722210 383 503 477 442 101417 2570 15 

716 16605336 486 519 473 441 101350 2408 15 

717 16726971 427 513 470 439 101374 2425 15 

718 16866784 425 515 482 443 101398 2446 15 

719 17023420 433 521 488 448 101412 2468 15 

721 17168432 441 527 491 451 101418 2489 15 

722 17309840 449 534 496 455 101416 2510 15 

724 17445408 456 540 500 459 101413 2530 15 

726 17576558 463 547 505 462 101412 2549 15 

727 17677886 470 553 509 466 101410 2563 15 

729 17756554 477 560 513 469 101408 2575 15 

730 17257022 495 566 509 467 101377 2502 15 

730 16494932 530 573 509 467 101352 2392 15 

731 16655850 508 572 514 467 101380 2415 15 

732 16710891 508 575 521 471 101392 2423 15 

734 16775306 513 584 526 476 101401 2432 15 

736 16790980 517 590 529 479 101402 2435 15 

737 16802604 521 597 534 482 101400 2436 15 

739 16809486 525 604 538 485 101399 2437 15 

741 16821192 528 611 543 488 101398 2439 15 
D-20

Table D-7 T&H Input Parameters for Case 153

Time 

in 

Minutes

Primary 

Pressure 

(Pa)

Surge line 

temperature 

(C)

HL

temperature 

(C)

Hot tube 

temperature 

- C

Cold tube 

temperature 

(C)

Secondary 

pressure 

(Pa)

Primary 

Pressure 

in psi

Secondary 

Pressure in 

psi

742 16828688 532 618 547 491 101398 2440 15 

744 16835622 535 625 552 494 101398 2441 15 

745 16837316 539 632 556 497 101398 2441 15 

747 16847754 542 640 561 500 101398 2443 15 

749 16864748 546 648 566 503 101399 2445 15 

750 16878606 549 655 570 506 101399 2447 15 

752 16892486 552 663 575 510 101399 2449 15 

753 16903808 556 672 580 513 101399 2451 15 

755 16916818 559 680 584 516 101399 2453 15 

757 16930512 563 688 589 519 101399 2455 15 

758 16945692 566 696 594 522 101399 2457 15 

760 16961192 570 705 599 526 101399 2459 15 

761 16978144 573 713 604 529 101399 2462 15 

763 16995640 577 722 609 532 101399 2464 15 

764 17013394 581 731 614 536 101399 2467 15 

766 17031428 584 740 619 539 101399 2470 15 

768 17049492 588 749 624 542 101399 2472 15 

769 17068202 592 758 629 545 101399 2475 15 

771 17087730 596 767 634 549 101399 2478 15 

772 17107852 600 777 639 552 101399 2481 15 

774 17129464 605 787 645 556 101399 2484 15 

776 17150636 609 796 650 559 101399 2487 15 

777 17173824 614 807 656 562 101399 2490 15 

779 17198290 618 818 661 566 101399 2494 15 

780 17225090 623 829 667 569 101399 2498 15 

782 17255404 629 840 673 573 101400 2502 15 

783 17289820 635 853 680 576 101401 2507 15 

785 17328194 641 866 686 580 101402 2513 15 
D-21

Table D-7 T&H Input Parameters for Case 153

Time 

in 

Minutes

Primary 

Pressure 

(Pa)

Surge line 

temperature 

(C)

HL

temperature 

(C)

Hot tube 

temperature 

- C

Cold tube 

temperature 

(C)

Secondary 

pressure 

(Pa)

Primary 

Pressure 

in psi

Secondary 

Pressure in 

psi

787 17371994 648 881 694 584 101404 2519 15 

788 17424672 656 898 702 588 101406 2527 15 

789 17454806 660 908 706 590 101408 2531 15 

790 17486682 665 918 710 592 101410 2536 15 

791 17523474 670 929 715 594 101412 2541 15 

791 17565386 676 942 720 596 101415 2547 15 

792 17610286 681 954 726 598 101418 2553 15 

793 17671602 689 972 732 601 101423 2562 15 

794 17295002 826 1,013 739 603 101419 2508 15 

795 16933844 804 1,077 743 599 101410 2455 15 

795 17161326 832 1,188 784 608 101485 2488 15 

796 17240314 851 1,223 788 613 101523 2500 15 

797 17288726 864 1,245 797 616 101533 2507 15 

798 17324848 877 1,275 806 618 101527 2512 15 

799 17355544 887 1,306 816 620 101509 2517 15 

799 17374412 898 1,341 828 622 101488 2519 15 

800 17369112 906 1,365 838 623 101473 2519 15 

801 17362924 914 1,386 846 626 101461 2518 15 

802 17346996 921 1,401 853 628 101453 2515 15 

803 17295070 930 1,413 864 632 101441 2508 15 

806 17222752 937 1,411 875 638 101419 2497 15 

808 17168220 941 1,409 885 644 101411 2489 15 

811 17100416 943 1,405 896 651 101400 2480 15 

814 17033290 941 1,398 904 658 101394 2470 15 

818 17023456 943 1,387 912 665 101390 2468 15 

822 17100190 945 1,370 918 673 101383 2480 15 

826 17211974 950 1,360 926 681 101380 2496 15 

830 17194184 945 1,350 931 688 101376 2493 15 
D-22

Table D-7 T&H Input Parameters for Case 153

Time 

in 

Minutes

Primary 

Pressure 

(Pa)

Surge line 

temperature 

(C)

HL

temperature 

(C)

Hot tube 

temperature 

- C

Cold tube 

temperature 

(C)

Secondary 

pressure 

(Pa)

Primary 

Pressure 

in psi

Secondary 

Pressure in 

psi

833 17074150 934 1,345 934 694 101374 2476 15 

836 16953292 922 1,339 937 700 101373 2458 15 

838 16845614 911 1,334 939 704 101372 2443 15 

841 16757801 901 1,331 942 710 101374 2430 15 

843 16804596 905 1,313 941 715 101371 2437 15 

844 16781984 901 1,300 939 715 101368 2433 15 

845 16777074 899 1,283 934 716 101364 2433 15 

849 16719079 890 1,294 940 718 101364 2424 15 

851 16631669 880 1,299 944 721 101365 2412 15 

853 16539559 870 1,302 948 725 101365 2398 15 

856 16444167 860 1,304 950 729 101365 2384 15 

858 16351976 850 1,303 951 732 101365 2371 15 

860 16267959 840 1,303 953 735 101364 2359 15 

863 16149878 828 1,301 953 738 101364 2342 15 

865 16039874 817 1,300 954 741 101363 2326 15 

868 15936266 807 1,300 955 743 101363 2311 15 

870 15829010 796 1,299 957 746 101363 2295 15 

872 15719427 785 1,298 958 749 101362 2279 15 

876 15764007 794 1,298 963 753 101363 2286 15 

883 15720647 783 1,307 969 760 101362 2279 15 

885 15609858 772 1,310 970 762 101362 2263 15 

887 15493158 761 1,312 972 765 101362 2247 15 

890 15376555 750 1,313 973 767 101361 2230 15 

891 15452803 759 1,314 975 769 101364 2241 15 

892 16746626 832 1,316 994 772 101383 2428 15 

893 16766600 1,172 1,356 997 771 101351 2431 15 

894 17313854 1,109 1,351 981 766 101360 2511 15 

895 17545106 1,117 1,338 968 763 101358 2544 15 
D-23

Table D-7 T&H Input Parameters for Case 153

Time 

in 

Minutes

Primary 

Pressure 

(Pa)

Surge line 

temperature 

(C)

HL

temperature 

(C)

Hot tube 

temperature 

- C

Cold tube 

temperature 

(C)

Secondary 

pressure 

(Pa)

Primary 

Pressure 

in psi

Secondary 

Pressure in 

psi

895 17177846 1,182 1,336 963 762 101351 2491 15 

1

2

153short-end Case 153 (late TDAFW pump failure) is shortened by removing some of the earlier time steps

not contributing to results

0.01 Significance factor to reduce time steps (0.0 uses all time steps input).

1.00 Fraction of “hot” SG tubes (1.00 means all flaws (100%)are on the hot tubes)

3
D-24

Table D-8 Margin for the Case with Failure of TDAFW Pump at 4 Hours 1

2

Time in Minutes

NUREG/

CR-6995

Calculator Comment

1 Event Starts 000 000

2 TDAFW Pump fails 240

3 Evacuation Start 240

4 Evacuation ends for internal events 480

5 SGs dryout 583

6 Evacuation ends for external events 720

7 HL fails 26% 768

8 HL fails 49% 769

9 HL fails 100% 777

10 HL 1 fails by Creep Rupture 793

11 Hot tube fails 6 cm2 (1 tube 

equivalent)

799

12 Hot tube fails max 6 cm2 (1 tube 

equivalent)

799

13 SL fails 33% 808

14 SL fails 58% 818

15 SL fails 100 % 893

Margin = HL fails 100% - Hot tube fails 6 cm2 -22

The definition of margin is based on the crucial T&H assumption that a full break of a 

single SG tube

(6 cm2 [0.93 in.2]) would not depressurize the RCS to prevent RCS failure 

elsewhere.

Hot tube fraction = 1.0 (all flaws are assumed to be on the hot tubes)

NUREG/CR-6995 RELAP 2010 Case 153

3

4

5 D.1.6 Effect of TT690 Material

6

7 This sensitivity analysis studies a comparison of having both W and CE SG types with TT690 

8 tube material. For this purpose two cases are defined and are simulated by the calculator:

9

10 Case 1:

11

12 Calvert Cliffs with TT690 tubes; a “large” wear type flaw 4 cm (1.6 in.) and 40 percent deep. 

13 SBO with failure of the turbine-driven pump (TDP) at the start of the event; loop A with average 

14 SG tubes used from the TH analysis.

15
D-25

1 Case 2:

2

3 Zion with TT690 tubes; a “large” wear type flaw 4 cm (1.57 in.) and 40 percent deep. SBO with 

4 failure of TDP at the start of the event; Wnewbase case used from the TH analysis.

5

6 In terms of the calculator input files used, the case information can be summarized as shown 

7 next:

8

Case 1: Case 2:

TH-CE-A-0-Avr-short TH-Wnewbase-short

W4-40 W4-40

Calvert Cliffs (TT690) ZION690

9

10 The results are summarized in Table D-9. When TT690 material is postulated to be used in W11 type SG, the margin is still favorable for failure of HL before large-flawed SG tube, but it is 

12 shortened compared to the same case with TT600 material (case 3). Case 3 is defined as

13

Case 3:

TH-Wnewbase-short

W4-40

ZION600

14

15 Case 3 margin is also shown in Table D-9. The result that case 3 margin is larger than case 2 

16 margin seems to indicate that SG tubes with TT690 material with a “large” flaw will leak earlier 

17 than SG tubes with TT600 material with the same “large” flaw (in 233 minutes versus in 243 

18 minutes in this case).
D-26

Table D-9 Comparison of TT690 Cases between W vs. CE Type SGs 1

2

Time in Minutes

NUREG/

CR-6995

Case 1 

Calculator

Case 2 

Calculator

Case 3 

Calculator

Comment

1 Event starts 000 000

2 TDAFW pPump fails 240

3 Evacuation start 240

4 Evacuation ends for internal 

events

480

5 SGs dryout 583

6 Evacuation ends for external 

events

720

7 HL fails 26%

8 HL fails 49%

9 HL fails 100% 357 221 219

10 HL 1 fails by creep rupture 793

11 Hot tube fails 6 cm2 (0.93 in.2) 

(1 tube equivalent)

325 233 243 Case 1 max 

failure area 

is 4.5 cm-sq.

12 Hot tube fails max 6 cm2

(0.93 in.2) (1 tube equivalent)

13 SL fails 33%

14 SL fails 58%

15 SL fails 100 %

Margin = HL fails 100% - Hot 

tube fails 6 cm2

32 -12 -24

3

4 The definition of margin is based on the crucial TH assumption that a full break of a single SG 

tube (6 cm2 [0.93 in.

2 5 ]) would not depressurize the RCS to prevent RCS failure elsewhere.

6

7 Hot tube fraction = 1.0 (all flaws are assumed to be on the hot tubes)

8

9 NUREG/CR-6995 RELAP 2010 Case 153

10

11

12 D.1.7 Conclusions

13

14 The analyses elsewhere in this report rely on the C-SGTR calculation results. The C-SGTR 

15 calculator provides some estimates of uncertainties, especially for the integrated leak areas. 

16 However, it does not provide a robust uncertainty estimate for uncertainties in the scenario TH 

17 input. For better understanding of the effect of TH uncertainties, sensitivity analyses were 

18 performed in this section, on a base case (Westinghouse SBO core damage sequence with a 

19 large flaw subject to temperature challenges). The sensitivity analyses indicate that, for this 

20 base case, the margin between the HL failure occurring first and tube failure growing into a 

21 large leak is not sensitive to changes on the base values of two major modeling parameters. 
D-27

1 These two modeling parameters are the HL thickness (to account for existence of weld 

2 overlays), and the temperature difference between HL and hot tube.

3

4 The margins are as follows:

5

Case Name Margin

Base Case -18 minutes

Reduced dT between HL and hot tube -14 minutes

Increased HL thickness -16 minutes

6

7 The -18 minute base margin is a reliable good margin, which appears to have a tight spread 

8 when other major modeling parameters are changed in an unfavorable direction.

9

10 Although these conclusions apply to this scenario with these cases, they provide:

11

12 • Insights about the model stability against some key changes

13 • Give some confidence that the margin point estimate is stable

14

15 An additional sensitivity analysis is made with the secondary-side pressure set at 6.9 MPa 

16 (1,100 psi). The result shows that the margin increases to 45 minutes.

17

18 Finally, if TDAFW pump fails at 4 hours, the HL and C-SGTR failures are pushed further in time 

19 to about 13 hours following the SBO.

20

21 D.2 Sensitivity Analyses for the Selected CE Plant

22

23 The following sensitivity analyses were performed for the representative CE plant. The 

24 measure of comparison used for these sensitivity analyses was based on the reevaluation of 

25 C-SGTR probability for stsbo sequences where LERF is of concern. In some cases; the 

26 C-SGTR probability was only reevaluated for one loop rather than for both loop A and loop B

27 (i.e., the reactor unit). When the sensitivity analysis was limited to one loop, loop B was 

28 selected because of its higher contribution to C-SGTR. The difference between the revised C29 SGTR probability and the base C-SGTR probability was used to prioritize the effect of the 

30 sensitivity results. The changes of less than 25 percent are assigned as low, 25 to 50 percent

31 as moderate, 50 to 100 percent as high, and any increases above 200 percent as significant.

32

33 D.2.1 Stuck Open Failure of Secondary Relief Valves before SG Dryout

34

35 In SBO scenarios, before SG dryout the secondary-side relief valves (SG PORVs or MSSVs) 

36 could be demanded and fail to re-close. This could happen in either or both SGs. Stick open 

37 relief valves initially depressurize and cool the primary below the accumulator discharge 

38 setpoint. Post accumulator discharge the SGs will go dry, the primary will re-pressurize, and the 

39 onset of core damage will be reached, although slightly delayed. The probability of C-SGTR is 

40 expected to be higher due to a lower secondary-side pressure and delayed HL failure. A 

41 bounding analysis of this scenario was evaluated using MELCOR package. This scenario is 

42 referred to as stsbo-as and ltsbo-as in Section 3.

43
D-28

1 Figures D-6 through D-9 shows the following graphs for stsbo-as scenario. Figures D-10

2 through D-13 shows the same graphs for ltsbo-as scenarios. The specific information 

3 presented in each figure for stsbo-as and ltsbo-as is shown below:

4

5 • Figure D-5 shows the primary and secondary pressure

6

7 • Figures D-6 and D-10: Overall results for Loop a

8

9 • Figures D-7 and D-11: Difference of HL Temp and Average Hot/Hottest Tube 

10 Temperature for Loop a

11

12 • Figures D-8 and D-12: Overall results for Loop B

13

14 • Figures D-9 and D-13: Difference of HL Temp and Average Hot/Hottest Tube 

15 Temperature for Loop b

16

17

18

19 Figure D-5 SBO with TDAFW operating for 0 hours with MSSVs stuck open; Calvert Cliffs

20

0.00E+00

5.00E+02

1.00E+03

1.50E+03

2.00E+03

2.50E+03

3.00E+03

0 100 200 300 400 500 600

Pressure (in psi)

Time (in minutes)

Primary Pressure

Secondary Pressure
D-29

1

2

3 Figure D-6 SBO with TDAFW operating for 0 hours; Calvert Cliffs loop A

4

5

6

7 Figure D-7 Temperature differences in SBO with TDAFW operating for 0 hours; Calvert 

8 Cliffs loop A

9

0

200

400

600

800

1000

1200

1400

1600

1800

0 100 200 300 400 500 600

Temperature (in 

oCelsius)

Time (in minutes)

Surge Line Temp

Top Hot Leg Temp

Ave Hot SG Tube

Temp

-300

-250

-200

-150

-100

-50

0

50

100

150

200

0 100 200 300 400 500 600

Temperature (in 

oCelsius)

Time (in minutes)

Hottest Tube - Top Hot Leg C

Average Hot - Top Hot Leg C
D-30

1

2

3 Figure D-8 SBO with TDAFW operating for 0 hours; Calvert Cliffs loop B

4

0

200

400

600

800

1000

1200

1400

1600

1800

0 100 200 300 400 500 600

Temperature (in 

oCelsius)

Time (in minutes)

Surge Line Temp

Top Hot Leg Temp

Ave Hot SG Tube Temp

Ave Cold SG Tube Temp

Hottest Tube Temp
D-31

1

2

3 Figure D-9 Temperature differences in SBO with TDAFW operating for 0 hours; Calvert 

4 Cliffs loop B

5

6

7

8 Figure D-10 SBO with TDAFW operating for 4 hours; Calvert Cliffs loop A

9

-250

-200

-150

-100

-50

0

50

100

150

200

250

0 100 200 300 400 500 600

Temperature (in 

oCelsius)

Time (in minutes)

Hottest Tube - Top Hot Leg C

Average Hot - Top Hot Leg C

0

200

400

600

800

1000

1200

1400

1600

0 500 1000 1500 2000

Temperature (in oCelsius)

Time (in minutes)

Surge Line Temp

Top Hot Leg Temp

Ave Hot SG Tube Temp

Ave Cold SG Tube Temp

Hottest Tube Temp
D-32

1

2

3 Figure D-11 Temperature differences in SBO with TDAFW operating for 4 hours; Calvert 

4 Cliffs loop A

5

-400

-350

-300

-250

-200

-150

-100

-50

0

50

100

150

0 500 1000 1500 2000

Temperature (in 

oCelsius)

Time (in minutes)

Hottest Tube - Top Hot Leg C

Average Hot - Top Hot Leg C
D-33

1

2

3 Figure D-12 SBO with TDAFW operating for 4 hours; Calvert Cliffs loop B

4

0

200

400

600

800

1000

1200

1400

1600

0 500 1000 1500 2000

Temperature (in 

oCelsius)

Time (in minutes)

Surge Line Temp

Top Hot Leg Temp

Ave Hot SG Tube Temp

Ave Cold SG Tube Temp

Hottest Tube Temp
D-34

1

2

3 Figure D-13 Temperature differences in SBO with TDAFW operating for 4 hours; Calvert 

4 Cliffs loop B

5

6 Separate C-SGTR runs were performed for average hot and hottest tube for loop A and loop B. 

7 The results for average hot and hottest tube for each loop then were combined to estimate 

8 single loop probabilities of C-SGTR. Figures D-14 and D-15 shows the results for loops A and 

9 B.

10

11 As shown in both Figures the curves associated with RCS survival probability are significantly 

12 shifted to the right compare to the probability of SGTR with leak areas less than 3 and 

6 cm2

.(0.46 and 0.93 in.2 13 ). This indicates that SGTR that exceeds the critical leak area will 

14 occur before the HL failure therefore the C-SGTR probability will be very high (close to 1).

15

16 Figure D-16 shows similar graph when the results from loop A and loop B are combined. This 

17 figure also shows that the RCS survival probability is on the right side of the graph for SGTR 

18 leak probability curves. The results show that the failure of secondary-side relief valve early 

19 during the sequence can have significant effect on LERF contribution because of C-SGTR. 

20 Table D-10 below shows the results of this re-evaluation for stsbo-as sequences. As shown in 

21 Table D-10, the C-SGTR probability is almost one (0.99) for this scenario.

22

-60

-40

-20

0

20

40

60

80

100

120

140

0 200 400 600 800 1000 1200 1400

Temperature (in 

oCelsius)

Time (in minutes)

Hottest Tube - Top Hot Leg C

Average Hot - Top Hot Leg C
D-35

1

2

Figure D-14 Probabilities of SGTR leak rates less than 3 and 6 cm2 3 vs. HL survival 

4 probability for stsbo-as-a-scf

5

6

7

Figure D-15 Probabilities of SGTR leak rates less than 3 and 6 cm2 8 vs. HL survival 

9 probability for stsbo-as-b-scf

10

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

15500 16000 16500 17000 17500 18000

Probability

Time (s)

P(SGTR<3cm^2)

P(SGTR<6cm^2)

P(RCS Survive)

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

15000 15500 16000 16500 17000 17500 18000

Probability

Time (s)

P(SGTR<3cm^2)

P(SGTR<6cm^2)

P(RCS Survive)
D-36

1

2

Figure D-16 Probability of SGTR less than 6 cm2 3 and probability of RCS survival

4

Table D-10 Sensitivity Results for Early Stick Open Failures of the Secondary 5

Relief Valves 6

7

Case runs Loop b CSGTR

> 3 cm2

Loop a CSGTR

> 3 cm2

CSGTR

> 6 cm2

Stsbo-a [base} 0.45 0.217 0.2

Stsbo-as [Stick open secondary relief 

valve] 0.999 0.997 0.99

8

9 Opening of Secondary Relief Valves after SG Dryout

10

11 The operators are guided to depressurize the SGs by opening the secondary relief valves in 

12 anticipation of using an alternate source of water to refill the SGs as a part of SAMGs. This 

13 sensitivity analysis examines the effect of intentionally opening the secondary relief after the 

14 onset of core damage when the operators fail to refill the SGs. This sensitivity analysis was 

15 performed by setting the secondary-side pressure to 1.0E+05 Pascal after the hot gas 

16 temperature reaches about 640 degrees C (1,184 degrees F) (i.e., at 16,800 seconds for stsbo17 a). The effects on primary pressure or temperature are not expected to be significant, therefore, 

18 no changes were made to these input. Figure D-17 shows the results for loop B with and 

19 without open secondary relief valves after SG dryout. As it can be seen the graph for the case 

20 where secondary relief is open is shifted further to the left indicating that the likelihood of 

C-SGTR greater than 3 cm2 (0.46 in.

2 21 )is higher than the base case.

22

23 Figure D-18 shows the aggregate effect of opening secondary relief valves after SG dryout for 

24 both loops. Similar to the previous graph, the SGTR curve associated with open secondary 

25 relief is shifted to the right indicating higher probability of C-SGTR.

26

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

18000 19000 20000 21000 22000 23000 24000

Probability

Time (s)

P(SGTR<6cm^2)

P(RCS-SURVIVE)
D-37

1

2

Figure D-17 Probability of SGTR leak rate less than 3 cm2 3 for loop B with and without 

4 open secondary relief valves after SG dryout

5

6 In summary, the results show that the opening of secondary-side relief valve after SG dry out 

7 and the onset of core damage which can increase LERF contribution due to C-SGTR by about 

8 65 percent (from 0.2 to 0.33) for stsbo-a scenarios. Table D-11 below shows the results of this 

9 re-evaluation.

10

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

15000 17000 19000 21000 23000 25000

Probability

Time (s)

STSBO-a with stick open

secondary relief

STSBO-a with no failure of

Secondary relief

P(RCS-SURVIVE)
D-38

1

2

3 Figure D-18 Probability of SGTR leak rate less than 6 cm2 with and without open 

4 secondary relief valves after SG dryout

5

Table D-11 Sensitivity Results for Opening the Secondary Relief Valves after SG Dryout 6

7

Case runs Loop b CSGTR

> 3 cm2

Loop a CSGTR

> 3 cm2

CSGTR

> 6 cm2

Stsbo-a [base} 0.450 0.217 0.200

Stsbo-a [secondary relief left opened after 

SG dryout] 0.591 0.262 0.330

8

9 D.2.2 Critical C-SGTR Leak Area

10

The critical area equivalent to Guillotine break of one tube (approximately 6 cm2 [0.93 in.2 11 ]) was 

12 considered to be sufficient to meet the LERF threshold if the secondary-side relief valves are 

13 open. Some MELCOR analyses showed that this size of leakage may not pressurize the 

14 secondary, such that SG relief valves are demanded. These MELCOR analyses assumed that 

there is a pre-existing secondary leakage area of 3.22 cm2 (0.5 in.

2 15 ) from the starting point of 

16 the sequence. To ensure that the secondary relief valves are demanded and primary can be 

17 depressurized, a larger critical C-SGTR leak area may have to be considered. Figure D-19

18 shows the probability graph of various leak rates for stsbo-a sequence when considering the 

19 expected flaw sample used for this study. The probability of RCS survival is also displayed on 

20 the same Figure; clearly showing the relative positions of the probability curves for various leak 

21 rates to the probability curve of RCS survival.

22

23 Another way of presenting this information in terms of the probability of C-SGTR is shown in 

24 Figure D-20. This figure shows how the C-SGTR probability decreases for larger critical leak 

25 rates for the stsbo-a sequence. It should be emphasized that these curves are only for the 

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

18000 19000 20000 21000 22000 23000 24000

Probability

Time (s)

P(SGTR<6cm^2)

P(RCS-SURVIVE)

P(SGTR<6cm^2) w/o open

secondary
D-39

1 expected flaw sample used for this study and shall not be considered generic. Similar graphs, 

2 however, could be generated for different accident sequences and for another set of flaws for 

3 each SG using the existing tools and approach.

4

5 Using Figure D-20, it can be shown that the probability of C-SGTR is reduced from 0.2 to 0.06 if 

one assumes a critical C-SGTR leak area of 12 cm2 (1.86 in.

2

) instead of 6 cm2 (0.93 in.2 6 ).

7
D-40

1

2

3 Figure D-19 Probability of SGTR with leak rates smaller than a specific value and 

4 probability of RCS survival as a function of accident time

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

18000 18500 19000 19500 20000 20500 21000 21500 22000

P(SGTR<1cm^2)

P(SGTR<2cm^2)

P(SGTR<3cm^2)

P(SGTR<4cm^2)

P(SGTR<5cm^2)

P(SGTR<6cm^2)

P(SGTR<7cm^2)

P(SGTR<8cm^2)

P(SGTR<9cm^2)

P(SGTR<10cm^2)

P(SGTR<11cm^2)

P(SGTR<12cm^2)

P(RCS-SURVIVE)
D-41

1

2

3 Figure D-20 Probability of SGTR as a function of critical leak area

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 2 4 6 8 10 12 14

P(CSGTR)

Leak Area (cm^2)

P(CSGTR)

E-1

1 APPENDIX E

2

3 WESTINGHOUSE SBO SCENARIO AND SENSITIVITY CASES

4

5

6 This Appendix contains additional sensitivity cases for C-SGTR cases in a Westinghouse 4-loop

7 plant with an SBO core damage sequence.

8

9 E.1 Westinghouse SBO Scenario and Sensitivity Cases

10

11 The following SBO scenario is considered for the sensitivity cases for temperature-induced 

12 C-SGTR events:

13

Scenario Name Scenario Description (Westinghouse 4-loop NPP – ZION-like)

WNEWBASE

SBO at time zero, no TDAFW, 3.22 cm2 (0.5 in2) leak area in each SG 

allowing depressurization post dryout. Reactor coolant pump seal 

leakage of 79.5 liters per minute/pump (21 gpm/pump). Ac power is not 

recovered during this scenario.

14

15 Three cases are studied for this core damage scenario:

16

17 Case-1 studies the above scenario with TT600 material and 1 large SG tube flaw.

18

19 Case-2 studies the above scenario with TT600 material and 10 large SG tube flaws in each of 

20 the four SGs.

21

22 Case-3 studies the above scenario with TT690 material and 5 large SG tube flaws in each of 

23 the four SGs.

24

25 The C-SGTR calculator is used for the calculations. The margin between HL failure time and 

26 large SG leak time is estimated. The input files used for the three cases are as follows:

27

Plant 

Information 

File Case

TH Scenario File 

Name Flaw File Name

Total # of 

Flaws in all 

SGs

Case-1 ZION600TT TH-wnewbase-short Flaw-W3-50 1

Case-2 ZION600TT TH-wnewbase-short Flaw-Multi-42 42

Case-3 ZION690TT TH-wnewbase-short Flaw-Multi-21-TT690 21

28

29 For comparison with other scenarios, the margin Mt between HL and tube failure is defined as

30

31 Mt = Mean time of likely HL failure – mean time of maximum tube flaw failure in terms of minutes

32

33 Choosing the mean time of likely HL failure and hot tube failure is left to the judgment of the 

34 analyst.

35

36 The relevant scenario parameters are summarized in Figures E-1 and E-2.

37
E-2

1

2

3 Figure E-1 WNEWBASE scenario parameters

4

5 The flaw distributions for TT600 and TT690 SG tube materials are summarized in Figures E-3 

6 and E-4.

7

0

500

1000

1500

2000

2500

3000

0.00 50.00 100.00 150.00 200.00 250.00 300.00 350.00

Time in Minutes

delta P in psi Avr. Hot Tube Temp C HT
E-3

1

2

3 Figure E-2 Delta T (in degrees C) between HL and hot tube—WNEWBASE

4

0

100

200

300

400

500

600

0.00 50.00 100.00 150.00 200.00 250.00 300.00 350.00

Axis Title

Time in Minutes

HL to Tube hot side delta T

HL to Tube hot side delta T
E-4

1

2

3 Bin size is ±0.25 centimeter (cm) from the bin center shown above. (For example, bin 0.75 

4 goes from 0.5 to 1.0 cm.)

Flaw Bin (cm) # of Flaws

0.25 138

0.75 270

1.25 189

1.75 99

2.25 44

2.75 17

3.25 5

3.75 10

4.25 3

Total = 775

5

Average Size = 1.1 cm Average Depth = 13%

Largest flaw is 4.46 cm (1.76 in.) in size with a depth of 

32%.

6

7 Figure E-3 Histogram for flaw distribution (by size) for TT600

8 Total of 10 flaw samples for a Zion-like SG with 3,880 TT600 tubes after the 15th “cycle”; all 

9 flaws are wear type

10

138

270

189

99

44

17

5 10 3

0

50

100

150

200

250

300

0.25 0.75 1.25 1.75 2.25 2.75 3.25 3.75 4.25

#

o

f

F

l

a

w

s

i

n

B

i

n

Length in cms up to the value shown

TT600 Flaws for 10 SGs 

Distribution by Length in cm

Example: there are 270 flaws larger 

than 0.25 cm in length; smaller or equal 

to 0.75 cm in length. 
E-5

1

2

Total # of Flaws = 421

Average Size = 1.1 cm

Average Depth = 13%

Max Length = 4.4 cm

Max Depth = 47%

3

Largest flaw is 4.4 cm in size with a depth of 20%.

Deepest flaw is 47% with a size 1.8 cm.

4

5 Figure E-4 Histogram for flaw distribution (by size) for TT690

6 Total of 10 flaw samples for a Zion-like SG with 3,880 TT690 tubes after the 15th “cycle”; all 

7 flaws are wear type

8

9 Note: All flaws 40% or deeper and generated before K=15 are assumed identified and 

10 removed, by plugging the tubes. Thus, only flaws 40% or deeper that are generated in the last 

11 cycle would show up in the flaw samples.

12

13 E.2 Case-1: WNEWBASE with 1 Large Flaw and TT600

14

15 The case with TT600 and a single large flaw of W3-50 (wear type flaw with length 3 cm 

16 (1.18 inches [in.]) and depth 50 percent) produced the results shown in Table E-1.

0

20

40

60

80

100

120

140

160

0.25 0.75 1.25 1.75 2.25 2.75 3.25 3.75 4.25

Midpoint of Bin in cm

# of Flaws for 10 SGs with TT690 after the 15th 

Cycle

# of Flaws
E-6

1

Table E-1 WNEWBASE Results for Case-1 2

3

Time in 

Hours

Time in 

Seconds

HL Failure 

Prob

Surge Line 

Failure Prob Amean cm2 A75 cm2 A95 cm2

3.52 12656 0.00 0.00 0.00 0.00 0.00

3.53 12716 0.00 0.00 0.00 0.00 0.00

3.55 12776 0.00 0.00 0.00 0.00 0.00

3.56 12830 0.02 0.00 0.00 0.00 0.00

3.58 12884 0.07 0.00 0.00 0.00 0.00

3.59 12938 0.17 0.00 0.00 0.00 0.00

3.61 12992 0.33 0.00 0.00 0.00 0.00

3.62 13048 0.55 0.00 0.00 0.00 0.00

3.63 13084 0.70 0.00 0.00 0.00 0.00

3.64 13090 0.72 0.00 0.00 0.00 0.00

3.64 13096 0.75 0.00 0.00 0.00 0.00

3.64 13108 0.79 0.00 0.00 0.00 0.00

3.65 13132 0.86 0.00 0.00 0.00 0.00

3.66 13162 0.91 0.00 0.00 0.00 0.00

3.67 13204 0.97 0.00 0.00 0.00 0.00

3.68 13246 0.99 0.00 0.00 0.00 0.00

3.69 13288 1.00 0.00 0.00 0.00 0.00

3.70 13330 1.00 0.00 0.00 0.00 0.00

3.84 13812 1.00 0.19 0.01 0.00 0.00

3.84 13836 1.00 0.22 0.05 0.00 0.00

3.85 13872 1.00 0.26 0.56 1.30 2.02

3.87 13938 1.00 0.32 3.23 4.47 4.93

3.89 14012 1.00 0.43 4.40 4.66 4.94

3.91 14078 1.00 0.50 4.46 4.66 4.94

3.93 14150 1.00 0.59 4.46 4.67 4.94

.....

4.88 17556 1.00 0.99 4.47 4.67 4.96

4.94 17778 1.00 0.99 4.47 4.67 4.96

5.00 18000 1.00 0.99 4.47 4.67 4.96

4

5 The conclusions are:

6

7 • HL fails at 217 minutes.

8 • Hot tube fails at 232 minutes.

9 • Surge line fails at 233 minutes.

• Expected value of the maximum SG tube leak area reached is 4.5 cm2

(0.69 in.2 10 ).

• Maximum flow area from a single tube is 6.1 cm2 (0.94 in.

2 11 ).

12 • Margin is -15 minutes.

13
E-7

Because the maximum leak area of 6 cm2 (0.93 in.2 1 ) (critical leak area) is not in this case 

2 reached, the margin is defined as:

3

4 Margin = {time at which HL failure probability exceeds 50%} –

5 {time at which integrated tube leak probability exceeds 50% of critical leak area}

6

7 E.3 Case-2: WNEWBASE with 42 Flaws and TT600

8

9 A second case is run as follows.

10

11 From the 10 flaw samples generated for TT600, 42 flaws of largest size and also largest depth 

12 are chosen. This corresponds to about 10 large flaws per SG. Other parameters of this case 

13 are the same as the one discussed above. All flaws are placed in hot tubes.

14

15 Out of the 42 flaws modeled for this case:

16

17 Largest flaw is 4.46 cm (1.76 in.) in size with a depth of 32 percent.

18 Deepest flaw is 40 percent with a size of 0.83 cm (0.32 in.).

19

20 The results are summarized in Tables E-2 and E-3.

21

22 Max # of tube-equivalent failures = 21 tubes at 250 minutes

23

24 Margin = -15 minutes

25

(Margin = HL fails 100% - Hot tube fails 6 cm2 [0.93 in.2 26 ])

27
E-8

Table E-2 Summary Output for the Final Scenario with 42 “Large” Flaws 1

2

Time in Minutes

NUREG/CR-6995 Calculator Comment

Event starts 000 000

SGs dryout 100

Evacuation starts 120

HL fails 14% 215

First fuel rod clad rupture 217

HL fails 54% 217

HL fails 100% 221

HL 1 fails by creep rupture 227

Surge line fails 16% 232

Hottest tube creep rupture failure 233

Surge line fails 55% 236

Hot tube fails 6 cm2 (0.93 in.2) (1-tube 

equivalent) 236

Hot tube fails 22 cm2 (3.41 in.2) (4-tube 

equivalent) 238

Hot tube fails max 125 cm2 (19.375 in.2)(21-tube 

equivalent) 252

Surge line fails 100% 280

Evacuation ends for internal events 360

Evacuation ends for external events 600

Margin = HL fails 100% - Hot tube fails 6 cm2

(0.93 in.2) -15

Note: Surge Line results are given for completeness only. The SL correlation and materials assumed may need 

further examination, but not needed for the purposes of this analysis.

3
E-9

Table E-3 WNEWBASE Results for Case-2 1

2

Time in 

Hours

Time in 

Minutes

HL Failure 

Prob

Surge Line 

Failure Prob Amean cm2 A75 cm2 A95 cm2

3.52 211 0.00 0.00 0.00 0.00 0.00

3.54 212 0.00 0.00 0.00 0.00 0.00

3.56 213 0.01 0.00 0.00 0.00 0.00

3.57 214 0.04 0.00 0.00 0.00 0.00

3.59 215 0.14 0.00 0.00 0.00 0.00

3.61 216 0.31 0.00 0.00 0.00 0.00

3.62 217 0.54 0.00 0.00 0.00 0.00

3.64 218 0.78 0.00 0.00 0.00 0.00

3.65 219 0.87 0.00 0.00 0.00 0.00

3.65 219 0.94 0.00 0.00 0.00 0.00

3.67 220 0.99 0.00 0.00 0.00 0.00

3.69 221 1.00 0.00 0.00 0.00 0.00

3.70 222 1.00 0.00 0.00 0.00 0.00

3.72 223 1.00 0.00 0.00 0.00 0.00

3.80 228 1.00 0.00 0.00 0.00 0.00

3.80 228 1.00 0.00 0.00 0.00 0.00

3.81 229 1.00 0.00 0.00 0.00 0.00

3.82 229 1.00 0.01 0.00 0.00 0.00

3.83 230 1.00 0.03 0.00 0.00 0.00

3.84 230 1.00 0.08 0.00 0.00 0.00

3.85 231 1.00 0.10 0.00 0.00 0.00

3.86 232 1.00 0.16 0.00 0.00 0.00

3.89 233 1.00 0.28 0.01 0.00 0.00

3.91 235 1.00 0.41 0.46 0.61 0.89

3.94 236 1.00 0.55 5.40 6.40 9.90

3.96 238 1.00 0.67 22.00 24.00 27.00

3.99 239 1.00 0.76 36.00 38.00 40.00

4.02 241 1.00 0.85 44.00 45.00 45.00

4.05 243 1.00 0.89 49.00 50.00 54.00

4.08 245 1.00 0.91 71.00 75.00 81.00

4.12 247 1.00 0.93 103.00 105.00 110.00

4.16 250 1.00 0.95 123.00 125.00 127.00

4.20 252 1.00 0.96 125.00 126.00 127.00

4.24 255 1.00 0.97 125.00 126.00 127.00

4.61 277 1.00 0.98 125.00 126.00 127.00

4.67 280 1.00 0.99 125.00 126.00 127.00

5.00 300 1.00 0.99 125.00 126.00 127.00

3

4
E-10

1 E.4 Case-3: WNEWBASE with 21 Flaws and TT690

2

3 A third case is run as follows.

4

5 From the 10 flaw samples generated for TT690, 21 flaws of largest size and also largest depth 

6 are chosen. This corresponds to about 2 large flaws per SG. Other parameters of this case are 

7 the same as the one discussed above.

8

9 Out of the 21 flaws modeled for this case:

10

11 Largest flaw is 4.4 cm (1.73 in.) in size with a depth of 20 percent.

12 Deepest flaw is 47 percent with a size 1.8 cm (0.71 in.).

13

14 The results are summarized in Table E-4. The margin is -7 minutes. Max # of tube-equivalent 

15 failures is nine and occurs at 4 hours.

16

17 Max # of tube-equivalent failures = 9 tubes at 4 hours

18

19 Margin = -7 minutes

20

(Margin = HL fails 100% - Hot tube fails 6 cm2 21 )

22
E-11

Table E-4 WNEWBASE Results for Case-3 with TT690 1

2

Time in 

Hours

Time in 

Seconds

HL Failure 

Prob

Surge Line 

Failure Prob Amean cm2 A75 cm2 A95 cm2

3.61 216 0.35 0.00 0.01 0.02 0.02

3.62 217 0.54 0.00 0.02 0.02 0.03

3.64 218 0.79 0.00 0.04 0.05 0.06

3.65 219 0.88 0.00 0.05 0.06 0.07

3.65 219 0.93 0.00 0.07 0.08 0.09

3.67 220 0.98 0.00 0.11 0.12 0.13

3.69 221 1.00 0.00 0.17 0.18 0.20

3.70 222 1.00 0.00 0.24 0.25 0.28

3.72 223 1.00 0.00 0.33 0.35 0.39

3.73 224 1.00 0.00 0.40 0.42 0.47

3.74 224 1.00 0.00 0.46 0.49 0.54

3.75 225 1.00 0.00 0.56 0.60 0.66

3.75 225 1.00 0.00 0.69 0.73 0.80

3.76 226 1.00 0.00 0.97 1.03 1.13

3.77 226 1.00 0.00 1.60 1.70 1.80

3.78 227 1.00 0.00 2.40 2.50 2.80

3.79 227 1.00 0.00 3.20 3.40 3.70

3.80 228 1.00 0.00 4.10 4.30 4.70

3.80 228 1.00 0.00 5.50 5.80 6.30

3.81 229 1.00 0.00 7.50 7.90 8.50

3.82 229 1.00 0.01 10.10 10.60 11.30

3.83 230 1.00 0.02 13.20 13.80 14.90

3.84 230 1.00 0.07 16.30 17.10 18.00

3.85 231 1.00 0.11 19.30 20.00 20.80

3.86 232 1.00 0.18 24.70 25.40 26.60

3.89 233 1.00 0.32 31.10 31.80 33.00

3.91 235 1.00 0.44 36.80 37.50 38.70

3.94 236 1.00 0.60 42.80 43.60 44.70

3.96 238 1.00 0.70 48.10 49.00 49.90

3.99 239 1.00 0.80 50.50 51.10 52.00

4.02 241 1.00 0.90 51.70 52.20 53.00

4.05 243 1.00 0.90 51.80 52.30 53.00

4.08 245 1.00 0.90 51.80 52.30 53.00

3

F-1

1 APPENDIX F

2

3 PRESSURE-INDUCED C-SGTR—SUPPORTING CALCULATIONS

4

5

6 F.1 Estimation of C-SGTR for a Flaw Bin

7

8 The loss of main feed water anticipated transient without scram (ATWS) event is selected for 

9 evaluating the bounding scenario. An analysis was performed using a primary pressure of 

10 22 megapascals (MPa) (3,200 pounds per square inch [psi]), a primary temperature of 

11 370 degrees C (698 degrees F), and a secondary pressure of 6.89 MPa (1,000 psi). The 

12 temperature of 370 degrees C (698 degrees F) was selected because it is the saturated 

13 temperature of water/steam at 22 MPa (3,200 psi). Table F-1 and Figure F-1 show the thermal14 hydraulic TH input file for the analysis.

15

Table F-1 TH Input File for C-SGTR for Simulating ATWS Scenarios 16

17

Time (s) Primary 

Pressure 

(pa)

Surge Line 

Temp (°C)

HL

Temp (°C)

Hot SG 

Tube 

Temp 

(°C)

Cold SG 

Tube

Temp (°C)

Secondary 

Pressure 

(pa)

0.0 1.56E+7 311.21 311.21 311.21 311.21 6.10E+6

2.0 2.20E+7 370.00 370.00 370.00 370.00 6.10E+6

4.0 2.20E+7 370.00 370.00 370.00 370.00 6.10E+6

6.0 2.20E+7 370.00 370.00 370.00 370.00 6.10E+6

8.0 2.20E+7 370.00 370.00 370.00 370.00 6.10E+6

10.0 2.20E+7 370.00 370.00 370.00 370.00 6.10E+6

20.0 2.20E+7 370.00 370.00 370.00 370.00 6.10E+6

30.0 2.20E+7 370.00 370.00 370.00 370.00 6.10E+6

40.0 1.55E+7 370.00 370.00 370.00 370.00 6.10E+6

50.0 1.55E+7 370.00 370.00 370.00 370.00 6.10E+6

60.0 1.55E+7 370.00 370.00 370.00 370.00 6.10E+6

120.0 1.55E+7 370.00 370.00 370.00 370.00 6.10E+6

18

19 Similarly Table F-2 and Figure F-2 show the TH behavior assumed for steam line break (SLB)

20 scenarios.

21

22 A set of case runs were performed using the consequential steam generator tube rupture 

23 (C-SGTR) software, the TH files discussed earlier, and a set of flaws representing the expected 

24 flaws plus one large flaw. An example of flaw set consisting of the expected flaw set plus one 

25 large flaw of 70-percent depth and 3 centimeter (cm) (1.2 inches [in.]) length is shown in Table 

26 F-3.

27

28 Portions of the two C-SGTR output files are shown in Tables F-4 and F-5 (i.e. “intermediate 

29 Probability” and “cumulative leakArea” files). Table F-4 shows the flaw failure results for the 

30 flaw #126 which corresponds to a large flaw when SLB TH file is used. The probability of tube

31 failure for a flaw with 70-percent depth and 3 cm (1.2 in.) length is about 0.57 during a severe 

32 SLB scenario. It also appears that the upper bound of the leak rate (95 percentile values) is 
F-2

1 about 4.529, which is approximately equivalent to guillotine break of one tube in the 

2 representative CE plant. This is further confirmed by examining the Cumulative Leak Area 

3 output in Table F-5. Table F-5 also shows that the expected set of flaws do not contribute to C4 SGTR during an SLB accident.

5

6

7

8 Figure F-1 Assumed TH behavior for ATWS for CSGTR analysis

9

Table F-2 TH Input File for C-SGTR for Simulating SLB Scenarios 10

11

Time (s) Primary 

Pressure 

(pa)

Surge Line 

Temp (°C)

HL

Temp (°C)

Hot SG 

Tube 

Temp 

(°C)

Cold SG 

Tube

Temp (°C)

Secondary 

Pressure 

(pa)

0.0 1.56E+7 311.21 311.21 311.21 311.21 6.10E+6

2.0 1.56E+7 300.00 300.00 300.00 300.00 9.60E+4

4.0 1.56E+7 300.00 300.00 300.00 300.00 9.60E+4

6.0 1.56E+7 300.00 300.00 300.00 300.00 9.60E+4

8.0 1.56E+7 300.00 300.00 300.00 300.00 9.60E+4

10.0 1.56E+7 300.00 300.00 300.00 300.00 9.60E+4

20.0 1.56E+7 300.00 300.00 300.00 300.00 9.60E+4

30.0 1.56E+7 300.00 300.00 300.00 300.00 9.60E+4

40.0 1.56E+7 300.00 300.00 300.00 300.00 9.60E+4

50.0 1.56E+7 300.00 300.00 300.00 300.00 9.60E+4

60.0 1.56E+7 300.00 300.00 300.00 300.00 9.60E+4

120.0 1.56E+7 300.00 300.00 300.00 300.00 9.60E+4

12

0

500

1000

1500

2000

2500

300

310

320

330

340

350

360

370

380

0 20 40 60 80 100 120 140

Temp (Deg. C)

Time (s)

Tube temp (Deg. C)

Delta P (psi)-2ndary Y-axis
F-3

1

2

3 Figure F-2 Assumed TH behavior for SLB for CSGTR analysis

4

Table F-3 Example of Expected Flaw Set Plus One Large Flaw of 70% Depth and 3 cm 5

Length for a CE Plant 6

7

Flaw 

orientation

Flaw 

length

(cm)

Circ. 

Angle

Depth Axial 

Location 

(not 

used)

Flaw 

type

SD of 

Error

Mean of 

Error

Flow 

reduction 

factor

A 1.5 0 0.05 0 2 0.03 0 1

A 1.5 0 0.05 0 2 0.03 0 1

A 1.5 0 0.05 0 2 0.03 0 1

A 1.5 0 0.05 0 2 0.03 0 1

A 1.5 0 0.05 0 2 0.03 0 1

A 1.5 0 0.05 0 2 0.03 0 1

A 2.5 0 0.05 0 2 0.03 0 1

A 2.5 0 0.05 0 2 0.03 0 1

A 2.5 0 0.05 0 2 0.03 0 1

A 3.5 0 0.05 0 2 0.03 0 1

--- --- --- --- --- --- --- --- ---

--- --- --- --- --- --- --- --- ---

A 1.5 0 0.35 0 2 0.03 0 1

A 1.5 0 0.35 0 2 0.03 0 1

A 3.0 0 0.70 0 2 0.03 0 1

8

0

500

1000

1500

2000

2500

298

300

302

304

306

308

310

312

0 20 40 60 80 100 120 140

Temp (Deg. C)

Time (s)

Hot SG Tube Temp (oC)

Delta P (psi)

Delta P (Psi)
F-4

Table F-4 Results of Intermediate File from CSGTR for Flaw #126, at 70% Depth and 3 cm 1

2 Length for a CE Plant and TH File Representing SLB

3

Flaw #

Time

(s)

Pleak

Pburst

PCR

(NA)

Abm

(mean 

burst area)

Ab0.05

(5% burst 

area)

Ab0.95

(95% burst 

area)

Alm

(mean leak

area)

Al0.05

(5% leak

area)

Al0.95

(95% leak 

area)

Acrm

(mean CR 

area)

Acr0.05

(5% CR

area)

Acr0.95

(95% CR 

area)

126 0 0.000 0.000 0 0.000 0 0.000 0.000 0 0.000 0.000 0 0

126 2 0.569 0.569 0 2.546 0 4.528 2.546 0 4.528 0.000 0 0

126 4 0.569 0.569 0 2.798 0 4.528 2.798 0 4.528 2.546 0 0

126 6 0.569 0.569 0 2.939 0 4.528 2.939 0 4.528 2.798 0 0

126 8 0.569 0.569 0 3.018 0 4.528 3.018 0 4.528 2.939 0 0

126 10 0.569 0.569 0 3.119 0 4.529 3.119 0 4.529 3.018 0 0

126 20 0.569 0.569 0 3.119 0 4.529 3.167 0 4.529 3.119 0 0

126 30 0.569 0.569 0 3.119 0 4.529 3.184 0 4.529 3.119 0 0

126 40 0.569 0.569 0 3.119 0 4.529 3.210 0 4.529 3.119 0 0

126 50 0.569 0.569 0 3.119 0 4.529 3.244 0 4.529 3.119 0 0

126 60 0.569 0.569 0 3.119 0 4.529 3.266 0 4.529 3.119 0 0

126 120 0.569 0.569 0 3.119 0 4.529 3.291 0 4.529 3.119 0 0

4

Table F-5 Results of Cumulative Leak Area File From CSGTR for Expected Flaws Plus 5

6 One Flaw at 70% Depth and 3 cm Length for a CE Plant and TH File Representing SLB

7

Time Am A0.05 A0.25 A0.50 A0.75 A0.95 Asd

0 0.000 0 0 0.00 0.00 0.00 0.00

2 2.546 0 0 4.41 4.49 4.53 2.213

4 2.798 0 0 4.45 4.49 4.53 2.160

6 2.939 0 0 4.45 4.49 4.53 2.116

8 3.018 0 0 4.45 4.49 4.53 2.087

10 3.119 0 0 4.45 4.49 4.53 2.044

20 3.167 0 0 4.46 4.49 4.53 2.021

30 3.184 0 0 4.46 4.49 4.53 2.013

40 3.210 0 0 4.46 4.49 4.53 1.999

50 3.245 0 0 4.46 4.49 4.53 1.981

60 3.266 0 0 4.46 4.49 4.53 1.969

120 3.291 0 0 4.46 4.49 4.53 1.954

8

9 The results of these evaluations for the representative CE plant are summarized in Tables F-6 

10 and F-7 for ATWS and SLB scenarios, for Inconel 690, and considering all bins of large. The 

11 results show that a large flaw with 70-percent depth has about 70-percent chance of failure 

12 during ATWS and 57-percent probability of failure during SLB. Furthermore, the results also 

13 showed that the minimum size of the flaw has to be at least 3 cm (1.2 in.) to create large 

14 enough leak area to be considered as C-SGTR. Limited runs were also performed for the 

15 representative Westinghouse plant and Inconel 600 tubes for comparison with the CE results. 

16 These runs indicated that the probability of the tube failure is slightly lower for the Westinghouse 

17 plant due to the differences between material properties of Inconel 600 and Inconel 690. For 

18 example, for a flaw with 70-percent depth, the tube failure probability for Westinghouse is about 

19 0.46 rather than 0.57 estimated for the CE plant. The comparison also revealed that the leak 

20 area for the Westinghouse plant is slightly larger because of its larger tube diameter.
F-5

1 For example, for a 3 cm (1.2 in.) flaw, the leak area for the representative Westinghouse plant 

was estimated to be about 4.93 square centimeter (cm2

) (0.76 square inch [in.2 2 ]) compared to 

the leak area of 4.46 cm2 (0.69 in.

2 3 )for the representative CE plant.

4

Table F-6 Case Results of Pressure Induced C-SGTR during ATWS 5

6

Case Run Am Pl Pb

Expected Flaw Sample 0.000 0.000 0.000

Expected Flaw Sample + 1 Flaw with 60% 

depth and 3 cm length

0.004 0.001 0.001

Expected Flaw Sample + 1 Flaw with 70% 

depth and 3 cm length

4.400 0.676 0.676

Expected Flaw Sample + 1 Flaw with 80% 

depth and 3 cm length

4.397 1.000 1.000

Expected Flaw Sample + 1 Flaw with 60% 

depth and 4 cm length

0.009 0.002 0.002

Expected Flaw Sample + 1 Flaw with 70% 

depth and 4 cm length

3.659 0.687 0.687

Expected Flaw Sample + 1 Flaw with 80% 

depth and 4 cm length

4.497 1.000 1.000

7

8 Table F-7 Case Results of Pressure Induced C-SGTR during SLB

9

Case Run Am Pl Pb

Expected Flaw Sample 0.00 0.00 0.00

Expected Flaw Sample + 1 Flaw with 60% 

depth and 3 cm length

0.00 0.00 0.00

Expected Flaw Sample + 1 Flaw with 70% 

depth and 3 cm length

3.29 0.57 0.57

Expected Flaw Sample + 1 Flaw with 80% 

depth and 3 cm length

4.40 1.00 1.00

Expected Flaw Sample + 1 Flaw with 60% 

depth and 4 cm length

0.00 0.00 0.00

Expected Flaw Sample + 1 Flaw with 70% 

depth and 4 cm length

4.40 0.55 0.55

Expected Flaw Sample + 1 Flaw with 80% 

depth and 4 cm length

4.40 1.00 1.00

10

11 The probability of CSGTR for the representative CE plant bounds the C-SGTR probability for 

12 the representative Westinghouse plant. Furthermore, the C-SGTR failure probability for ATWS 

13 bounds the C-SGTR failure probability for SLB scenarios. Therefore, the bounding probability of 

14 C-SGTR for both ATWS and SLB scenarios, covering both Westinghouse and CE plants, for 

15 each of the flaw bins tabulated in Section 7.1, is provided below in Tables F-8 and F-9.

16

17 The probability that the SG tubes fail, but it does not create sufficient leak rate to be considered 

18 as C-SGTR (i.e., called SGTR-Leak), is shown in Table F-9. These are due to flaws with depth 

19 of 70 percent or more but length of 3 cm (1.18 in.) or less.

20
F-6

Table F-8 Bounding C-SGTR Probability per a Flaw Bin To Be Used for Both SLB and 1

ATWS Scenarios for Westinghouse and CE Plants 2

3

Depth/ 

Length

0 cm to 

1 cm

1 cm to 

2 cm

2 cm to 

3 cm

3 cm to 

4 cm

4 cm to 

5 cm

5 cm to 

6 cm

0.1 to 0.6 0 0 0 0 0 0

0.6 to 0.7 0 0 0 1.0E-03 1.0E-03 1.0E-03

0.7 to 0.8 0 0 0 5.7E-01 5.7E-01 5.7E-01

0.8 to 0.9 0 0 0 1.0E+00 1.0E+00 1.0E+00

4

Table F-9 Bounding Probability for SGTR – Leak per a Flaw Bin To Be Used for Both 5

SLB and ATWS Scenarios for Westinghouse and CE Plants 6

7

Depth/ 

Length

0 cm to 

1 cm

1 cm to 

2 cm

2 cm to 

3 cm

3 cm to 

4 cm

4 cm to 

5 cm

5 cm to 

6 cm

0.1 to 0.6 0 0 0 0 0 0

0.6 to 0.7 0 0 0 0 0 0

0.7 to 0.8 0.57 0.57 0.57 0 0 0

0.8 to 0.9 1.00 1.00 1.00 0 0 0

8

9 For both Inconel 600 and 690 SG Tubes, the probability that a flaw belongs to a flaw bin is 

10 reproduced from Table 7-3 and provided below in Table F-10. The probability of a flaw residing 

11 in a flaw bin multiplied by the probability of C-SGTR will yield the probability of C-SGTR per flaw 

12 tubes. This is provided in Table F-11. The bounding probability that a flawed tube results in 

13 C-SGTR during ATWS or SLB is estimated to be approximately 2.3 E-5. Similarly, bounding 

14 probability that a flawed tube fails but not with sufficient leak area to be considered C-SGTR but 

15 considered as SGTR-Leak is 1.4E-4.

16

Table F-10 Probability that a Detected Flaw Belongs to a Bin Size at 15 EFPY 17

18

Depth/ 

Length

0 cm to 

1 cm

1 cm to 

2 cm

2 cm to 

3 cm

3 cm to 

4 cm

4 cm to 

5 cm

5 cm to 

6 cm

Total

0 to 0.1 2.74E-3 4.62E-2 2.23E-2 5.38E-3 1.04E-3 1.80E-4 7.78E-2

0.1 to 0.2 1.86E-2 3.14E-1 1.52E-1 3.66E-2 7.08E-3 1.23E-3 5.29E-1

0.2 to 0.3 9.59E-3 1.62E-1 7.81E-2 1.89E-2 3.64E-3 6.31E-4 2.73E-1

0.3 to 0.4 3.09E-3 5.21E-2 2.52E-2 6.07E-3 1.17E-3 2.03E-4 8.78E-2

0.4 to 0.5 8.47E-4 1.43E-2 6.90E-3 1.66E-3 3.22E-4 5.57E-5 2.41E-2

0.5 to 0.6 2.14E-4 3.61E-3 1.74E-3 4.21E-4 8.13E-5 1.41E-5 6.08E-3

0.6 to 0.7 5.14E-5 8.67E-4 4.19E-4 1.01E-4 1.95E-5 3.38E-6 1.46E-3

0.7 to 0.8 1.19E-5 2.01E-4 9.73E-5 2.35E-5 4.54E-6 7.86E-7 3.39E-4

0.8 to 0.9 2.71E-6 4.57E-5 2.21E-5 5.32E-6 1.03E-6 1.78E-7 7.70E-5

Total 3.52E-2 5.93E-1 2.86E-1 6.91E-2 1.34E-2 2.31E-3 ~1
F-7

1

2 Table F-11 C-SGTR Probability for SLB or ATWS Scenarios per Flaw

3

Depth 0 cm to 1 cm

0.0 to 0.5 0 

0.6 to 0.7 1.24E-7

0.7 to 0.8 1.64E-5

0.8 to 0.9 6.52E-6

Total 2.30E-5

4

5 F.2 Estimation of Pressure Induced C-SGTR Probability

6

7 For ATWS scenarios, all SGs will be exposed to potential high RCS pressure, which could 

8 cause C-SGTR. The probability of C-SGTR is estimated by considering the total number of 

9 flaws at cycle 15 for the representative Westinghouse and CE plants.

10

11 For most of SLB scenarios, one or more SGs could be exposed to the pressure environment 

12 conducive to the pressure induced C-SGTR. This would depend on what has led to secondary 

13 depressurization and how many MSIVs have closed. A specific SG may be of interest for some 

14 scenarios of SLB, rather than all SGs.

15

16 The bounding C-SGTR probability for ATWS and SLB, is therefore, estimated twice; once for 

17 one specific SG, and then for all SGs. This is shown below:

18

19 Representative Westinghouse Plant at Cycle 15

20 Expected number of flaws in each SG = 79

21 Expected number of flaws in all four SGs = 315

Probability of C-SGTR for the specific SG = (1-(1-2.3E-5)79 22 ) = 2.5E-3

Probability of C-SGTR for ATWS for any of four SGs = (1-(1-2.3E-5)315 23 ) = 0.01

24 Representative CE Plant at Cycle 15

25 Expected number of flaws in each SG = 125

26 Expected number of flaws in both SGs = 253

Probability of C-SGTR for the specific SG = (1-(1-2.3E-5)125 27 ) = 4.0E-3

Probability of C-SGTR for ATWS for any of four SGs = (1-(1-2.3E-5)253 28 ) = 8.0E-3

29

30 The above values are used in Section 7.4 and Appendix C.

31

32 F.3 Estimation of Pressure Induced SGTR-Leak Probability

33

34 The bounding SGTR-Leak probability for ATWS and SLB is estimated twice; once for one 

35 specific SG, and then for all SGs. This is shown below:

36
F-8

1 SGTR-Leak Probability for Representative Westinghouse Plant at Cycle 15

2 Expected number of flaws in each SG = 79

3 Expected number of flaws in all four SGs = 315

Probability of C-SGTR for the specific SG = (1-(1-1.4E-4)79 4 ) = 1.1E-02

Probability of C-SGTR for ATWS for any of four SGs =(1-(1-1.4E-4)315 5 ) = 4.3E-02

6 SGTR-Leak Probability for Representative CE Plant at Cycle 15

7 Expected number of flaws in each SG = 125

8 Expected number of flaws in both SGs = 253

Probability of C-SGTR for the specific SG = (1-(1-1.4E-4)125 9 ) = 1.7E-2

Probability of C-SGTR for ATWS for any of four SGs = (1-(1-1.4E-4)253 10 ) = 3.5E-2

11

12 The above values are used in Appendix C.
G-1

1 APPENDIX G

2

3 ESTIMATING THE ENTRY FREQUENCY FROM LEVEL 1 PRA FOR 

4 LEVEL 2 PRA ANALYSIS

5

6

7 G.1 Zion Nuclear Power Plant (ZNPP)

8

9 ZNPP was also selected for developing the Level 2 probabilistic risk assessment (PRA) models 

10 to ensure consistency with the thermal-hydraulic (TH) analyses results. No current PRA or 

11 standardized plant analysis risk (SPAR) models are available for ZNPP and ZNPP units are no 

12 longer in operation. The estimates for a prolonged station blackout (SBO) condition, as the 

13 entry point for the Level 2 PRA was, therefore, estimated based on the plant design features 

14 and information from vintage ZNPP PRA documents. The process of developing the Level 2 

15 PRA entry condition for containment bypass resulting from C-SGTR for Unit 1 of ZNPP is 

16 discussed in this section. All potential conditions from internal and external hazards resulting in 

17 a prolonged station blackout are considered.

18

19 G.1.1 Internal Event

20

21 Relevant information for ZNPP is provided in Table G-1. The frequency of all scenarios 

22 resulting in prolonged SBOs (greater than battery duration of 6 hours) was estimated for internal 

23 initiating events excluding internal fires and floods (i.e., from Table 2.2-2 of NUREG/CR-4551). 

24 The overall frequency estimated from this process for ZNPP is about 5.23E-6 per year.

25

26 The reasonableness of the overall frequency of prolonged SBO was examined using the current 

27 information on loss of offsite power from NUREG/CR-6890. Both single and dual unit loss of 

28 offsite power (LOOP) frequencies, along with the latest common cause alpha factor model in 

29 SPAR, were used for this independent examination.

30

31 The frequencies of single- and dual-unit LOOP exceeding 6 hours were estimated as 7.72E-4 

32 and 1.64E-3. A success criterion for a dual LOOP event was defined as having at least three 

33 emergency diesel generators (EDGs) operating. This success criterion could include any of the 

34 following:

35

36 • at least the three dedicated EDGs operating or

37

38 • two dedicated EDGs operating in one Unit and a swing EDG aligned to the other unit. 

39 This configuration will meet all the operational requirements for the service water and the 

40 component cooling water (CCW) systems.

41

42 For single LOOP events the success criteria of two dedicated EDGs operating or one dedicated 

43 EDG in the affected Unit plus the operation of the shared EDG was considered as success.

44

45 For a dual unit LOOP, common cause failures of three out of five EDGs, and for a single LOOP, 

46 common cause failures of three out of three EDGs, will result in SBO.

47
G-2

Table G-1 Information from Zion Nuclear Station 1

2

Systems System Features

Emergency Power System

a. Each unit consists of 3 4160-VAC class 1E buses, each 

feeding 1 480-VAC class 1E bus and motor control center.

b. For the 2 units there are 5 diesel generators, with 1 being a 

swing diesel generator shared by both units.

c. 3 trains of dc power are supplied from the inverters and 3 unit 

batteries. The battery duration is 6 hours.

Auxiliary Feedwater System

a. Two 50 percent motor-driven pumps and one 100 percent 

turbine-driven pump.

b. Pumps take suction from own unit condensate storage tank 

(CST) but can be manually cross-tied to the other unit’s CST.

Service Water (SW)

a. Shared system between both units.

b. Consists of 6 pumps and 2 supply headers.

c. Cools component cooling heat exchangers, containment fan 

coolers, diesel generator coolers, auxiliary feedwater pumps.

d. 2 out of 6 pumps can supply sufficient flow.

Component Cooling Water 

(CCW)

a. Shared system between both units.

b. Consists of 5 pumps, 3 heat exchangers, and 2 surge tanks.

c. Cools RHR heat exchangers, reactor coolant pump motors 

and thermal barriers, RHR pumps, SI pumps, and charging 

pumps.

d. One of 5 pumps can provide sufficient flow.

Secondary Relief

a. steam dump valves

b. atmospheric dump valves (1per SG)

c. safety relief valves

Primary Relief a. 2 PORVs

b. 3 safety relief valves

Containment

a. large, dry, pre-stressed concrete

b. 2.6 million cubic foot volume

c. 49 psig design pressure

Reproduced from NUREG/CR-3300, NUREG/CR-4550, and NUREG/CR-4551

3

4 The point estimate of the frequency for prolonged SBOs (entry point for Level 2 PRA), was 

5 obtained for a plant with the features same as ZNPP including the contribution of extreme 

6 weather. This value was about 2.1E-6 per year.

7

8 The value estimated independently for the frequency of prolonged SBO did not include all the 

9 contributors to the SBO events. For example, potential test and maintenance unavailability, 

10 human errors in aligning the electrical bus, and CCFs of other electrical components such as 

11 breakers were not included in the model. The comparison of this limited independent estimation 

12 with the PRA results clearly shows that the internal event contribution to the frequency of 

13 prolonged SBO as documented in NUREG/CR-4551 is reasonable.

14

15 G.1.2 Seismic Initiating Event

16

17 An examination of Zion probabilistic safety assessment (PSA) (NUREG/CR-3300, Vol. 1) 

18 indicated that the frequency of loss of total nonrecoverable alternating current (ac) power is 

19 about 5.6E-6 per year because of seismic events. The two major contributors to seismic 

20 induced SBO in ZNPP are:
G-3

1

2 • LOOP because of a seismic event with a median ground acceleration of 0.3 g

3 • failure of SW pumps due to a seismic event with median ground acceleration of 0.63 g

4

5 The failure of service water pumps will result in an eventual failure of EDGs, because SW 

6 supports the operation of EDGs and most of the emergency core cooling system (ECCS)

7 components.

8

9 The failure of SW pumps during a seismic event could result from one or more of the following 

10 reasons:

11

12 • failure of the pumps (the largest contributor)

13 • failure of all the underground SW piping

14 • failure of the crib house roofing

15

16 Considering the seismicity of the area surrounding ZNPP, NUREG/CR-3300 estimated a total 

17 core damage probability of 5.6E-6 per reactor year due to extended SBO beyond the battery 

18 duration.

19

20 G.1.3 Fire Initiating Event

21

22 Zion PSA performed a very limited fire analysis as indicated in NUREG/CR-3300. It basically 

23 identified two areas that contributed the most to fire risk; the auxiliary equipment room and the 

24 cable spreading room. The fire in the auxiliary equipment room damaged cabinets to the extent 

25 that the operators received incorrect diagnostic information. The loss of diagnostic information 

26 also impeded the recovery actions involving auxiliary feedwater or high-pressure injection.

27

28 The fire in the cable spreading room damaged the motor-driven auxiliary feedwater pump power 

29 cables, the turbine-driven auxiliary feedwater (TDAFW) pump failed randomly, and operators 

30 failed to initiate feed-and-bleed operation for decay heat removal. NUREG/CR-3300 did not 

31 agree with the ZNPP assessment of the cable spreading room. As noted in NUREG/CR-3300, 

32 it appears that ZNPP Unit 1 cable spreading room contains the following cables:

33

34 • power feeds for three CCW pumps, and three service water pumps

35 • power feeds for two charging pumps

36 • power feeds for two auxiliary feedwater (AFW) pumps

37 • control cabling for five fan coolers

38 • control cabling for at least two containment spray pumps

39

40 Docketed information from Commonwealth Edison also indicated that the cable spreading room 

41 contains power cables for the steam supply valves of the TDAFW pump, which is separated by 

42 a minimum distance of 20 feet from the motor-driven AFW pump power cables. Information on 

43 the location of safety injection pump cables and the third containment spray pump was not 

44 available at the time of evaluation.

45

46 Based on this information, it appears that a relatively large fire in the cable spreading room 

47 would have similar effect as the total loss of ac. However, the TDAFW is not expected to be 

48 affected and its operation would not be limited by the battery depletion time similar to other 

49 extended SBO scenarios. Because of a lack of detail cable routing and other fire-related 

50 information, NUREG/CR-3300 estimated a core damage probability of about 4.0E-5 per year. 
G-4

1 A re-analysis of this scenario was performed with less conservative assumptions and based on 

2 recent data on ignition, detection, and suppression of fires. Furthermore, for this scenario, the 

3 operation of TDAFW was assumed to be unaffected by the fire and it could only fail because of

4 independent causes from the fire scenario. This updated analysis resulted in an estimated core 

5 damage probability which was much smaller than the bounding estimate reported in 

6 NUREG/CR-3300 (9.5E-7/reactor year (RY)). The assumptions used in this calculation, which 

7 is equivalent to the earlier calculation, are as follows:

8

9 Cable spreading room ignition frequency = 1.9E-3 per year

10 Location and severity factor = 0.1

11 Failure of Halon fire suppression system = 0.05

12 Failure of TDAFW early or late = 0.1

13

14 The initiating event frequency for prolonged SBOs, which is required for the entry point to 

15 Level-2 analysis, should exclude the failure of TDAFW. Therefore, the resulting initiating event 

16 frequency would be about 9.5E-6 per year.

17

18 G.2 Calvert Cliffs Nuclear Power Plant (CCNP)

19

20 Relevant plant information for Calvert Cliffs Units 1 and 2 are provided in Table G-2. Each unit 

21 of Calvert Cliffs is equipped with two TDAFW pumps; and the duration to battery depletion is 

22 nominally 2 hours, although they are expected to last 4 hours in the case that was modeled in 

23 TH runs.

24

25 The scenarios associated with the SBOs with early failures of both TDAFW pumps are 

26 estimated in SPAR model, and are reproduced in Table G-3. The early failures of both TDAFW 

27 pumps was dominated by the operator’s failure to control the flow, causing SG overfill, and 

28 failing the TDAFW by carrying water to turbine. The overall frequency estimated from this 

29 process is about 1.88E-08 and 2.47E-08 per year, for Units 1 and 2, respectively. The higher 

30 contribution for Unit 2 was resulted from the asymmetric dependence on service water (SRW). 

31 For example, EDG 12 can be supplied with cooling water from the SRW system of either Unit 1 

32 or Unit 2.

33

34 For losses of offsite power, especially those related to grid and weather related causes, there is 

35 a high potential that both units experience a loss of offsite power (i.e., dual LOOP scenario). A 

36 rough estimate of the major contributors to the frequency of the early core damage in both units 

37 from the occurrence of a dual LOOP initiator is obtained by the following equation:

38

39 CD due to Dual LOOP = [Frequency of Dual Unit LOOP]* [CCF probability of all Five EDGs]*

40 [Probability the TDAFW fails due to SG overfill in both units]

41

42 Substituting the estimates from the SPAR model,

43

44 [Frequency of Dual Unit LOOP] = [Frequency of LOOP-GR]+LOOP-WR] = 1.86E-02 + 4.83E-03

45 = 2.4E-02,

46 [CCF probability of all Five EDGs directly from SPAR models] = 2.13E-5, and 

47

48 [Probability the TDAFW fails due to SG overfill] = 

49 [SPAR model for failure of both TDAFW failure in one Unit due to overfilling = 0.3*0.12 = 0.036]* 

50 [Conditional Probability of failing both TDAFW due to SG overfill in the second Unit = 0.3; 

51 estimated] = 1.08E-02
G-5

1

2 Single and dual LOOP core damage frequency results for the SBO with the early failures of both 

3 TDAFW pumps are shown in Table G-4 for internal events.

4

Table G-2 Information from Calvert Cliffs Nuclear Station 5

6

Systems System Features

Emergency Power System a. Currently there are 5 diesel generators for the 2 units. One of 

these 5 EDGs is the SBO EDG, which can power any safety 

related 4-kV bus at either unit. The operation of 1 EDG with 

success of 1 TDAFW pump per unit is adequate for a 

long-term SG heat removal. The SBO EDG requires operator 

action to align it to a safety bus and is credited as a recovery 

action in the PRA models.

b. At the time when individual plant evaluation/individual plant 

evaluation for external events (IPE/IPEEE) was performed, 

each unit had a dedicated EDG with 1 shared EDG for both 

units. Therefore, the information contained in IPE/IPEEE 

should be used as a guide, and they are not directly 

applicable.

c. Each unit has 3 4160-VAC Class 1E buses, each feeding 

1 480-VAC Class 1E bus and motor control center.

d. 3 trains of dc power are supplied from the inverters and 3 unit 

batteries. The battery duration is 2 hours, but it is expected to 

last 4 hours during most scenarios.

Auxiliary Feedwater System Each unit is equipped with 2 turbine-driven pumps (TDAFW) and 

1 motor-driven pump (MDAFW). There is a cross connection to 

other unit’s MDAFW discharge line.

Salt Water System (SW) There are 2 cross-tied trains, each with 1 pump and 1 heat 

exchanger. A third pump could also supply either trains if 

needed.

Service Water (SRW) There are 2 trains, each with a salt water pump, a CCW HX, an

SRW HX, and ECCS pump room air cooler. A third pump could 

be aligned to each train if needed.

Component Cooling Water (CCW) The CCW pumps do not restart automatically after a LOOP. The 

operators manually re-establish RCP seal cooling after a LOOP.

Secondary Relief a. 4 turbine bypass valves—TBVs (2 SG)

b. atmospheric dump valve (1 per SG)

d. main steam safety relief valve (8 per SG)

Primary Relief a. 2 reverse-seated PORVs (2400 psi); 

b. the PORVs do not require dc power for once through cooling 

(feed and bleed)

c. 2 block valves that are powered from the opposite 480 VAC 

with respect to their PORVs

d. 2 spring loaded safety relief valves (P>2500 psig)

Containment Large, dry

Note: The information in this table is reproduced from Calvert Cliffs IPE/IPEEE.

7

8 Table G-5 provides similar results for SBO with the failure of TDAFW pumps after the battery 

9 depletion. The core damage frequencies are estimated by removing the probability of SG 

10 overfill and including a probability of about 0.24 for the recovery of power from the EDG or 
G-6

1 offsite (0.7 for recovery of the EDG in 4 hours and 0.34 for recovery of the offsite power from 

2 weather or grid related causes).

3

Table G-3 Core Damage for SBO Scenarios with Early Failure of TDAFWS 4

5

Calvert Cliffs Unit 1 Calvert Cliffs Unit 2

Initiator IE Frequency CDF 

Contribution Initiator IE Frequency

CDF 

Contribution

LoopGR 1.86E-2 1.02E-8 LoopGR 1.86E-2 1.43E-8

LoopPC 2.07E-3 2.15E-10 LoopPC 2.07E-3 3.24E-10

LoopSC 1.04E-2 2.87E-9 LoopSC 1.04E-2 3.99E-9

LoopWR 4.83E-3 5.48E-9 LoopWR 4.83E-3 6.14E-9

Total 3.59E-2 1.88E-8 Total 3.59E-2 2.47E-8

6

Table G-4 CDF for the SBO and the Failures of TDAFWs due to Overfill (for Internal 7

Event Initiators Affecting One or Both Units) 8

9

Affected Unit CDF Estimates (Per Reactor Year)

Unit 1 [only] 1.3E-8 = [1.88E-8 – 5.5E-9]

Unit 2 [only] 1.9E-8 = [2.47E-8 – 5.5E-9]

Both Units 5.5E-9

10

Table G-5 CDF for an SBO and the Failures of All TDAFWs after the Battery Depletion 11

(Internal Event Initiators Affecting One or Both Units) 12

13

Affected Unit CDF Estimates (Per Reactor Year)

Unit 1 [only] 5.0E-9 = [1.25E-7 – 1.20E-7]

Unit 2 [only] 4.5E-8 = [1.65E-7 – 1.20E-7]

Both Units 1.2E-7

14

15 G.2.2 Seismic Initiating Event

16

17 An examination of Calvert Cliff IPEEE indicated that the frequency of loss of the total 

18 nonrecoverable ac power is about 1.3E-5 and 1.5E-5 per year due to seismic events for 

19 Units 1 and 2. These estimates were found when both units were equipped with only 

20 three EDGs rather than the current configuration of five EDGs. However, the original IPEEE 

21 stated that all EDGs are dependent on SRW, and the SRW has significantly lower fragility than 

22 EDGs. A further examination of the two new EDGs, the SBO EDG, and EDG 1A; revealed that 

23 these two EDGs are not dependent on SRW for cooling. This is expected to reduce the seismic 

24 contribution by a factor of 10 accounting. Following the approach used for internal events for 

25 the single and dual unit core damage and no recovery credit for ac power after a seismic event, 

26 the following results were estimated.

27
G-7

Table G-6 CDF for the SBO, and Failures of TDAFWs due to a Potential Overfill (Seismic 1

Events Affecting One or Both Units) 2

3

Affected Unit CDF Estimates (Per Reactor Year)

Unit 1 [only] 3.3E-8 = [4.7E-08 – 1.4E-8]

Unit 2 [only] 5.0E-8 = [5.4E-8 – 1.4E-8]

Both Units 1.4E-8

4

Table G-7 CDF for SBO and Failures of TDAFWs after the Battery Depletion (Seismic 5

Events Affecting One or Both Units) 6

7

Affected Unit CDF Estimates (Per Reactor Year)

Unit 1 [only] Negligible = [1.3E-6 – 1.30E-6]

Unit 2 [only] 2.0E-7 = [1.5E-6 – 1.30E-6]

Both Units 1.30E-6

8

9 G.2.3 Fire Initiating Event

10

11 Calvert Cliffs IPEEE estimates the contributions from internal fire are 7.3E-05 and 1.1E-04 for 

12 Units 1 and 2, respectively. Fires in the control room resulting in its abandonment were the 

13 major contributors to the overall fire core damage frequency. This is important because the 

14 main control room is shared between the two units, although there are two cable spreading 

15 rooms. The majority of the core damage frequency resulting from fires the in control room 

16 therefore is considered to affect both units.

17

18 Severe fires in control room cabinets are assumed to result in control room evacuation. Once 

19 the Control Room is evacuated, the operators are required to load shed most of the electrical 

20 loads, and manually re-start these loads. If not restarted, the site would lead itself into a 

21 self-induced SBO. This condition will eventually result in a loss of the 125 VDC batteries. Even 

22 if the operators successfully re-load the buses, a failure of either of the EDGs supporting the fire 

23 safe shutdown trains, will eventually result in a loss of two of the four batteries. It will indicate a 

24 loss of <something> in the auxiliary shutdown panels, which is the only source of indication for 

25 the operators. Therefore, most of the scenarios involving an EDG failure would involve 

26 extended LOOP with initial successful actuation and control of equipment, initially establishing 

27 AFW flow, but followed by failure of AFW sometimes later due to battery depletion.

28

29 The Calvert Cliffs fire PRA in IPEEE, consistent with the methodology of that time, had several 

30 conservative assumptions and used somewhat conservative data. For example, they did not 

31 adequately account for fire severity and the plant layout effect on fire ignition frequency. In 

32 addition, the analysts considered relatively high heat release rates, and they did not develop 

33 and use scenario specific propagation and suppression. Conservative assumptions were also 

34 made regarding the human error probabilities, specifically for the mitigation of control room fires. 

35 Control room fires are significantly affected by the failure of the operator to perform local manual 

36 actions, and in some cases may rely on a self-imposed SBO to avoid spurious actuations. 

37 Subsequent to submittal of the Calvert Cliffs’ IPEEE, several studies were performed to 

38
G-8

eliminate some of these conservatisms.

1 1 The results of these studies lowered the core damage 

2 frequency contribution of the MCR fire by one unit to 2.45E-5 per reactor year. Note that this 

3 estimate does not reflect the additional credits for the two added EDGs. The probability of the 

4 early core damage, before battery depletion, is driven by the human error probabilities. This 

5 core damage probability is not generally affected by the added EDGs. The single unit core 

6 damage frequency is approximately apportioned (split) to 0.1 and 0.9 for the early and late core 

7 damage, which corresponds to the failures of TDAFWs before or after battery depletion. As a 

8 result, the early core damage frequency of the control room fire would be about 2.4E-06 per 

9 reactor year. The late core damages, i.e., TDAFW failures after the depletion of the batteries, 

10 require failures of EDGs. This split fraction then will be affected by the addition of two EDGs in 

11 Calvert Cliffs. An additional credit of 0.1 is therefore, assigned to reflect the credit for the added 

12 EDGs. For the late core damages affecting both units, this will reduce the fraction of the core 

13 damage frequency from 0.9 down to 0.09 (0.1*0.9).

14

Table G-8 CDF for SBO, and Failures of TDAFWs due to Potential Overfill (Control Room 15

Fire Events Affecting One or Both Units) 16

17

Affected Unit CDF Estimates (Per Reactor Year)

Unit 1 [only] Negligible

Unit 2 [only] Negligible

Both Units 2.45E-6 (0.1*2.45E-5)

18

Table G-9 CDF for SBO and Failures of TDAFWs after Battery Depletion (Control Room 19

Fire Events Affecting One or Both Units) 20

21

Affected Unit CDF Estimates (Per Reactor Year)

Unit 1 [only] 2.2E-5 = [2.45E-5*0.9]

Unit 2 [only] 2.2E-5 = [2.45E-5*0.9]

Both Units 2.2E-6 = [2.45E-5*0.9*0.1]

22

23 G.2.4 Contributions from Other Initiating Events

24

25 Two initiating events, high wind and internal flood were considered for the purpose of estimating 

26 the frequencies of the entry points for estimating the CSGTR probabilities. The internal flood 

27 core damage was estimated at 1.55E-05 per reactor year. Most of the flood scenarios resulted 

28 in eventual core damage as a result of losing the SW, MFW, AFW, and ECCS systems. The 

29 failure of the AFW crosstie between the units is needed for the core damage if not affected by 

30 the flood initiator itself (e.g., if the flood was due to break in AFW suction line, which could 

31 impede the AFW crosstie). The flood scenarios developed in IPEs are expected to result in 

32 core damages that are generally considered late (approximately 12 hours or more after the 

33 initiator), therefore may not be considered for evaluating containment bypass. The original flood 

34 analysis in IPE also suffered from conservative assumptions and high flood initiating event 

frequency. A PRA update of the flood model in 2 January 2000 2 35 resulted in an updated 

 1 A letter from Charles H. Cruse, BGE vice president of Nuclear Energy, to U.S. Nuclear Regulatory Commission, 

 May 18, 1999, “Additional Response to Request for Additional Information on Calvert Cliffs Nuclear Power 

 Plant, Unit Nos. 1 and 2, Individual Plant Examination of External Events Submittal (TAC Nos. M83603 

 and M83604).” 2 A presentation by Bruce Mrowca on Calvert Cliffs PRA update, January 2001 titled “Calvert Cliffs PRA, 

 January 22, 2000,” Agencywide Documents Access and Management System (ADAMS) Accession 

 No. ML010400376.
G-9

1 estimate of 1.6E-06 for flood CDF. This value is conservatively used as a single unit CDF 

2 contributor due to internal flood for estimating CSGTR frequency for scenarios where AFW 

3 system has operated for 4 hours.

4

5 The high wind contribution to the core damage is estimated to be 4.4E-6. The main contributors 

6 to this estimate were the SBO scenarios. This contribution of CDF is considered to affect both 

7 units. The frequency of dual LOOP and early failures of TDAFW pumps was estimated as being 

8 similar to the internal event CDF [i.e., 4.7E-8 per reactor year = 0.0108×4.4E−6]. The remaining 

9 CDF of 4.3E-6 per reactor year was estimated for those scenarios where TDAFW pumps 

10 operated early and failed after battery depletion.

H-1

1 APPENDIX H

2

3 A SCREENING APPROACH BASED ON FLAW DEPTH AND LENGTH

4

5

6 This approach accounts for both the distribution of flaw lengths and depths and considers the 

7 possibility of multiple flaws. This approach evaluates the consequential steam generator tube 

8 rupture (C-SGTR) probability based on failure of one or more tubes and estimates the 

9 contributions of single tube and multiple tube failures separately. This approach has less 

10 conservatism than Approach 1 and it can be used for progressive screening of probabilistic risk 

11 assessment (PRA) scenarios or for evaluating inspection findings where the surveillance data 

12 for both depths and lengths are available, especially for large flaws.

13

14 This approach considers the contribution of shallower (less than 45-percent deep) and shorter 

15 (less than 2-centimeter (cm) [0.79-inch [in.]) flaws to C-SGTR to be negligible. The following 

16 large flaw bin sizes were considered for this approach:

17

18 • size bins for length: flaw length between 1.5 to 2.5 cm (0.59 to 0.98 in.), 2.5 to 3.5 cm

19 (0.98 to 1.38 in.), and 3.5 to 4.5 cm (1.38 to 1.77 in.)

20

21 • size bins for depth: flaw depth from 45 percent to 55 percent, from 55 percent to 

22 65 percent, from 65 percent to 75 percent, from 75 percent to 85 percent, and from 

23 85 percent to 95 percent

24

25 The probability that a flaw belongs to each size bin was calculated using following equation.

26

27 PPPPPPPP [( 1 < ffff ff h < 2), ( 1 < ffff ff ff h < 2)]

28 = PPPPPPPP [FF ) ∗ PPPPPPPP PP PP[( 1 < ffff ff h < 2)|ffff ff ff ]

29 ∗ PPPP[( 1 < ffff ff h < 2)|ffff ]

30

31 A large flaw here is defined as a flaw large enough to require the tube to be plugged. As 

32 discussed earlier, a plugged tube is expected to have a flaw with an average length of 1.3 cm, 

33 and a depth of 30 percent or more. They account for 0.95 percent of all flawed tubes. The 

34 conditional probabilities for a flaw to be in such a flaw bin are estimated from the associated 

35 Gamma distributions, divided by the probability that a large flaw is observed [1-cumulative 

36 Gamma (1.3 cm [0.51 in.] and 30 percent; the large flaw thresholds)].

37

38 Table H-1 shows the probability that a flaw resides in one of the large size bins. The size 

39 distribution length and depth do not differentiate between Inconel 600 and 690.

40
H-2

Table H-1 Probability that a Large Wear Flaw in the Last Cycle Has the Specific Ranges 1

of the Length and Depth 2

3

Depth Range 1.5 cm to 2.5 cm

2.5 cm to 

3.5 cm

3.5 cm to 

4.5 cm

Total Probability 

for Length > 1.5 cm

45%<d<55% 5.70E-2 1.26E-2 2.34E-3 7.19E-2

55%<d<65% 1.36E-2 3.01E-3 5.59E-4 1.71E-2

65%<d<75% 3.14E-3 6.95E-4 1.29E-4 3.96E-3

75%<d<85% 7.09E-4 1.57E-4 2.91E-5 8.95E-4

85%<d<95% 1.57E-4 3.48E-5 6.47E-6 1.99E-4

Total Probability of a flaw is considered large and has a length greater than 

2 cm and less than 4.5 cm, and depth between 45% to 95% 9.41E-2

4

5 For a wear flaw, the probability of a tube failure is a function of flaw depth only. This is because 

6 the current C-SGTR software conservatively models the wear flaw as tube thinning (flaws were 

7 assumed to be relatively large). So the probability of tube failure before the failure of the HL

8 (HL) is only a function of the flaw depth. The maximum leak area, however, is a function of the 

9 wear length as estimated by C-SGTR software. For a 2 cm (0.78 in.) wear flaw the maximum 

area is about 2 square centimeters (cm2

) (0.31 square inch [in.2 10 ]), for 3 cm (1.18 in.) flaws, it is 

close to 5 cm2 (0.77 in.2 11 ), and for larger flaws the leak area is limited by twice the cross 

sectional area of the tube (approximately 6.08 cm2 (0.94 in.2 12 ). There are large uncertainties 

13 associated with the estimated leak area as a result of tube failure because of wear flaw. As a 

14 bounding approach, it was considered that the failure of at least one large flaw with a length 

15 greater than 2 cm (0.78 in.) is required for C-SGTR to occur. The C-SGTR probability 

16 estimations in this section have considered two contributions:

17

18 (1) the existence of one tube with a large flaw in any of the plant SGs

19 (2) the existence of two or more tubes with large flaws

20

21 The approach taken here is considered somewhat conservative. For example, the best 

22 estimate of the number of tubes resulting in a leak rate equivalent to a guillotine break of one 

23 whole tube for a 2 cm (0.78 in.) flaw is about three tubes. However, in this approach, the failure 

24 of any one tube is considered sufficient. This conservative approach was adopted in lieu of not 

25 considering several smaller (less than 2 cm [0.78 in.] long) deep flaws as a part of this analysis.

26

27 The probabilities of C-SGTR occurring before HL failure for different bin sizes are shown in 

28 Table H-2 for Inconel 600 and Table H-3 for Inconel 690. These probabilities are estimated 

29 using the C-SGTR calculator for predicting the C-SGTR probability and a TH file for the 

30 representative plant, which simulates the SBO with failure of TDAFW at start of accident (Case 

31 Wnewbase).

32

A tube is assumed to have failed if it exhibits a leak area of at least 1 cm2 (0.16 in.2 33 ). The 

34 threshold leak area is conservatively selected. This is done in appreciation of the existing large 

35 uncertainties associated with the predicted leak area for wear. The results shown in these 

36 tables reaffirm that for the wear flaws, the bounding probability of tube failure is only function of 

37 the flaw depth.

38
H-3

Table H-2 Probability of C-SGTR Occurring before HL Failure for Different Sizes of Flaws 1

in Inconel 600 in Zion Wnewbase Case 2

3

Flaw Depth Maximum Leak 

50% 60% 70% 80% 90% Area

Flaw Length

2 cm ~ 0 ~ 0.05 ~0.8 ~1.0 NA: May leak 

during operation ~2.0 cm2

3 cm ~ 0 ~ 0.05 ~0.8 ~1.0 NA: May leak 

during operation ~5.0 cm2

4 cm ~ 0 ~ 0.05 ~0.8 ~1.0 NA: May leak 

during operation

Limited by 

guillotine break of 

the tube 6.08 cm2

4

Table H-3 Probability of C-SGTR Occurring before HL Failure for Different Sizes of Flaws 5

in Inconel 690 in Zion Wnewbase Case 6

7

Flaw 

Depth ->

Flaw Length

50% 60% 70% 80% 90% Maximum Leak 

Area

2 cm ~ 0 ~ 0.00 ~0.75 ~1.0 NA: May leak during 

operation ~2.0 cm2

3 cm ~ 0 ~ 0.00 ~0.75 ~1.0 NA: May leak during 

operation ~5.0 cm2

4 cm ~ 0 ~ 0.00 ~0.75 ~1.0 NA: May leak during 

operation

Limited by guillotine 

break of the tube 

6.08 cm2

8

9 The above estimates need to be aggregated through a probability model to produce an estimate 

10 of the probability of C-SGTR. To do so, the following terms are defined:

11

12 N: Number of Flaws

13

14 Subscript “i”: for defining the length bins

15

16 Subscript “j”: for defining the depth bins

17

18 Qi,j : The probability that a large flaw belongs to bin i, j (Obtained from Table H-1)

19

20 Θi,j : The C-SGTR probability associated with a flaw that belongs to bin i, j (obtained 

21 from Table H-2 or H-3)

22

23 The aggregate probability of C-SGTR (P) is given by the following equation using the variables 

24 defined earlier:

PP = NN ∗ �

jj

�QQii,jj ∗ θθii,jj

ii

25

26

27 If Θi,j; the C-SGTR probability of a flaw with depth index j and length index i does not depend on 

28 index i as it is true for wear flaw (not true for cracks). Then the above equation is simplified to:

29
H-4

PP = NN ∗�θθjj

jj

�QQii,jj

ii

1

2

3 For one flaw; with N set to one, the value of P was estimated based on the results in 

4 Tables 7.1-9 and 7.1-10 for Inconel 600, and Tables 7.1-9 and 7.1-11 for Inconel 690. These 

5 are the values obtained for this single flaw: P600=4.92E-3, and P690=4.72E-3.

6

7 As discussed earlier, it is expected that 31 flawed tubes will be generated in Cycle 15 

8 (15 EFPYs of operation) for Inconel 600 tubes and 20 flaws for Inconel 690. The probability that 

9 one tube fails before HL failure can be estimated using the following equation:

10

PPPPPPPP (1 tt CCCCCC CC) = �

NNNN>0

11 PPPPPPPP (NN tt h ffff ) ∗ NN ∗ PPPPPPPP(tt ff ff )

12

13 The probability of two tubes failure can be estimated using the following equation:

14

15 PPPPPPPP(2 tt CCCCCC CC)

= � PP

NNNN>1

(NN tt h ffff ) ∗ �

NN

2 16 � ∗ PPPPPPPP(tt ff ff ) ∗ [1

− PPPPPPPP(tt ff ff )]

NNNN−2 17

18

19 Similarly, higher numbers of tube failures causing C-SGTR; i.e., 3, 4, etc., can be estimated. 

20 The results of these calculations are shown below, in Table H-4, for Inconel 600 and 690.

21

Table H-4 Probability of Single- and Multi-Tube Failure in C-SGTR for Inconel 600/690 22

23

Tube Materials C-SGTR: One Tube 

Failure

C-SGTR: Two Tubes 

Failure

C-SGTR: More Than 

Two Tubes Failure

Inconel 600 1.31E-2 8.24E-5 Negligible

Inconel 690 8.90E-3 3.85E-5 Negligible

24

25 The two probabilities of single tube failure and multiple tube failures can be used in PRA 

26 evaluations. For Inconel 600, these values are 0.013 and 8.23E-5; for Inconel 690 the values 

27 are 0.0089 and 3.85E-5 for effective full power year 15. The probabilities of Inconel 690 are a 

28 factor of 1.5 lesser than Inconel 600. Similar analyses for limited number of flaw sizes were 

29 performed for the SBO scenarios with late failure of TDAFWs after the battery depletion (Case 

30 153). The preliminary results showed that the probability of single and multiple tube failures is 

31 about a factor of 2 higher for Case 153 as compared to the Wnewbase case. All analyses 

32 results shown in the remainder of this section are performed for the Wnewbase case with 

33 Inconel 600. The scaling factors—an increase of twofold is used for SBO cases with late failure 

34 of TDAFWs, and a decrease of one-and-a-half-fold is used for Inconel 690.

35

36 The contribution to C-SGTR from single tube failure can be compared to the estimates obtained 

37 from the first approach. The results show that for Inconel 600, the single tube failure 

38 contribution to C-SGTR is about 1.31E-2 from both methods. Similarly, for Inconel 600, the 

39 single tube failure contribution to C-SGTR is 8.1E-3 and 8.90E-3E-3 from the first and the 

40 second approach respectively. This provides some confidence that the estimated results are 

41 consistent from two different approaches.
I-1

1

2 APPENDIX I

3

4 MELTING TEMPERATURES AND STEEL OXIDATION 

5 CONSIDERATIONS IN MELCOR MODELING

6

7

8 The melting temperatures presented in the slides for stainless steel and Inconel (1,725 K 

9 (1,452 degrees C)) originate from the SGAP analysis. These temperatures are consistent with 

10 those listed in the SCDAP/RELAP (1,671 – 1,727 K [1,398–1,454 degrees C]) and MELCOR 

11 (1,700 K [1,426 degrees C)) manuals. The temperatures are also consistent with typical listings 

12 of LWR melting temperatures such as that shown in NUREG/CR-6042 (R-800 course material).

13

14 The lowest melting temperature for iron listed in this are for eutectics with Zr (approximately 

15 940 degrees C [1,724 degrees F)) and B4C eutectics (approximately 1,150 degrees C

16 [2,102 degrees F]). Steel reactions with Zr and with B4C are modeled in MELCOR.

17

18 Steel oxidation of reactor coolant system (RCS) components are typically not considered in 

19 severe accident analyses. Oxidation of RCS components was not considered during the Steam 

20 Generator Action Plan (SGAP) analysis. The influence of oxidation of core components was 

21 analyzed during the SGAP. It was concluded that variations in oxidation of additional metal 

22 affect absolute failure timing but do not significantly affect the relative failure timing of different 

23 components which is of interest for evaluating whether the containment is bypassed.

24

25 MELCOR contains a steel oxidation models but they applied in components in the COR module 

26 rather than the HS (heat structure) module use to model the RCS piping.

27

28 The effects of oxidation are analyzed below to assess the possible effects of oxidation in the 

29 RCS. The MELCOR steel-H2O oxidation model was used. External sources for steel oxidation 

30 or steel oxide melting were not sought since it is expected that the major oxidation mechanisms 

31 should have been captured during the study of degradation of steel present in the reactor core.

32

33 The steel-H2O rate constant in MELCOR is calculated using the following equation.

34

K(T) = 2.42 * 109 35 * exp(-42,400/T)

36

37 The fact that the reaction constant is 8 orders of magnitude greater than that used in MELCOR 

for the Zr-steam reaction rate (listed for units of SI (kg, m2 38 )) and closer to the range listed in the 

39 literature for the Zr-steam for units of milligram and centimeter rather than kilogram and meter. 

40 The analysis is continued assuming that the steel-H2O rate constant listed in MELCOR applies 

41 to units of kilogram and square meters.. If this assumption is incorrect and the units 

42 represented are indeed milligram and centimeter the mass losses and consumed thickness 

43 would be lower by 2 orders of magnitude (rate constant reduced by 4 orders of magnitude) 

44 when converted to SI.

45

46
I-2

1 This was verified in the literature. A paper by the same author as the primary reference in 

MELCOR (J.F. White)1 2 but published 3 years after the MELCOR reference lists the following 

3 parabolic rate constant:

4

w^2/t = 2.4 * 1012 5 * exp(-84,300/(RT))

6

where w is the weight gain per unit area in mg/cm2 7 , R is the gas constant in cal/(mole-K), T in K, 

8 and t in s.

9

10 Applying the universal gas constant of R = 1.987 cal/(mole-K) the equation becomes:

11

w2

/t = 2.4 * 1012 12 * exp(-42,426/T)

13

Because the units of w2 are mg2

/cm4, to convert to rate to kg2/m4 14 , the constant should be 

multiplied by 10-4 15 . This was also the factor used in the conversion of the Urbanic-Heidrich 

16 constant for Zr in the MELCOR manual. It seems that the constant in MELCOR for the steel17 H2O rate constant should therefore have an exponent of 8 rather than 9. i.e.

18

K(T) = 2.42 * 108 19 * exp(-42,400/T)

20

21 The MELCOR manual refers to w as the mass of metal oxidized per unit area whereas the 

22 paper refers to w as the weight gain per unit area. Assuming that the oxidation product is FeO 

23 the ratio of weight gain to metal mass oxidized should be the ratio of atomic weights - about 

24 16/56 or 0.29.

25

26 The following calculation is conducted with the rate constant as listed in the MELCOR manual 

27 (exponent of 9) because making the change would only reduce the calculated oxidation rates 

28 and amounts.

29

 1 J.T. Bittel, L. H. Sjodahl, and J. F. White, “Oxidation of 304L Stainless Steel by Steam and by Air,” Corrosion-

 NACE, Vol. 25, No. 1, January 1969.
I-3

1 The parabolic rate constant for steam-H2O reaction is shown in the following figure.

2

3

4

5

6 Figure I-1 The parabolic rate constant for steam-H2O reaction

7

8 In the CSGTR analyses RCS failures typically occur when temperatures are substantially below 

9 1,750 K (1,476 degrees C). The temperatures are rapidly rising limiting the time at high 

10 temperatures. Steel mass loss at a fixed temperature over the course of 1 day is shown for 

11 select temperatures below 1,750 K (1,476 degrees C) in the following plot.

12

1.E-14

1.E-13

1.E-12

1.E-11

1.E-10

1.E-09

1.E-08

1.E-07

1.E-06

1.E-05

1.E-04

1.E-03

1.E-02

1.E-01

1.E+00

5 7.5 10 12.5 15

K (kg^2 m^-4 s^-1)

1/T [K^-1] *10^-4

Steel-H2O Consumption Rate Constant
I-4

1

2

3 Figure I-2 Steel mass loss at a fixed temperature

4

The corresponding loss of steel thickness assuming a density of 8,000 kg m-3 5 is shown in the 

6 following plot.

7

8

9

10 Figure I-3 Loss of steel thickness

11

1.E-07

1.E-06

1.E-05

1.E-04

1.E-03

1.E-02

1.E-01

1.E+00

1.E+01

1.E+02

100 1000 10000 100000

w (kg m^-2)

Time (s)

Reaction of steel with steam

steel mass loss

750 K 1000 K 1250 K 1500 K 1750 K

1.E-09

1.E-08

1.E-07

1.E-06

1.E-05

1.E-04

1.E-03

1.E-02

1.E-01

1.E+00

1.E+01

100 1000 10000 100000

Thickness loss (cm)

Time (s)

Reaction of steel with steam

Steel thickness consumed

750 K 1000 K 1250 K 1500 K 1750 K
I-5

1

The steel-H2O model in the MELCOR reference manual 2 2 predicts no appreciable oxidation 

3 (approximately greater than 1 mm [0.04 in.]) except for extended durations (approximately

4 1 day) at near the melting point. It is assumed that, at these temperatures, failure by creep will 

5 occur long before oxidation is significant.

6

7 The stainless steel oxidation paper presented steam oxidation for different stainless steels and 

8 mild steel with the data points falling in the same general range. It is assumed that the relation 

9 is generally applicable to other steels.

10

11 The approach to RCS steel oxidation taken in this report is consistent with how phenomena is 

12 handled in severe accident analysis and previous consequential steam generator tube rupture 

13 analyses.

14

15 Because the existing oxidation model does not predict appreciable oxidation in the absence of 

16 the hydrogen affect except at high temperatures, no attempt was made to consider the influence 

17 of hydrogen on oxidation, to identify low-melting-point iron oxides, to consider additional heat 

18 and hydrogen generation, and to consider the effects of stainless steel foaming including 

19 insulation for the oxidation of RCS components. If additional effects of foaming other effects are 

20 significant they should probably be considered first for the core where temperatures are hottest.

 2 The “in the MELCOR reference manual” refers to both the use of the 9 rather than 8 as the exponent for the

reaction rate and the interpretation of the parabolic rate referring to metal mass consumed rather than mass gain 

 (oxide mass gained – metal mass consumed).

J-1

1 APPENDIX J

2

3 LOOP SEAL CLEARING CONSIDERATIONS

4

5

6 This appendix discusses loop seal clearing related assumptions. Different opinions can be 

7 found in NUREG/CR-6695 and various sections (e.g., Section 3.7, Section 8.1) of the draft 

8 NUREG.

9

10 J.1 TH Analysis Related Considerations

11

12 The assumptions in section 3.7 build upon NUREG/CR-6695. The issue was not explored fully. 

13 Any difference is not expected to be a significant issue for the Combustion Engineering (CE)

14 configuration analyzed in this work. Considering the current scope of the project a 

15 thermal-hydraulics (TH) assessment of loop seal clearing for CE was not conducted. It was 

16 simply noted that the loop seals did not clear in the simulations that were run.

17

18 One of the reasons that this TH analysis was not prioritized is that a high degree of containment 

19 bypass was concluded for CE even in the absence of loop clearing as a result of the high 

20 temperatures that the steam generator (SG) tubes are exposed. Because the effect of loop seal 

21 clearing primarily results from hotter (near core temperature) gases reaching steam generator 

22 tubes, which already occurs in the CE design analyzed even for closed-loop-seal natural 

23 circulation, the additional impact of loop seal clearing on risk for CE is not expected to be 

24 significant.

25

26 The initial intent to address loop seal clearing for this project was to test the different failure 

27 mode hypotheses and to determine whether apparent differences in loop seal behavior were 

28 inherent to designs, because of differences in codes, or differences in user choices. The plan 

29 was to perform a quick related “hand calculation” to ascertain what parameters would be 

30 important to both hypothesized failure modes and expected behavior, verify these relevant 

31 parameters in the input decks, and the run a series of simulations to test the extent to which the 

32 failure modes affected behavior. Only a general outline for approaching the problem was 

33 developed when initially planning the work. The text for loop seal clearing in the TH section 

34 reflects this initial outline.

35

36 The assumptions described in the TH analysis section for loop seal clearing do not factor into 

37 results since neither geometry nor system-code models are changed. Rather these 

38 assumptions factor into how the results are interpreted and to help decide what to look for.

39

40 The assumptions for loop seal clearing do not differ appreciably from those in 

41 NUREG/CR-6995. One additional factor is considered explicitly: the upper-vessel-to42 downcomer leakage. The knowledge of the influence of this leakage is not new. In fact 

43 individuals involved with the Steam Generator Action Plan (SGAP) and NUREG/CR-6695 

44 indicated that core-to-downcomer bypass leakage had also been a considered during the 

45 development of the system-code inputs. A choice of a small upper-core-to-downcomer leakage 

46 area for these Westinghouse analyses was found to result in loop seal clearing.

47

48 What was planned to be explored further during this study is the expectation that the amount of 

49 seal leakage that results in loop seal clearing depends on both the assumed upper-vessel-to50 downcomer leakage area and (perhaps to a lesser extent) RCS-to-containment heat transfer.
J-2

1

2 Additional detail of the expected behavior follows:

3

4 Upper loop seal water can be lost in 3 different ways:

5

6 (1) Flow over to downcomer or out of reactor coolant pump (RCP) seal before bubble 

7 formation or if bubble shrinks or water level oscillations (bubble shrinking/not initially 

8 forming). In fact, in the absence of upper-vessel-to-downcomer leakage a bubble should 

9 not even form until either loop seal water reaches saturation or until SG side water level 

10 drops to the horizontal pipe section of the seal thereby allowing steam to bubble through.

11 (seems to be a new consideration for this report)

12

13 (2) Entrainment to RCP seal once (or if) steam flows through upper loop seal (lower loop 

14 seal must still be intact to maintain differential pressure. This is the primary mechanism 

15 for loop seal clearing described in NUREG/CR-6995.

16

17 (3) Evaporation/flashing. This is an additional mechanism described in NUREG/CR-6995.

18

19 To create sufficient differential pressure across the upper loop seal to cause steam to bubble 

20 through it (and thereby remove inventory by mechanism 2) other in-leakage to the upper 

21 horizontal part of the cold leg must not be significant. This means that:

22

23 (1) The lower loop seal (downcomer-core) must be intact.

24

25 (2) The upper-vessel-to-downcomer leakage area should not be large relative to the RCP 

26 seal leakage area.

27

28 If one of the other in-leakage pathways is open gas driven by the evaporation of any saturated 

29 water in the system would take that pathway rather than bubbling through the upper cold leg 

30 loop seal.

31

32 The following questions for a more detailed treatment of loop seal clearing come to mind for 

33 potential future analyses in this subject:

34

35 • How do the flow resistances across core and SGs in the code input compare with -

36 measurements?

37

38 • How do the Westinghouse and CE flow resistances compare, including the relative flow 

39 resistances between SGs and core?

40

41 • What is the maximum range of pressure drop and pressure drop difference achievable? 

42 That is, neglecting any liquid flashing to steam, what would the steam pressure drops 

43 across core and SG tubes be for an infinite volume of steam at cold legs if flow is limited 

44 by choked condition at the SRVs (parallel channel problem)?

45

46 • How much does flashing affect behavior – from lower head and from loop seals? How 

47 do the elevations of the downcomer skirts in the inputs match expectations?

48

49 • How do these elevations and those of the loops differ between Westinghouse and CE 

50 designs and how would this be expected to affect clearing behavior?
J-3

1

2 • How much condensation is occurring? How does the magnitude compare to that of the 

3 Westinghouse calculations?

4

5 • Are differences primarily because of differing geometry surface-area or because of 

6 differing heat transfer coefficients? Do the Westinghouse and CE reactor vessels have 

7 differing discharge rates?

8

9 J.2 PRA Analysis Related Considerations

10

11 The probabilistic risk assessment (PRA) model used in this report postulates that loop seal will 

12 occur for both Westinghouse and CE cases in severe accident sequences where a 

13 1,135–1,817 liters per minute/pump (300–480 gpm/pump) leakage exists. These leakage 

14 sequences are generally well delineated in PRA studies. Such sequences are assumed to lead 

15 to consequential steam generator tube rupture end state.

K-1

1

2 APPENDIX K

3

4 FURTHER DISCUSSION OF SG TUBE FLAW DISTRIBUTIONS

5

6

7 This appendix contains a further discussion of steam generator (SG) tube flaw distributions as 

8 already given in Section 6 of the main body of this report and their application as discussed in 

9 Section 7.1.3. The material in this appendix is based on an Advisory Committee on Reactor 

Safeguards (ACRS) subcommittee briefing 1 10 on consequential steam generator tube rupture 

11 (C-SGTR).

12

13 K.1 On Development of Distributions in Section 6.0

14

15 The previous work on estimating SG tube flaw distributions was for 600 MA tube materials 

16 (NUREG/CR-6521 Gorman Report) and for cracks only using data that existed pre 1995. These 

17 (U-tube) SGs are replaced with those having new SG tube materials (Thermally Treated Alloy 

18 600 and 690). Use of the information from previous studies could not be justified. The objective 

19 is to update the previous study on flaw statistics and provide current statistics sufficient to 

20 generate flaw samples for C-SGTR analysis (input to the C-SGTR calculator).

21

22 Flaw data for Thermally Treated Inconel 600 and 690 (600TT and 690TT) were collected from 

23 selected inservice inspection reports available to the U.S. Nuclear Regulatory Commission 

24 (NRC). Flaw data was manually extracted and compiled into a data base for further analyses. 

25 Figures K-1 and K-2 show the empirical data used for the flaw depth and length parameters, 

26 before a fitted gamma distribution was imposed. The data were binned against operating time 

27 (measured in Equivalent Full Power Years-EFPY) and flaw types. Flaw Generation Rate per 

28 tube as a function of SG service life [measured in EFPY] is generated for:

29

30 • Volumetric/Wear Flaw 600TT

31 • Volumetric/Wear Flaw 690TT

32 • Axial Cracks 600TT

33 • Circumferential Cracks 600TT

34

35 (No Crack data was found for 690TT)

 1 ACRS Meeting of the Subcommittees on Metallurgy & Reactor Fuels and PRA Consequential Steam Generator 

 Tube Rupture (C-SGTR) Subcommittee Briefing. April 7, 2015, transcript. Agencywide Documents Access and 

 Management System (ADAMS) Accession No. ML15182A262.
K-2

1

2

Figure K-1 Graphical presentation of aggregate flaw data 3

Empirical depth distribution using all flaws in the database 4

5
K-3

12

FigureK-2 Graphical presentation of aggregate flaw data3

Empirical distribution of axial length of all flaws in the database4
K-4

1

2 Model Parameters

3

4 • A flaw model was developed by

5

6 – linearly increasing rate of volumetric flaws generation as a function of time 

7 (i.e., effective full power year [EFPY])

8

9 – linearly increasing rate of crack flaws generation as a function of EFPY

10

11 – gamma distribution of flaw length

12

13 – gamma distribution of flaw depth

14

15 • Statistical Estimation Approach

16

17 – regression using Excel routine for estimating the linearly increasing rates

18

19 – matching the first two moments for estimating the parameters of Gamma 

20 distributions

21

22 General Findings

23

24 • Sufficient statistical results were developed to generate flaw samples for the C-SGTR 

25 calculator software.

26

27 • New material 600TT/690TT flaw rate generation is about an order of magnitude less 

28 than what was reported for MA 600.

29

30 • The majority of flaws observed are volumetric rather than cracks.

31

32 • The flaw length and depth distribution is somewhat smaller than MA 600.

33

34 The most important flaw parameter that specifies failure resistance of a tube is the flaw depth, 

35 as it was confirmed by the probabilistic risk assessment (PRA) models and the C-SGTR 

36 calculator in Section 7 of this report. Figure K-3 shows the fitted and empirical cumulative 

37 distribution for flaw depth.

38

39 The high end tail of the distribution is affected by the tubes removed because of plugging 

40 practice because these flaws will not be available for further growth to larger flaw in the next 

41 cycle. See Section K-2 (also Section 7.1.3) for the correction for that (shifted distribution) for 

42 PRA modeling purposes.

43

44 The lower tail of empirical distribution is affected by the error associated with measuring small 

45 flaws. With small and shallow flaws, in the relatively small database being used, one plant 

46 reported many flaws that were very shallow, at the range of 2, 3 and 5 percent depth, where the 

47 other plant did not report such small flaws. Knowing that the small flaws have a larger error in 

48 them, there is a possibility that, even the lower tail may not be very accurate, even for the 

49 empirical distribution.
K-5

12

FigureK-3 Flaw depth distribution3

Distribution of percentage of flaw depth45
K-6

1 K.2 On the Adjusted (shifted) Flaw Distributions Used in PRA

2

3 As discussed in Section 7.1.3, during PRA analysis, adjustments were made to the original 

4 estimated distributions of Section 6.0 for flaw depth and length.

5

6 To improve the distribution fit for large flaws which are more important to C-SGTR and to 

7 compensate for the perceived distortion of flaw size distributions toward the shallower and 

8 smaller flaws, the previous distribution were shifted by a small amount of depth and length 

9 (adding a scale variable to Gamma distribution).

10

11 This adjustment also provided much closer estimates of the number of tubes that are plugged in 

12 each cycle (better estimate of the number of large and deep flaws at the tails).

13

14 For example, for Westinghouse plant, the large and deep flaws were the major contributor to 

15 C-SGTR fraction estimates. Better fits at the tail of distributions of length and depth therefore 

16 were need to be modeled in PRA.

17

18 There were also a large number of unreliable small depth and length measurements (i.e., depth 

19 less than 10 percent), which skewed the size distributions of depths and lengths toward the 

20 lower values, whereas tube plugging criteria removed those larger flaws that could have grown 

21 into even larger ones if they were allowed to remain.

22

23 Figure K-4 compares the cumulative probabilities of the empirical, fitted, and shifted flaw 

24 distributions for flaw depth. Additional discussion, figures, and tables can be found in Section 

25 7.1.3.
K-7

1

2

3

Figure K-4 Flaw depth distribution (shifted gamma) 4

Fitted and shifted depth distribution 5

6

L-1

1 APPENDIX L

2

3 A PROCESS TO COMPREHENSIVELY ESTIMATE C-SGTR CDF IN A 

4 PRA MODEL

5

6

7 L.1 Introduction

8

9 This appendix outlines a process to include consequential steam generator tube rupture in a 

10 probabilistic risk assessment Level 1 model to collect those end states for further modeling in 

11 Level 2 analysis. Section L.2 discusses the PRA Level 1 modeling detail deemed to be 

12 sufficient and cost effective to capture the bulk of the potential C-SGTR core damage frequency 

13 for further modeling in PRA Level 2 analysis. The validity of this approach was tested by 

14 applying it to a PRA model for a 4-loop Westinghouse plant. The results of this application are 

15 summarized in Section L.3.

16

17 All domestic nuclear power plants already have mature PRA studies that do not necessarily 

18 attempt to model C-SGTR in a detailed manner in their event trees. This process is also 

19 intended to assess the contribution of those deliberately “unmodeled” potential C-SGTR 

20 sequences in an existing PRA study. The example provided in Section L.3 attempts to illustrate 

21 such an assessment.

22

23 A guidance document containing an expanded version of this process may be produced in the 

24 future for use by U.S. Nuclear Regulatory Commission risk analysts.

25

26 L.2 The Process

27

28 The objective of this section is to outline a process to model C-SGTR in PRA Level 1 to collect 

29 those end states for further consideration in Level 2 analysis. The process aims to provide 

30 PRA Level 1 modeling detail sufficient and cost effective to capture the bulk of the potential 

31 C-SGTR CDF for further treatment in PRA Level 2 analysis (i.e., to focus effort in collecting 

32 C-SGTR CDF from the most likely sources).

33

34 The process is discussed for the internal event hazard category during a power operation 

35 Level 1 PRA for a pressurized-water reactor; extension to other hazard categories is considered 

36 to be straightforward.

37

38 An internal events PRA model may have 20-30 event trees leading to numerous accident 

39 sequences. It is assumed that initially C-SGTR is not modeled and the objective is to capture 

40 C-SGTR candidate sequences for further treatment in the Level 2 model with minimal intrusion 

41 into the existing model, yet assuring that a large fraction of such sequences are identified. For 

42 this purpose, two modeling actions may be considered:

43

44 1. Explicitly insert event tree nodes that query sequences to lead to identification of 

45 C-SGTR end states (i.e., sequences with C-SGTR occurring prior to core damage).

46

47 2. Use sequence rules on core damage sequences to mark HDL (H/D/L) sequences and 

48 others, if necessary, as C-SGTR candidates (i.e., sequences with the potential for 

49 C-SGTR to occur after core damage).
L-2

1

2 Both of these approaches are used in this process. Those sequences that may have some 

3 C-SGTR potential, but are deliberately not modeled, are termed as unmodeled sequences. As 

4 long as the unmodeled sequences are expected to contribute a very small percentage to the 

5 total of all C-SGTR sequences, they can be left as unmodeled.

6

7 The process examines different event trees and accident sequence sets to provide C-SGTR 

8 modeling suggestions in five steps. The first two steps are for screening out sequences.

9

10 1. Those event trees and sequences that are already steam generator tube rupture 

11 (SGTR)

12

13 SGTR event tree already has end states for SGTR; thus, there is no need to model C-SGTR.

14

15 2. Those ETs that cannot cause C-SGTR or have very little potential for C-SGTR

16

17 Such event trees and their sequences can be identified and removed from further consideration 

18 for C-SGTR. Examples of such event trees are:

19

20 – Large LOCA (LLOCA)

21

22 – Excessive loss-of-coolant accident (LOCA) (Vessel Failure XLOCA, 

23 LOCA beyond emergency core cooling system (ECCS) capacity)

24

25 – Interfacing Systems LOCA (ISLOCA)

26

27 Since the primary system is depressurized and stays so in such events, C-SGTR challenges are 

28 not expected.

29

30 3. Those event trees where pressure-induced C-SGTR may occur early in the event

31

32 Such event trees include anticipated transient without scram (ATWS), secondary side break 

33 (SSB), and consequential secondary side break (CSSB). Whenever possible, an event tree

34 node could be inserted in an early part of such event trees to query for C-SGTR, and then 

35 transfer the ensuing sequence to an SGTR event tree with the appropriate boundary conditions. 

36 See Figures L-1 and L-2 for suggestions for ATWS and SSB event tree modifications for 

37 C-SGTR. Note that these figures introduce a conditional probability of an existing large flaw 

38 of 0.01. This value is derived from Appendix C (and in turn Appendix F) of this NUREG.

39

40 4. HDL core damage sequences

41

42 When the core damage sequences are examined, it is possible to identify those sequences 

43 that can clearly be marked as HDL. This can be done either manually or by defining sequence 

44 rules. Thus, such sequences can be assigned to the C-SGTR end state (or otherwise tagged) 

45 to be modeled in Level 2. The conditional C-SGTR probability for HDL sequences can be 

calculated for the plant-specific case; if not, a generic value of 0.02 to 0.03 1 46 is in order, 

 1 This range is for SGs with favorable geometry, such as those seen in Westinghouse PWRs. For other SGs, values

 from the main body of this report, or plant-specific calculations if thermal hydraulic (T&H) analyses are available, 

 could be used.
L-3

1 depending on the type of steam generators (SGs) in question. Use probability of 1 if the 

2 primary side loop is cleared.

3

4 5. Indeterminate or faulted steam generator (FSG) core damage sequences

5

6 After Step 4 above, there will be sequences that are indeterminate as to their C-SGTR potential.

7

8 Such sequences may arise from:

9

10 (a) Auxiliary feedwater (AFW) status is not asked in the sequence definition, which does let 

11 the sequence be qualified as HDL or otherwise (indeterminate core damage sequences).

12

13 (b) AFW appears as successful but flow to one or more AFW trains may fail, still meeting 

14 the success criteria. If AFW to an SG fails, the operator will isolate that SG by 

15 procedures, leading to a dry SG. Similarly, secondary side leakage (isolation failure, 

16 secondary side break condition) may occur in a fed SG, other SG loops operating as 

17 intended, leading to a faulted SG that would be isolated. In such scenarios, some level 

18 of C-SGTR challenge may exist. The conditional probability of C-SGTR in such SGs can 

19 be calculated if the thermal hydraulic properties of such scenarios are known. However, 

20 in a typical PRA, such analyses are not readily available. Based on thermal hydraulic 

21 expert opinion, the potential for C-SGTR challenge in such SGs is estimated to be lower 

22 or much lower than HDL conditions with no AFW.

23

24 This process suggests that the potential C-SGTR that may stem from indeterminate core 

25 damage sequences should not be modeled (e.g., they are in the unmodeled C-SGTR category) 

26 to avoid extensive modeling involved. It is deemed that such unmodeled sequences will be a 

27 small fraction of the total SGTR frequency captured in Steps 1, 3, and 4.

28

29 Two parameters of importance are used in the claim that such sequences are deemed to be a 

small fraction of the total C-SGTR:2 30

31

32 1. Failure probability of SSB (unisolated leaking loop) in one or more loops, Qfsg = 0.13, 

33 given operators isolate an SG due to AFW failure 

34

35 2. The conditional probability of C-SGTR = Qcsgtr = 0.01, given an indeterminate core 

36 damage sequence occurs.

37

38 As an approximation, the C-SGTR CDF of unmodeled sequences above can be estimated by 

39 multiplying the CDF with the fraction Qfsg*Qcsgtr = 0.0013. An example application is given in 

40 Section L.3.

41

 2 These values are given as expert judgment since they are not supported by publicly available calculations. If 

 plant-specific values are available, they should be used.
L-4

1 The five steps discussed above are summarized in Table L-1.

2

Table L-1 Process Summary for Event Trees and CDF Sequences 3

4

Category Treatment

1 Event Tree: SGTR as the initiator Use IE-SGTR ET; no additional C-SGTR.

2 Event Trees: LLOCA/XLOCA No potential for C-SGTR due to depressurization

Event Tree: ISLOCA No treatment of C-SGTR due to existing bypass

3

Event Tree: ATWS

If primary pressure relief fails, assume C-SGTR; 

otherwise, no C-SGTR on basis of very low 

frequency.

Event Trees: SSB / CSSB

Add new node (SSB-CSGTR) that equates to 

probability of existence of large flaw depth and 

route up-branch to the existing (non-C-SGTR) 

portion of the tree and down-branch to a 

consequential (subtree) version of the SGTR tree.

4 CDF Sequences: HDL Identify and label for Level 2 treatment; to be 

multiplied by P(C-SGTR), etc.

5 CDF Sequences: Non-HDL 

or Indeterminate 

Do not model further based on discussion in Step 5 

above.

5

6 As a final sanity check, examine the ratio of:

7

8 • (HDL CDF) / (Frequency of indeterminate core damage sequences)

9

10 The larger this ratio is, the less significant the unmodeled sequences in Step 5 will be.

11

IE-SSBI 

(or IE-SSBO) RPS SSB-CSGTR End State

1 2 3

No C-SGTR continue with the 

existing SSB ET logic

Success (~1)

Occurs C-SGTR Transfer to SGTR ET

(0.01)

Fails CD-CSGTR (*)

12

13 Figure L-1 Insertion of C-SGTR event tree node in SSB event trees

14 Note: (*) Although this sequence can be transferred to the ATWS event tree for further 

15 treatment, it may be more practical to assign it to the core damage end state for further 

16 treatment in L2 analysis, since the expected frequency of such a sequence is small.

17
L-5

IEV RPS PR-REL AFW ATWSCSGTR End State

1 2 3 4

Success

Yes continue with the 

existing ET logic

Occurs Yes. 2200 < P < 3300 No C-SGTR

continue with the 

existing ET logic

No ~1

C-SGTR CD-CSGTR

Fails (0.01)

(ATWS) Yes CD-CSGTR

No. P > 3300

No CD-CSGTR

1

2 Figure L-2 Insertion of C-SGTR event tree node in ATWS event tree

3 RPS = Reactor Protection System (trip)

4 PR-REL = Primary system pressure relief

5 P > 3300 = RCS pressure greater than 3,300 psi

6

7 L.3 Summary of the Results of the Application

8

9 The above approach was applied to a 4-loop Westinghouse NPP PRA model that did not 

10 originally have C-SGTR explicitly modeled in its Level 1 PRA model.

11

12 Some changes were made to the base model to capture pressure-induced SGTR (PI-SGTR) 

13 CDF sequences. The CDF sequences that are identifiable as HDL are marked by event tree 

14 rules to be transferred to the Level 2 model as C-SGTR. Those CDF sequences not captured in 

15 the above process, labeled as “unmodeled” sequences that may have some C-SGTR 

16 consequence, are then examined for their potential impact. The results are summarized in 

17 Table L-2. Based on these results, the following are observed:

18

19 • C-SGTR (and IE-SGTR) are a small fraction of CDF (<2%).

20

21 • C-SGTR potential is dominated by post core damage temperature-induced SGTR 

22 (TI-SGTR) (89%).

23

24 • PI-SGTR is a small contributor to C-SGTR (7%) and a very small contributor to 

25 CDF (<1%).

26

27 • Unmodeled C-SGTR sequences in this PRA model would be a small fraction of modeled 

28 C-SGTR sequences (3%).

29
L-6

1 The important qualifiers on these findings are:

2

3 • Consistent with the approach outlined in Section L.2, and with the state of practice in 

4 C-SGTR modeling, leaks below the critical break area (one double-ended tube break) 

5 are not considered.

6

7 • These results are for a given version of a PRA model. Any changes made to the model 

8 can affect these numbers, though there is no reason to believe that such changes would 

9 be significant enough to affect the above findings.

10

11 • These estimates (necessarily) project what the Level 2 TI-SGTR frequency will be, 

12 based on the high/dry/low frequency and the conditional TI-SGTR probability. This 

13 capturing does not include any “benefit” that the Level 2 will ultimately estimate with 

14 respect to operator actions prior to HL creep rupture. But again, this is not likely to affect 

15 the above findings.

16

17 Developing the estimates provided above was a tedious process, because (a) the high/dry/low 

18 assignment was a manual exercise and (b) most of the underlying frequencies come from 

19 consequential trees and were extracted manually. The former issue can be avoided if event 

20 tree rules that identify HDL sequences and label them as such for Level 2 analysis are built into 

21 the PRA model as a one-time effort. The latter issue may not apply to some model architecture 

22 and software package combinations.

23

24 This application to a PRA model illustrates, but does not prove, that the assumptions stated in 

25 the modeling approach of Section L.2 for the “unmodeled” sequences are valid. This exercise 

26 also demonstrated that this comprehensive, yet limited, intrusion into the PRA Level 1 model to 

27 estimate C-SGTR CDF is feasible.

28
L-7

Table L-2 Summary of C-SGTR Modeling Applied to a Specific PRA Model for a 4-Loop 1

Westinghouse Plant 2

3

Initiator Sequence CDF C-GTR 

Multiplier

C-SGTR 

Frequency

% of 

C-SGTR

IE-SGTR All 7.6E-8 0

IE-LLOCA/XLOCA/ISLOCA All 2.1E-7 0

Transients/SLOCA/MLOCA 

--> ATWS IE*RPS*/PR-REL*AFW 6.9E-8 0.01 6.9E-10 0.06%

Transients/SLOCA/MLOCA 

--> ATWS IE*RPS*PR-REL 6.2E-8 1 6.2E-8 5.00%

IE-SSB --> ATWS IE-SSBI*RPS 5.9E-9 1 5.9E-9 0.50%

IE-SSB --> ATWS IE-SSBO*RPS 3.0E-8 1 3.0E-8 2.40%

SSBI / SSBO IE-SSBI*/RPS*PI-SGTR 4.5E-10 1 4.5E-10 0.04%

SSBI / SSBO IE-SSBO*/RPS*PI-SGTR 2.3E-9 1 2.3E-9 0.20%

All transients --> 

consequential SSB

Transient IE*/RPS*...--

>CSSB-->PI-SGTR 2.0E-9 1 2.0E-9 0.16%

HDL No loop clearing 4.5E-5 0.024 1.1E-6 88.70%

HDL With loop clearing (*) 1

Non-HDL (b) Non-HDL with FSG 2.7E-5 0.0013 3.5E-8 2.90%

Non-HDL (a)

Non-HDL with possible 

AFW failure (**)

Sum = 7.3E-5 1.2E-6 100%

The items marked in yellow are not modeled.

(*) No sequences showed up among the dominant CDF sequences; not further examined in this calculation.

(**) Estimated to be a small contributor

(a) and (b) refer to Step 5 in Section L.2-1.

RPS = Reactor Protection System

PR-REL = Primary System Pressure Relief

SSBI (SSBO) = Secondary Side Break Inside (Outside) Containment

LLOCA (MLOCA, SLOCA) = Large (Medium, Small) LOCA

IE = Initiating Event

4

5

6







NUREG-2195

Draft

Consequential SGTR Analysis for Westinghouse and Combustion Engineering 

Plants with Thermally Treated Alloy 600 and 690 Steam Generator Tubes