Safety Evaluation Report

Related to the License Renewal 

of LaSalle County Station, 

Units 1 and 2

Docket Nos. 50-373 and 50-374

Exelon Generation Company, LLC

Office of Nuclear Reactor Regulation

NUREG-2205

 

Safety Evaluation Report

Related to the License Renewal 

of LaSalle County Station,

Units 1 and 2

Docket Nos. 50-373 and 50-374

Exelon Generation Company, LLC

Manuscript Completed: August 2016

Date Published: September 2016

Office of Nuclear Reactor Regulation

NUREG-2205

 

iii

ABSTRACT

This safety evaluation report (SER) documents the technical review of the LaSalle County 

Station, Units 1 and 2 (LSCS), license renewal application (LRA) by the United States (U.S.) 

Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated December 9, 2014, 

Exelon Generation Company, LLC (Exelon or the applicant), submitted the LRA in accordance 

with Title 10 of the Code of Federal Regulations, (10 CFR) Part 54, “Requirements for Renewal 

of Operating Licenses for Nuclear Power Plants.” Exelon requests renewal of the LSCS

operating licenses (Operating License Nos. NPF-11 and NPF-18) for a period of 20 years 

beyond the current expiration at midnight on April 17, 2022, for Unit 1, and at midnight on 

December 16, 2023, for Unit 2.

LSCS is located approximately 55 direct-line miles southwest of Chicago, IL. The NRC issued 

the Unit 1 and Unit 2 construction permits (CPPR-99 and CPPR-100, respectively) on 

September 7, 1973, and the operating licenses on April 17, 1982, for Unit 1, and 

December 16, 1983, for Unit 2. Units 1 and 2 are of a boiling water reactor design. General 

Electric (Nuclear Energy Division) supplied the nuclear steam supply system and Sargent & 

Lundy originally designed and constructed the balance of the plant. Units 1 and 2 each have a 

licensed power output of 3,546 megawatts thermal, with a gross electrical output of 

approximately 1,207 megawatts electric.

Unless otherwise indicated, this SER presents the status of the staff’s review of information 

submitted through June 8, 2016, the cutoff date for consideration in the SER. The two open 

items previously identified in the SER with open items, issued February 29, 2016, have been 

closed (see Section 1.5); therefore, no open items remain to be resolved before the final 

determination is reached by the staff on the LRA.

v 

TABLE OF CONTENTS

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

TABLE OF CONTENTS ............................................................................................................ v

LIST OF TABLES.................................................................................................................... xv

ABBREVIATIONS .................................................................................................................. xvii

INTRODUCTION AND GENERAL DISCUSSION............................................ 1-1

1.1 Introduction ................................................................................................................. 1-1

1.2 License Renewal Background ..................................................................................... 1-2

1.2.1 Safety Review.................................................................................................. 1-3

1.2.2 Environmental Review ..................................................................................... 1-4

1.3 Principal Review Matters ............................................................................................. 1-5

1.4 Interim Staff Guidance................................................................................................. 1-6

1.5 Summary – Closure of Open Items.............................................................................. 1-8

1.6 Summary of Confirmatory Items .................................................................................. 1-9

1.7 Summary of Proposed License Conditions .................................................................. 1-9

STRUCTURES AND COMPONENTS SUBJECT TO AGING 

MANAGEMENT REVIEW................................................................................ 2-1

2.1 Scoping and Screening Methodology .......................................................................... 2-1

2.1.1 Introduction...................................................................................................... 2-1

2.1.2 Summary of Technical Information in the Application....................................... 2-1

2.1.3 Scoping and Screening Program Review......................................................... 2-1

2.1.3.1 Implementing Procedures and Documentation Sources Used 

for Scoping and Screening............................................................... 2-2

2.1.3.2 Quality Controls Applied to LRA Development ................................. 2-4

2.1.3.3 Training............................................................................................ 2-5

2.1.3.4 Scoping and Screening Program Review Conclusion....................... 2-5

2.1.4 Plant Systems, Structures, and Components Scoping Methodology ................ 2-5

2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1).................. 2-6

2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2).................. 2-7

2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3)................ 2-11

2.1.4.4 Plant Level Scoping of Systems and Structures............................. 2-13

2.1.4.5 Mechanical Scoping....................................................................... 2-14

2.1.4.6 Structural Scoping.......................................................................... 2-15

2.1.4.7 Electrical Scoping .......................................................................... 2-17

2.1.4.8 Scoping Methodology Conclusion .................................................. 2-18

2.1.5 Screening Methodology ................................................................................. 2-18

2.1.5.1 General Screening Methodology.................................................... 2-18

2.1.5.2 Mechanical Component Screening................................................. 2-19

2.1.5.3 Structural Component Screening ................................................... 2-20
vi

2.1.5.4 Electrical Component Screening .................................................... 2-21

2.1.5.5 Screening Methodology Conclusion ............................................... 2-22

2.1.6 Summary of Evaluation Findings.................................................................... 2-22

2.2 Plant Level Scoping Results ...................................................................................... 2-22

2.2.1 Introduction.................................................................................................... 2-22

2.2.2 Summary of Technical Information in the Application..................................... 2-23

2.2.3 Staff Evaluation.............................................................................................. 2-23

2.2.4 Conclusion..................................................................................................... 2-23

2.3 Scoping and Screening Results: Mechanical Systems ............................................. 2-23

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System................................ 2-24

2.3.1.1 Reactor Coolant Pressure Boundary System ................................. 2-25

2.3.1.2 Reactor Vessel............................................................................... 2-26

2.3.1.3 Reactor Vessel Internals ................................................................ 2-28

2.3.2 Engineered Safety Features Systems............................................................ 2-29

2.3.2.1 High Pressure Core Spray System................................................. 2-30

2.3.2.2 Low Pressure Core Spray System ................................................. 2-31

2.3.2.3 Reactor Core Isolation Cooling System.......................................... 2-32

2.3.2.4 Residual Heat Removal System..................................................... 2-34

2.3.2.5 Standby Gas Treatment System .................................................... 2-35

2.3.3 Auxiliary Systems........................................................................................... 2-37

2.3.3.1 Closed Cycle Cooling Water System.............................................. 2-37

2.3.3.2 Combustible Gas Control System .................................................. 2-39

2.3.3.3 Compressed Air System ................................................................ 2-41

2.3.3.4 Control Rod Drive System.............................................................. 2-42

2.3.3.5 Control Room Ventilation System................................................... 2-44

2.3.3.6 Cranes, Hoists and Refueling Equipment System.......................... 2-45

2.3.3.7 Demineralized Water Makeup System ........................................... 2-47

2.3.3.8 Diesel Generator and Auxiliaries System ....................................... 2-48

2.3.3.9 Drywell Pneumatic System............................................................. 2-50

2.3.3.10 Electrical Penetration Pressurization System ................................. 2-51

2.3.3.11 Essential Cooling Water System .................................................... 2-52

2.3.3.12 Fire Protection System................................................................... 2-53

2.3.3.13 Fuel Pool Cooling and Storage System.......................................... 2-62

2.3.3.14 Nonessential Cooling Water System .............................................. 2-65

2.3.3.15 Nonsafety-Related Ventilation System ........................................... 2-66

2.3.3.16 Plant Drainage System .................................................................. 2-68

2.3.3.17 Primary Containment Ventilation System ....................................... 2-70

2.3.3.18 Process Radiation Monitoring System............................................ 2-71

2.3.3.19 Process Sampling and Post Accident Monitoring System .............. 2-73

2.3.3.20 Radwaste System .......................................................................... 2-75

2.3.3.21 Reactor Water Cleanup System..................................................... 2-76
vii

2.3.3.22 Safety-Related Ventilation System................................................. 2-78

2.3.3.23 Standby Liquid Control System ...................................................... 2-79

2.3.3.24 Suppression Pool Cleanup System................................................ 2-80

2.3.3.25 Traversing Incore Probe System.................................................... 2-81

2.3.4 Steam and Power Conversion System........................................................... 2-82

2.3.4.1 Condensate System....................................................................... 2-82

2.3.4.2 Condenser and Air Removal System ............................................. 2-83

2.3.4.3 Feedwater System ......................................................................... 2-85

2.3.4.4 Main Steam System....................................................................... 2-87

2.3.4.5 Main Turbine and Auxiliaries System ............................................. 2-88

2.4 Scoping and Screening Results: Structures and Component Supports..................... 2-90

2.4.1 Auxiliary Building............................................................................................ 2-91

2.4.1.1 Summary of Technical Information in the Application..................... 2-91

2.4.1.2 Staff Evaluation.............................................................................. 2-92

2.4.1.3 Conclusion ..................................................................................... 2-92

2.4.2 Component Supports Commodity Group ....................................................... 2-92

2.4.2.1 Summary of Technical Information in the Application..................... 2-92

2.4.2.2 Staff Evaluation.............................................................................. 2-93

2.4.2.3 Conclusion ..................................................................................... 2-93

2.4.3 Cooling Lake.................................................................................................. 2-93

2.4.3.1 Summary of Technical Information in the Application..................... 2-93

2.4.3.2 Staff Evaluation.............................................................................. 2-94

2.4.3.3 Conclusion ..................................................................................... 2-95

2.4.4 Diesel Generator Building .............................................................................. 2-95

2.4.4.1 Summary of Technical Information in the Application..................... 2-95

2.4.4.2 Staff Evaluation.............................................................................. 2-95

2.4.4.3 Conclusion ..................................................................................... 2-96

2.4.5 Lake Screen House ....................................................................................... 2-96

2.4.5.1 Summary of Technical Information in the Application..................... 2-96

2.4.5.2 Staff Evaluation.............................................................................. 2-97

2.4.5.3 Conclusion ..................................................................................... 2-97

2.4.6 Offgas Building .............................................................................................. 2-97

2.4.6.1 Summary of Technical Information in the Application..................... 2-97

2.4.6.2 Staff Evaluation.............................................................................. 2-98

2.4.6.3 Conclusion ..................................................................................... 2-98

2.4.7 Primary Containment ..................................................................................... 2-98

2.4.7.1 Summary of Technical Information in the Application..................... 2-98

2.4.7.2 Staff Evaluation.............................................................................. 2-99

2.4.7.3 Conclusion ................................................................................... 2-100

2.4.8 Radwaste Building ....................................................................................... 2-100

2.4.8.1 Summary of Technical Information in the Application................... 2-100
viii

2.4.8.2 Staff Evaluation............................................................................ 2-101

2.4.8.3 Conclusion ................................................................................... 2-101

2.4.9 Reactor Building .......................................................................................... 2-101

2.4.9.1 Summary of Technical Information in the Application................... 2-101

2.4.9.2 Staff Evaluation............................................................................ 2-102

2.4.9.3 Conclusion ................................................................................... 2-102

2.4.10 Structural Commodity Group........................................................................ 2-102

2.4.10.1 Summary of Technical Information in the Application................... 2-102

2.4.10.2 Staff Evaluation............................................................................ 2-103

2.4.10.3 Conclusion ................................................................................... 2-104

2.4.11 Switchyard Structures .................................................................................. 2-104

2.4.11.1 Summary of Technical Information in the Application................... 2-104

2.4.11.2 Staff Evaluation............................................................................ 2-105

2.4.11.3 Conclusion ................................................................................... 2-105

2.4.12 Tank Foundations and Dikes ....................................................................... 2-105

2.4.12.1 Summary of Technical Information in the Application................... 2-105

2.4.12.2 Staff Evaluation............................................................................ 2-106

2.4.12.3 Conclusion ................................................................................... 2-106

2.4.13 Turbine Building........................................................................................... 2-106

2.4.13.1 Summary of Technical Information in the Application................... 2-106

2.4.13.2 Staff Evaluation............................................................................ 2-107

2.4.13.3 Conclusion ................................................................................... 2-107

2.4.14 Yard Structures............................................................................................ 2-107

2.4.14.1 Summary of Technical Information in the Application................... 2-107

2.4.14.2 Staff Evaluation............................................................................ 2-108

2.4.14.3 Conclusion ................................................................................... 2-108

2.5 Scoping and Screening Results: Electrical ............................................................. 2-108

2.5.1 Electrical Systems........................................................................................ 2-109

2.5.1.1 Summary of Technical Information in the Application................... 2-109

2.5.1.2 Staff Evaluation............................................................................ 2-110

2.5.1.3 Conclusion ................................................................................... 2-112

2.6 Conclusion for Scoping and Screening.................................................................... 2-112

AGING MANAGEMENT REVIEW RESULTS.................................................. 3-1

3.0 Applicant’s Use of the Generic Aging Lessons Learned Report................................... 3-1

3.0.1 Format of the License Renewal Application ..................................................... 3-2

3.0.1.1 Overview of Table 1’s....................................................................... 3-2

3.0.1.2 Overview of Table 2’s....................................................................... 3-3

3.0.2 Staff’s Review Process .................................................................................... 3-3

3.0.2.1 Review of Aging Management Programs ......................................... 3-4

3.0.2.2 Review of AMR Results ................................................................... 3-5

3.0.2.3 UFSAR Supplement......................................................................... 3-6
ix

3.0.2.4 Documentation and Documents Reviewed....................................... 3-6

3.0.3 Aging Management Programs.......................................................................... 3-7

3.0.3.1 AMPs Consistent with the GALL Report......................................... 3-10

3.0.3.2 AMPs Consistent with the GALL Report with Exceptions or 

Enhancements............................................................................... 3-60

3.0.3.3 AMPs Not Consistent with or Not Addressed in the 

GALL Report................................................................................ 3-144

3.0.4 Quality Assurance Program Attributes Integral to Aging Management 

Programs ..................................................................................................... 3-157

3.0.4.1 Summary of Technical Information in the Application................... 3-157

3.0.4.2 Staff Evaluation............................................................................ 3-157

3.0.4.3 Conclusion ................................................................................... 3-158

3.0.5 Operating Experience for Aging Management Programs ............................. 3-159

3.0.5.1 Summary of Technical Information............................................... 3-159

3.0.5.2 Staff Evaluation............................................................................ 3-159

3.0.5.3 UFSAR Supplement..................................................................... 3-164

3.0.5.4 Conclusion ................................................................................... 3-164

3.1 Aging Management of Reactor Vessel, Internals and Reactor Coolant System....... 3-165

3.1.1 Summary of Technical Information in the Application................................... 3-165

3.1.2 Staff Evaluation............................................................................................ 3-165

3.1.2.1 AMR Results Consistent with the GALL Report............................ 3-190

3.1.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation Is Recommended ........................................... 3-195

3.1.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL Report................................................................................ 3-201

3.1.3 Conclusion................................................................................................... 3-204

3.2 Aging Management of Engineered Safety Features Systems.................................. 3-204

3.2.1 Summary of Technical Information in the Application................................... 3-204

3.2.2 Staff Evaluation............................................................................................ 3-204

3.2.2.1 AMR Results Consistent with the GALL Report............................ 3-216

3.2.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation Is Recommended ........................................... 3-220

3.2.2.3 Results Not Consistent with or Not Addressed in the 

GALL Report................................................................................ 3-224

3.2.3 Conclusion................................................................................................... 3-229

3.3 Aging Management of Auxiliary Systems................................................................. 3-230

3.3.1 Summary of Technical Information in the Application................................... 3-230

3.3.2 Staff Evaluation............................................................................................ 3-231

3.3.2.1 AMR Results Consistent with the GALL Report............................ 3-256

3.3.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation Is Recommended ........................................... 3-270

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL Report................................................................................ 3-274
x

3.3.3 Conclusion................................................................................................... 3-286

3.4 Aging Management of Steam and Power Conversion System................................. 3-286

3.4.1 Summary of Technical Information in the Application................................... 3-286

3.4.2 Staff Evaluation............................................................................................ 3-287

3.4.2.1 AMR Results Consistent with the GALL Report............................ 3-298

3.4.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation Is Recommended ........................................... 3-301

3.4.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL Report................................................................................ 3-303

3.4.3 Conclusion................................................................................................... 3-305

3.5 Aging Management of Structures and Component Supports ................................... 3-305

3.5.1 Summary of Technical Information in the Application................................... 3-306

3.5.2 Staff Evaluation............................................................................................ 3-306

3.5.2.1 AMR Results Consistent with the GALL Report............................ 3-323

3.5.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation Is Recommended ........................................... 3-332

3.5.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL ........................................................................................... 3-351

3.5.3 Conclusion................................................................................................... 3-357

3.6 Aging Management of Electrical Components ......................................................... 3-357

3.6.1 Summary of Technical Information in the Application................................... 3-358

3.6.2 Staff Evaluation............................................................................................ 3-358

3.6.2.1 AMR Results Consistent with the GALL Report............................ 3-363

3.6.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation Is Recommended ........................................... 3-365

3.6.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL Report................................................................................ 3-369

3.6.3 Conclusion................................................................................................... 3-372

3.7 Conclusion for Aging Management Review Results................................................. 3-373

TIME-LIMITED AGING ANALYSES................................................................ 4-1

4.1 Identification of Time-Limited Aging Analyses.............................................................. 4-1

4.1.1 Summary of Technical Information in the Application....................................... 4-2

4.1.1.1 Identification of TLAAs ..................................................................... 4-2

4.1.1.2 Identification of Regulatory Exemptions ........................................... 4-4

4.1.2 Staff Evaluation................................................................................................ 4-4

4.1.2.1 Identification of TLAAs ..................................................................... 4-4

4.1.2.2 Identification of Exemptions in the LRA.......................................... 4-15

4.1.3 Conclusion..................................................................................................... 4-17

4.2 Reactor Vessel and Internals Neutron Embrittlement Analyses ................................. 4-18

4.2.1 Neutron Fluence Analyses ............................................................................. 4-18

4.2.1.1 Summary of Technical Information in the Application..................... 4-18

4.2.1.2 Staff Evaluation.............................................................................. 4-19
xi

4.2.1.3 UFSAR Supplement....................................................................... 4-20

4.2.1.4 Conclusion ..................................................................................... 4-20

4.2.2 Upper-Shelf Energy Analyses ........................................................................ 4-20

4.2.2.1 Summary of Technical Information in the Application..................... 4-20

4.2.2.2 Staff Evaluation.............................................................................. 4-21

4.2.2.3 UFSAR Supplement....................................................................... 4-23

4.2.2.4 Conclusion ..................................................................................... 4-24

4.2.3 Adjusted Reference Temperature Analyses................................................... 4-24

4.2.3.1 Summary of Technical Information in the Application..................... 4-24

4.2.3.2 Staff Evaluation.............................................................................. 4-24

4.2.3.3 UFSAR Supplement....................................................................... 4-26

4.2.3.4 Conclusion ..................................................................................... 4-27

4.2.4 Pressure-Temperature Limits......................................................................... 4-27

4.2.4.1 Summary of Technical Information in the Application..................... 4-27

4.2.4.2 Staff Evaluation.............................................................................. 4-28

4.2.4.3 UFSAR Supplement....................................................................... 4-30

4.2.4.4 Conclusion ..................................................................................... 4-30

4.2.5 Axial Weld Failure Probability Assessment Analyses ..................................... 4-30

4.2.5.1 Summary of Technical Information in the Application ..................... 4-30

4.2.5.2 Staff Evaluation.............................................................................. 4-31

4.2.5.3 UFSAR Supplement....................................................................... 4-35

4.2.5.4 Conclusion ..................................................................................... 4-36

4.2.6 Circumferential Weld Failure Probability Assessment Analyses..................... 4-36

4.2.6.1 Summary of Technical Information in the Application..................... 4-36

4.2.6.2 Staff Evaluation.............................................................................. 4-37

4.2.6.3 UFSAR Supplement....................................................................... 4-38

4.2.6.4 Conclusion ..................................................................................... 4-38

4.2.7 Reactor Pressure Vessel Reflood Thermal Shock Analyses .......................... 4-38

4.2.7.1 Summary of Technical Information in the Application..................... 4-38

4.2.7.2 Staff Evaluation.............................................................................. 4-39

4.2.7.3 UFSAR Supplement....................................................................... 4-42

4.2.7.4 Conclusion ..................................................................................... 4-43

4.2.8 RPV Core Plate Rim Hold-Down Bolt Loss of Preload Analysis ..................... 4-43

4.2.8.1 Summary of Technical Information in the Application..................... 4-43

4.2.8.2 Staff Evaluation.............................................................................. 4-43

4.2.8.3 UFSAR Supplement....................................................................... 4-45

4.2.8.4 Conclusion ..................................................................................... 4-45

4.2.9 Jet Pump Riser Brace Clamp Loss of Preload Analysis ................................. 4-45

4.2.9.1 Summary of Technical Information in the Application..................... 4-45

4.2.9.2 Staff Evaluation.............................................................................. 4-45

4.2.9.3 UFSAR Supplement....................................................................... 4-46
xii

4.2.9.4 Conclusion ..................................................................................... 4-46

4.2.10 Jet Pump Slip Joint Repair Clamp Loss of Preload Analysis .......................... 4-46

4.2.10.1 Summary of Technical Information in the Application..................... 4-46

4.2.10.2 Staff Evaluation.............................................................................. 4-47

4.2.10.3 UFSAR Supplement....................................................................... 4-48

4.2.10.4 Conclusion ..................................................................................... 4-48

4.3 Metal Fatigue Analyses ............................................................................................. 4-48

4.3.1 ASME Section III, Class 1 Fatigue Analyses.................................................. 4-49

4.3.1.1 Summary of Technical Information................................................. 4-49

4.3.1.2 Staff Evaluation.............................................................................. 4-49

4.3.1.3 UFSAR Supplement....................................................................... 4-50

4.3.1.4 Conclusion ..................................................................................... 4-50

4.3.2 ASME Section III, Class 2 and 3 and ANSI B31.1 Allowable Stress 

Analyses ........................................................................................................ 4-50

4.3.2.1 Summary of Technical Information................................................. 4-50

4.3.2.2 Staff Evaluation.............................................................................. 4-51

4.3.2.3 UFSAR Supplement....................................................................... 4-53

4.3.2.4 Conclusion ..................................................................................... 4-53

4.3.3 Environmental Fatigue Analyses for RPV and Class 1 Piping ........................ 4-53

4.3.3.1 Summary of Technical Information................................................. 4-53

4.3.3.2 Staff Evaluation.............................................................................. 4-54

4.3.3.3 UFSAR Supplement....................................................................... 4-60

4.3.3.4 Conclusion ..................................................................................... 4-60

4.3.4 Reactor Vessel Internals Fatigue Analyses.................................................... 4-60

4.3.4.1 Summary of Technical Information................................................. 4-60

4.3.4.2 Staff Evaluation.............................................................................. 4-61

4.3.4.3 UFSAR Supplement....................................................................... 4-61

4.3.4.4 Conclusion ..................................................................................... 4-62

4.3.5 High-Energy Line Break Analyses Based on Fatigue ..................................... 4-62

4.3.5.1 Summary of Technical Information................................................. 4-62

4.3.5.2 Staff Evaluation.............................................................................. 4-62

4.3.5.3 UFSAR Supplement....................................................................... 4-63

4.3.5.4 Conclusion ..................................................................................... 4-63

4.3.6 Main Steam Relief Valve Discharge Piping Fatigue Analyses ........................ 4-63

4.3.6.1 Summary of Technical Information................................................. 4-63

4.3.6.2 Staff Evaluation.............................................................................. 4-64

4.3.6.3 UFSAR Supplement....................................................................... 4-65

4.3.6.4 Conclusion ..................................................................................... 4-65

4.4 Environmental Qualification (EQ) of Electric Components ......................................... 4-65

4.4.1 Summary of Technical Information in the Application..................................... 4-65

4.4.2 Staff Evaluation.............................................................................................. 4-66
xiii

4.4.3 UFSAR Supplement....................................................................................... 4-67

4.4.4 Conclusion..................................................................................................... 4-68

4.5 Concrete Containment Tendon Prestress Analyses................................................... 4-68

4.5.1 Summary of Technical Information in the Application..................................... 4-68

4.5.2 Staff Evaluation.............................................................................................. 4-69

4.5.3 UFSAR Supplement....................................................................................... 4-70

4.5.4 Conclusion..................................................................................................... 4-70

4.6 Primary Containment Fatigue Analyses..................................................................... 4-70

4.6.1 Primary Containment Liner and Penetrations Fatigue Analyses..................... 4-71

4.6.1.1 Summary of Technical Information in the Application..................... 4-71

4.6.1.2 Staff Evaluation.............................................................................. 4-71

4.6.1.3 UFSAR Supplement....................................................................... 4-74

4.6.1.4 Conclusion ..................................................................................... 4-75

4.6.2 Primary Containment Refueling Bellows Fatigue Analysis ............................. 4-75

4.6.2.1 Summary of Technical Information in the Application..................... 4-75

4.6.2.2 Staff Evaluation.............................................................................. 4-75

4.6.2.3 UFSAR Supplement....................................................................... 4-76

4.6.2.4 Conclusion ..................................................................................... 4-76

4.6.3 Primary Containment Downcomer Vents Fatigue Analysis............................. 4-76

4.6.3.1 Summary of Technical Information in the Application..................... 4-76

4.6.3.2 Staff Evaluation.............................................................................. 4-77

4.6.3.3 UFSAR Supplement....................................................................... 4-77

4.6.3.4 Conclusion ..................................................................................... 4-77

4.7 Other Plant-Specific Time-Limited Aging Analyses.................................................... 4-78

4.7.1 Reactor Building Crane Cyclic Loading Analysis............................................ 4-78

4.7.1.1 Summary of Technical Information in the Application..................... 4-78

4.7.1.2 Staff Evaluation.............................................................................. 4-78

4.7.1.3 UFSAR Supplement....................................................................... 4-79

4.7.1.4 Conclusion ..................................................................................... 4-80

4.7.2 Main Steam Line Flow Restrictors Erosion Analysis....................................... 4-80

4.7.2.1 Summary of Technical Information in the Application..................... 4-80

4.7.2.2 Staff Evaluation.............................................................................. 4-80

4.7.2.3 UFSAR Supplement....................................................................... 4-81

4.7.2.4 Conclusion ..................................................................................... 4-81

4.8 Conclusion for TLAAs................................................................................................ 4-81
xiv

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR 

SAFEGUARDS................................................................................................ 5-1

CONCLUSION................................................................................................. 6-1

APPENDICES

LICENSE RENEWAL COMMITMENTS...........................................................A-1

CHRONOLOGY...............................................................................................B-1

PRINCIPAL CONTRIBUTORS........................................................................C-1

REFERENCES ................................................................................................D-1
xv

LIST OF TABLES

Current Interim Staff Guidance........................................................................... 1-7

LSCS Aging Management Programs.................................................................. 3-7

Staff Evaluation for Reactor Vessel, Internals and Reactor Coolant 

System Components in the GALL Report....................................................... 3-166

Staff Evaluation for Engineered Safety Features Systems Components in 

the GALL Report ............................................................................................ 3-205

Staff Evaluation for Auxiliary Systems Components in the GALL Report........ 3-232

Staff Evaluation for Steam and Power Conversion System Components 

in the GALL Report ........................................................................................ 3-288

Staff Evaluation for Structures and Component Supports Components in 

the GALL Report ............................................................................................ 3-307

Staff Evaluation for Electrical Components in the GALL Report ..................... 3-359

Table A.1-1 LaSalle County Station, Units 1 and 2, License Renewal Commitments.............A-2
xvi
xvii

ABBREVIATIONS

°F degree(s) Fahrenheit

1/4T one-fourth of the way through the vessel wall measured from the internal surface 

of the vessel

AAI applicant action item

AC alternating current

ACI American Concrete Institute

ACRS Advisory Committee on Reactor Safeguards

ACSR aluminum conductor steel reinforced

ADAMS Agencywide Document Access and Management System

ADS automatic depressurization system

AEM aging effect/mechanism

AERM aging effect requiring management

AFW auxiliary feedwater

AMP aging management program

AMR aging management review

ANSI American National Standards Institute

ART adjusted reference temperature

ASME American Society of Mechanical Engineers

ASTM American Society for Testing and Materials

ATWS anticipated transient without scram

BTP Branch Technical Position

BWR boiling water reactor

BWROG Boiling Water Reactor Owners Group

BWRVIP Boiling Water Reactor Vessel and Internals Project

CAR condenser and air removal

CAS Compressed Air System

CASS cast austenitic stainless steel

CB&I Chicago Bridge and Iron Company

CCW Closed Cycle Cooling Water

CE Combustion Engineering

CECo Commonwealth Edison Company

CEOG Combustion Engineering Owners Group

CFR Code of Federal Regulations

CGC combustible gas control

CHRE Cranes, Hoists and Refueling Equipment

CLB current licensing basis

CMAA Crane Manufacturers Association of America

CMTR certified material test report

CO2 carbon dioxide

CRD control rod drive

CRDRL control rod drive return line

CRV control room ventilation

CSCS core standby cooling system

CUF cumulative usage factor

CUFen environmentally adjusted cumulative usage factor
xviii

DBA design basis accident

DBE design basis event

DGA diesel generator and auxiliaries

DPS Drywell Pneumatic System

EAF environmentally assisted fatigue

ECCS Emergency Core Cooling System

EDG emergency diesel generator

EFPY effective full-power year

EPP electrical penetration pressurization

EPRI Electric Power Research Institute

EQ environmental qualification

ER environmental report (Applicant’s Environmental Report Operating License 

Renewal Stage)

ESF engineered safety features

Exelon Exelon Generation Company, LLC

FASA focused area self-assessment

Fen environmental fatigue life correction factor

FERC Federal Energy Regulatory Commission

FPR fire protection report

FR Federal Register

FSAR final safety analysis report

ft foot (feet)

ft-lb foot-pound

GALL Generic Aging Lessons Learned

GE General Electric Company

GEH General Electric Hitachi

GEIS Generic Environmental Impact Statement

GL generic letter

GSI generic safety issue

HAZ heat affected zone

HELB high-energy line break

HPCS high pressure core spray

HPSI high-pressure safety injection

HVAC heating, ventilation, and air conditioning

I&C instrumentation and controls

IASCC irradiation-assisted stress corrosion cracking

ID inside diameter

IE inspection and enforcement

I&FE inspection and flaw evaluation

IGSCC intergranular stress corrosion cracking

IN information notice

INPO Institute of Nuclear Power Operations

IPA integrated plant assessment

ISG interim staff guidance

ISI inservice inspection

ISP integrated surveillance program
xix

ksi kilopound(s) per square inch

kV kilovolt(s)

lb pound(s)

LBB leak before break

LCO limiting condition(s) of operation

LOCA loss-of-coolant accident

LPCI low-pressure coolant injection

LPCS low pressure core spray

LPRM local power range monitor

LRA license renewal application

LR-ISG license renewal interim staff guidance

LSCS LaSalle County Station, Units 1 and 2

LTOP low-temperature overpressure protection

μm micrometer

MEB metal-enclosed bus

MeV million electron volt(s)

MIC microbiologically-influenced corrosion

MoS2 molybdenum disulfide

MPa megapascal

mpy mil per year

MRV minimum required valve

MSRV main steam relief valve

MS main steam

MSIV main steam isolation valve

MTA main turbine and auxiliaries

mV millivolt(s)

n/cm2 neutrons per square centimeter

NEDO New Energy and Industrial Technology Development Organization

NEI Nuclear Energy Institute

NFPA National Fire Protection Association

NPS nominal pipe size

NRC U.S. Nuclear Regulatory Commission

OBE operating-basis earthquake

OI Open Item

OPEX Exelon Operating Experience (Program)

PCV primary containment ventilation

pH potential of hydrogen

PLL predicted lower limit

PSP process sampling and post-accident monitoring

psi pound(s) per square inch

psig pound(s) per square inch, gauge

P-T pressure-temperature

PTLR pressure-temperature limit report

PVC polyvinyl chloride

PWR pressurized water reactor

PWSCC primary water stress corrosion cracking
xx

QA quality assurance

radwaste radioactive waste

RAI request for additional information

RAMA Radiation Analysis Modeling Application

RBCCW reactor building closed cooling water

RCIC reactor core isolation cooling

RCP reactor coolant pump

RCPB reactor coolant pressure boundary

RCS Reactor Coolant System

RCSC Research Council on Structural Connections

RFO refueling outage

RG regulatory guide

RHR residual heat removal

RI-ISI Risk-Informed Inservice Inspection

RPV reactor pressure vessel

RTNDT reference temperature nil ductility transition

RVI reactor vessel internals

RWCU reactor water cleanup

SAT system auxiliary transformer

SBA small break accident

SBO station blackout

SC structure and component

SCC stress corrosion cracking

SE safety evaluation

SER safety evaluation report

SGT Standby Gas Treatment

SLC standby liquid control

SMAW shielded metal-arc welding

S-N stress versus number of cycles

SPC Suppression Pool Cleanup

SRP Standard Review Plan

SRM source range monitor

SRP-LR Standard Review Plan for Review of License Renewal Applications for Nuclear 

Power Plants

SRV safety-related ventilation

SSC system, structure, and component

SSE safe-shutdown earthquake

TBCCW turbine building closed cooling water

TIP traversing incore probe

TLAA time-limited aging analysis

TS Technical Specification(s)

UFSAR updated final safety analysis report

USE upper-shelf energy

UT ultrasonic testing

UV ultraviolet
xxi

VAC volt(s) alternating current

VDC volt(s) direct current

VFLD vessel flange leak detection

WPC wear particle count

yr year

Zn zinc

1-1

INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

This document is a safety evaluation report (SER) on the license renewal application (LRA) for 

LaSalle County Station, Units 1 and 2 (LSCS), as filed by Exelon Generation Company, LLC 

(Exelon or the applicant). By letter dated December 9, 2014, Exelon submitted its application to 

the United States (U.S.) Nuclear Regulatory Commission (NRC) for renewal of the LSCS

operating licenses for an additional 20 years. The NRC staff (the staff) prepared this report to 

summarize the results of its safety review of the LRA for compliance with Title 10 of the Code of 

Federal Regulations (CFR) Part 54, “Requirements for Renewal of Operating Licenses for 

Nuclear Power Plants.” The NRC project manager for the license renewal review is Mr. Jeffrey 

Mitchell. Mr. Mitchell may be contacted by telephone at 301-415-3019 or by electronic mail at 

jeffrey.mitchell2@nrc.gov. Alternatively, written correspondence may be sent to the following 

address:

Division of License Renewal

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

Attention: Jeffrey Mitchell, Mail Stop O11-F1

In its December 9, 2014, submission letter, the applicant requested renewal of the operating 

licenses issued under Section 103 (Operating License Nos. NPF-11 and NPF-18) of the Atomic 

Energy Act of 1954, as amended (42 U.S.C. 2011 et seq.), for Units 1 and 2, respectively, for a 

period of 20 years beyond the current expiration at midnight on April 17, 2022, for Unit 1 and at 

midnight on December 16, 2023, for Unit 2. LSCS is located approximately 55 direct-line miles 

southwest of Chicago, Illinois. The NRC issued the construction permits for Units 1 and 2 on 

September 10, 1973. The NRC issued the operating licenses for Unit 1 and Unit 2 on 

April 17, 1982, and December 16, 1983, respectively. Units 1 and 2 are of a boiling water 

reactor (BWR) design. General Electric (Nuclear Energy Division) supplied the nuclear steam 

supply system, and Sargent & Lundy originally designed and constructed the balance of the 

plant. Units 1 and 2 each have a licensed power output of 3,546 megawatts thermal, with a 

gross electrical output of approximately 1,207 megawatts electric each. The updated final 

safety analysis report (UFSAR) shows details of the plant and the site.

The license renewal process consists of two concurrent technical reviews: a review of safety 

issues, and an environmental review. The NRC regulations at 10 CFR Part 54, “Requirements 

for Renewal of Operating Licenses for Nuclear Power Plants,” and 10 CFR Part 51, 

“Environmental Protection Regulations for Domestic Licensing and Related Regulatory 

Functions,” respectively, set forth requirements for these reviews. The safety review for the 

LSCS license renewal is based on the applicant’s LRA and responses to the staff’s requests for 

additional information (RAIs). The applicant supplemented the LRA and provided clarifications 

through its responses to the staff’s RAIs in audits, meetings, and docketed correspondence. 

Unless otherwise noted, the staff reviewed and considered information submitted through 

June 8, 2016. The staff reviewed information received after this date depending on the stage of 

the safety review and the volume and complexity of the information. The public may view the 

LRA and all pertinent information and materials, including the UFSAR, at the NRC Public 

Document Room located on the first floor of One White Flint North, 11555 Rockville Pike, 
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Rockville, MD 20852-2738 (301-415-4737/800-397-4209), and at the Reddick Public Library 

District, 1010 Canal St., Ottawa, IL 61350; Marseilles Public Library, 155 East Bluff St., 

Marseilles, IL 61341; and Seneca Public Library District, 210 N. Main St., Seneca, IL 61360. In 

addition, the public may find the LRA, as well as materials related to the license renewal review, 

on the NRC Web site at http://www.nrc.gov.

This SER summarizes the results of the staff’s safety review of the LRA and describes the 

technical details considered in evaluating the safety aspects of the LSCS’s proposed operation 

for an additional 20 years beyond the term of the current operating licenses. The staff reviewed 

the LRA in accordance with NRC regulations and the guidance in NUREG-1800, Revision 2, 

“Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants”

(SRP-LR), dated December 2010.

SER Sections 2 through 4 address the staff’s evaluation of license renewal issues considered 

during the review of the application. SER Section 5 is reserved for the report of the Advisory 

Committee on Reactor Safeguards (ACRS). The conclusions of this SER are in Section 6.

SER Appendix A is a table showing the applicant’s commitments for renewal of the operating 

licenses. SER Appendix B is a chronology of the principal correspondence between the staff 

and the applicant regarding the LRA review. SER Appendix C is a list of principal contributors 

to the SER, and Appendix D is a bibliography of the references in support of the staff’s review.

In accordance with 10 CFR Part 51, the staff prepared a draft plant-specific supplement to 

NUREG-1437, “Generic Environmental Impact Statement for License Renewal of Nuclear 

Plants (GEIS).” This supplement discusses the environmental considerations for license 

renewal for LSCS. The staff issued draft, plant-specific GEIS Supplement 57, “Generic 

Environmental Impact Statement for License Renewal of Nuclear Power Plants, Supplement 57, 

Regarding LaSalle County Station, Units 1 and 2, Draft Report for Comment,” in February 2016.

1.2 License Renewal Background

In accordance with the Atomic Energy Act of 1954, as amended, and NRC regulations, 

operating licenses for commercial power reactors are issued for 40 years and can be renewed 

for up to 20 additional years. The original 40-year license term was selected based on 

economic and antitrust considerations rather than on technical limitations; however, some 

individual plant and equipment designs may have been engineered for an expected 40-year 

service life.

In 1982, the staff anticipated interest in license renewal and held a workshop on nuclear power 

plant aging. This workshop led the NRC to establish a comprehensive program plan for nuclear 

plant aging research. From the results of that research, a technical review group concluded that 

many aging phenomena are readily manageable and pose no technical issues precluding life 

extension for nuclear power plants. In 1986, the staff published a request for comment on a 

policy statement that would address major policy, technical, and procedural issues related to 

license renewal for nuclear power plants.

In 1991, the staff published 10 CFR Part 54, the License Renewal Rule (Volume 56 of the 

Federal Register, page 64943 (56 FR 64943), dated December 13, 1991). The staff 

participated in an industry-sponsored demonstration program to apply 10 CFR Part 54 to a pilot 

plant and to gain the experience necessary to develop implementation guidance. To establish a 

scope of review for license renewal, 10 CFR Part 54 defined age-related degradation unique to 
1-3

license renewal; however, during the demonstration program, the staff found that adverse aging 

effects on plant systems and components are managed during the period of initial license and 

that the scope of the review did not allow sufficient credit for management programs, particularly 

the implementation of 10 CFR 50.65, “Requirements for Monitoring the Effectiveness of 

Maintenance at Nuclear Power Plants,” which regulates management of plant-aging 

phenomena. As a result of this finding, the staff amended 10 CFR Part 54 in 1995. As 

published on May 8, 1995, in 60 FR 22461, amended 10 CFR Part 54 establishes a regulatory 

process that is simpler, more stable, and more predictable than the previous 10 CFR Part 54. In 

particular, as amended, 10 CFR Part 54 focuses on the management of adverse aging effects 

rather than on the identification of age-related degradation unique to license renewal. The staff 

made these rule changes to ensure that important systems, structures, and components (SSCs) 

will continue to perform their intended functions during the period of extended operation. In 

addition, the amended 10 CFR Part 54 clarifies and simplifies the integrated plant assessment 

process to be consistent with the revised focus on passive, long-lived structures and 

components (SCs).

Concurrent with these initiatives, the staff pursued a separate rulemaking effort (61 FR 28467;

June 5, 1996) and amended 10 CFR Part 51 to focus the scope of the review of environmental 

impacts of license renewal to fulfill NRC responsibilities under the National Environmental 

Policy Act of 1969, as amended (42 U.S.C. 4321 et seq.). In June 2013, the staff revised and 

updated the environmental protection regulations (10 CFR Part 51) and issued a revised GEIS 

(GEIS, Revision 1) to incorporate lessons learned and knowledge gained from previous 

plant-specific environmental reviews. The revisions identify 78 environmental impact issues for 

consideration in license renewal environmental reviews, 59 of which have been determined to 

be generic to all plant sites.

1.2.1 Safety Review

License renewal requirements for power reactors are based on two key principles:

(1) The regulatory process is adequate to ensure that the licensing bases of all currently 

operating plants maintain an acceptable level of safety with the possible exceptions of 

the detrimental aging effects on the functions of certain SSCs, as well as a few other 

safety-related issues, during the period of extended operation.

(2) The plant-specific licensing basis must be maintained during the renewal term in the 

same manner and to the same extent as during the original licensing term.

In implementing these two principles, 10 CFR 54.4, “Scope,” defines the scope of license 

renewal as including those SSCs that (1) are safety related, (2) whose failure could affect 

safety-related functions, or (3) are relied on to demonstrate compliance with NRC regulations for 

fire protection, environmental qualification, pressurized thermal shock, anticipated transient 

without scram, and station blackout.

In accordance with 10 CFR 54.21(a), a license renewal applicant must review all SSCs within 

the scope of 10 CFR Part 54 to identify SCs subject to an aging management review (AMR). 

Those SCs subject to an AMR perform an intended function without moving parts or without 

change in configuration or properties and are not subject to replacement based on a qualified 

life or specified time period. In accordance with 10 CFR 54.21(a), a license renewal applicant 

must demonstrate that the aging effects will be managed so that the intended function(s) of 

those SCs will be maintained consistent with the current licensing basis (CLB) for the period of 
1-4

extended operation. However, active equipment is considered to be adequately monitored and 

maintained by existing programs. In other words, detrimental aging effects that may affect 

active equipment can be readily identified and corrected through routine surveillance, 

performance monitoring, and maintenance. Surveillance and maintenance programs for active 

equipment, as well as other maintenance aspects of plant design and licensing basis, are 

required throughout the period of extended operation.

In accordance with 10 CFR 54.21(d), the LRA is required to include a UFSAR supplement that 

contains a summary description of the applicant’s programs and activities for managing the

effects of aging and an evaluation of time-limited aging analyses (TLAAs) for the period of 

extended operation.

License renewal also requires TLAA identification and updating. During the plant design phase, 

certain assumptions about the length of time the plant can operate are incorporated into design 

calculations for several plant SSCs. In accordance with 10 CFR 54.21(c)(1), the applicant must 

either show that these calculations will remain valid for the period of extended operation, project 

the analyses to the end of the period of extended operation, or demonstrate that the aging 

effects on these SSCs will be adequately managed for the period of extended operation.

In 2005, the NRC revised Regulatory Guide 1.188, “Standard Format and Content for 

Applications to Renew Nuclear Power Plant Operating Licenses.” This regulatory guide

endorses Nuclear Energy Institute (NEI) 95-10, Revision 6, “Industry Guideline for Implementing 

the Requirements of 10 CFR Part 54 – The License Renewal Rule,” issued June 2005. 

NEI 95-10 details an acceptable method of implementing 10 CFR Part 54. The staff also used 

the SRP-LR to review the LRA.

In the LRA, the applicant used the process defined in NUREG-1801, Revision 2, “Generic Aging 

Lessons Learned (GALL) Report,” dated December 2010. The GALL Report summarizes 

staff-approved aging management programs (AMPs) for many SCs subject to an AMR. If an 

applicant commits to implementing these staff-approved AMPs, the time, effort, and resources 

for LRA review can be greatly reduced, improving the efficiency and effectiveness of the license 

renewal review process. The GALL Report summarizes the aging management evaluations, 

programs, and activities credited for managing aging for most of the SCs used throughout the 

industry. The report is also a quick reference for both applicants and staff reviewers to AMPs 

and activities that can manage aging adequately during the period of extended operation.

1.2.2 Environmental Review

Part 51 of 10 CFR contains environmental protection regulations. In December 1996, the staff 

revised the environmental protection regulations to facilitate the environmental review for 

license renewal. The staff prepared the GEIS to document its evaluation of possible 

environmental impacts associated with nuclear power plant license renewals. For certain types 

of environmental impacts, the GEIS contains generic findings that apply to all nuclear power 

plants and are codified in Appendix B, “Environmental Effect of Renewing the Operating License 

of a Nuclear Power Plant,” to Subpart A, “National Environmental Policy Act—Regulations 

Implementing Section 102(2),” of 10 CFR Part 51. In accordance with 10 CFR 51.53(c)(3)(i), a 

license renewal applicant may incorporate these generic findings in its environmental

report (ER). In accordance with 10 CFR 51.53(c)(3)(ii), an ER also must include analyses of 

environmental impacts that must be evaluated on a plant-specific basis (i.e., Category 2 issues).
1-5

In June 2013, the NRC staff issued a final rule revising 10 CFR Part 51 to update the potential 

environmental impacts associated with the renewal of an operating license for a nuclear power 

reactor for an additional 20 years. Revision 1 to the GEIS was issued concurrently with the final 

rule. The revised GEIS specifically supports the revised list of environmental issues identified in 

the final rule. Revision 1 to the GEIS and the 2013 final rule reflect lessons learned and 

knowledge gained during previous license renewal environmental reviews.

In accordance with the National Environmental Policy Act of 1969, as amended, and 

10 CFR Part 51, the staff reviewed the plant-specific environmental impacts of license renewal, 

including whether there was new and significant information not considered in the GEIS. As 

part of its scoping process, the staff held a public meeting on March 10, 2015, at the LaSalle 

County Emergency Management Agency in Ottawa, Illinois, to identify plant-specific 

environmental issues. The draft, plant-specific GEIS Supplement 57 documents the results of 

the environmental review and makes a preliminary recommendation as to the license renewal 

action. The staff held another public meeting on March 22, 2016, at the LaSalle County 

Emergency Operations Center in Ottawa, Illinois, to discuss the draft, plant-specific GEIS 

Supplement 57. After considering comments on the draft, the staff will publish the final, 

plant-specific GEIS Supplement 57 separately from this report.

1.3 Principal Review Matters

Part 54 of 10 CFR describes the requirements for renewal of operating licenses for nuclear 

power plants. The staff’s technical review of the LRA was in accordance with NRC guidance 

and 10 CFR Part 54 requirements. Section 54.29, “Standards for Issuance of a Renewed 

License,” of 10 CFR sets forth the license renewal standards. This SER describes the results of 

the staff’s safety review.

In accordance with 10 CFR 54.19(a), the NRC requires a license renewal applicant to submit 

general information, which the applicant provided in LRA Section 1. The staff reviewed LRA 

Section 1 and finds that the applicant has submitted the required information.

In accordance with 10 CFR 54.19(b), the NRC requires that the LRA include “conforming 

changes to the standard indemnity agreement, 10 CFR 140.92, “Appendix B – Form of 

Indemnity Agreement with Licensees Furnishing Insurance Policies As Proof of Financial 

Protection,” to account for the expiration term of the proposed renewed license.” On this issue, 

the applicant stated in the LRA:

10 CFR Part 54.19(b) requires that “each application must include conforming 

changes to the standard indemnity agreement, 10 CFR 140.92, Appendix B, to 

account for the expiration term of the proposed renewed license.” The current 

indemnity agreement (No. B-84) for LaSalle County Station, Units 1 and 2, states 

in Article VII that the agreement “shall terminate at the time of expiration of that 

license specified in Item 3 of the Attachment to the agreement, which is the last 

to expire; provided that, except as may otherwise be provided in applicable 

regulations or orders of the Commission, the term of this agreement shall not 

terminate until all the radioactive material has been removed from the location 

and transportation of the radioactive material from the location has ended as 

defined in subparagraph 5(b), Article I.” Item 3 of the Attachment to the 

indemnity agreement includes license numbers NPF-11 and NPF-18. Applicant 

requests that any necessary conforming changes be made to Article VII and 

Item 3 of the Attachment, and any other sections of the indemnity agreement as 
1-6

appropriate to ensure that the indemnity agreement continues to apply during 

both the terms of the current licenses and the terms of the renewed licenses. 

Applicant understands that no changes may be necessary for this purpose if the 

current license numbers are retained.

The staff intends to maintain the original license numbers upon issuance of the renewed 

licenses, if approved. Therefore, conforming changes to the indemnity agreement need not be 

made and the 10 CFR 54.19(b) requirements have been met.

In accordance with 10 CFR 54.21, “Contents of Application – Technical Information,” the NRC 

requires that the LRA contain (a) an integrated plant assessment, (b) a description of any CLB 

changes during the staff’s review of the LRA, (c) an evaluation of TLAAs, and (d) a UFSAR 

supplement. LRA Sections 3 and 4 and Appendix B address the license renewal requirements 

of 10 CFR 54.21(a), (b), and (c). LRA Appendix A satisfies the license renewal requirements of 

10 CFR 54.21(d).

In accordance with 10 CFR 54.21(b), the NRC requires that, each year following submission of 

the LRA and at least 3 months before the scheduled completion of the staff’s review, the 

applicant submit an LRA amendment identifying any CLB changes to the facility that affect the 

contents of the LRA, including the UFSAR supplement. By letter dated December 2, 2015, the 

applicant submitted an LRA update that summarizes the CLB changes that have occurred 

during the staff’s review of the LRA. This submission has been reviewed by the staff and 

satisfies 10 CFR 54.21(b) requirements.

In accordance with 10 CFR 54.22, “Contents of Application – Technical Specifications,” the 

NRC requires that the LRA include changes or additions to the technical specifications that are 

necessary to manage aging effects during the period of extended operation. In LRA 

Appendix D, the applicant stated that it had not identified any changes to the technical 

specifications that would be necessary for issuance of the renewed LSCS operating licenses. 

This statement adequately addresses the 10 CFR 54.22 requirement.

The staff evaluated the technical information required by 10 CFR 54.21 and 10 CFR 54.22 in 

accordance with NRC regulations and SRP-LR guidance. SER Sections 2, 3, and 4 document 

the staff’s evaluation of the LRA technical information.

As required by 10 CFR 54.25, “Report of the Advisory Committee on Reactor Safeguards,” the 

ACRS will issue a report documenting its evaluation of the staff’s LRA review and SER. SER 

Section 5 is reserved for the ACRS report when it is issued. SER Section 6 documents the 

findings required by 10 CFR 54.29, “Standards for Issuance of a Renewed License.”

1.4 Interim Staff Guidance

License renewal is a living program. The staff, industry, and other interested stakeholders gain 

experience and develop lessons learned with each renewed license. The lessons learned 

address the staff’s performance goals of maintaining safety, improving effectiveness and 

efficiency, reducing regulatory burden, and increasing public confidence. Interim staff guidance 

(ISG) is documented for use by the staff, industry, and other interested stakeholders until it is 

incorporated into license renewal guidance documents, such as the SRP-LR and GALL Report.

Table 1.4-1 shows the current set of ISGs, as well as the SER sections in which the staff 

addresses them.
1-7

Current Interim Staff Guidance

ISG Issue

(Approved ISG Number) Purpose SER Section

“Aging Management of Stainless 

Steel Structures and Components in 

Treated Borated Water,” Revision 1

(LR-ISG-2011-01)

This LR-ISG clarifies the staff’s 

existing position on aging 

management in treated borated water 

environments.

Not Applicable to BWRs

“Aging Management Program for 

Steam Generators”

(LR-ISG-2011-02)

This LR-ISG evaluates the suitability 

of using Revision 3 of NEI 97-06 for 

implementing the licensee’s steam 

generator AMP.

Not Applicable to BWRs

“Generic Aging Lessons Learned 

(GALL) Report Revision 2 

AMP XI.M41, ‘Buried and 

Underground Piping and Tanks’”

(LR-ISG-2011-03)

This LR-ISG gives additional 

guidance on managing the effects of 

aging on buried and underground 

piping and tanks.

SER Sections 3.0.3.1.12, 3.0.3.2.14, 

and 3.3.2.1.9

“Updated Aging Management Criteria 

for Reactor Vessel Internal 

Components of Pressurized Water 

Reactors”

(LR-ISG-2011-04)

This LR-ISG updates the GALL 

Report, Revision 2, and SRP-LR, 

Revision 2, to ensure consistency 

with MRP-227-A for the aging 

management of age-related 

degradation for components of 

pressurized water reactor vessel 

internals during the term of a 

renewed operating license.

Not Applicable to BWRs

“Ongoing Review of Operating 

Experience”

(LR-ISG-2011-05)

This LR-ISG clarifies the staff’s 

existing position in the SRP-LR that 

acceptable license renewal AMPs 

should be informed and enhanced,

when necessary, based on the 

ongoing review of both plant-specific 

and industry operating experience.

SER Section 3.0.5

“Wall Thinning Due to Erosion 

Mechanisms”

(LR-ISG-2012-01)

This LR-ISG gives additional 

guidance on managing the effects of 

wall thinning due to erosion 

mechanisms.

SER Section 3.0.3.1.7

“Aging Management of Internal 

Surfaces, Fire Water Systems, 

Atmospheric Storage Tanks, and 

Corrosion under Insulation”

(LR-ISG-2012-02)

This LR-ISG gives guidance on 

managing the effects of aging for 

internal surfaces, fire water system, 

atmospheric storage tanks, and 

corrosion under insulation.

SER Sections 3.0.3.1.12, 3.0.3.1.13, 

3.0.3.2.5, 3.0.3.2.6, 3.0.3.2.10, 

3.0.3.2.11, 3.2.2.2.9, and 3.4.2.2.6

“Aging Management of Loss of 

Coating or Lining Integrity for Internal 

Coatings/Linings on In-Scope Piping, 

Piping Components, Heat 

Exchangers, and Tanks”

(LR-ISG-2013-01)

This final LR-ISG gives guidance on 

aging management for coating or 

lining integrity for internal 

coatings/linings on in-scope piping, 

piping components, heat exchangers, 

and tanks.

SER Sections 3.0.3.3.1, 3.2.2.1.1,

3.2.2.3.3, 3.3.2.1.1, 3.3.2.3.7, and 

3.4.2.1.1

“Changes to Buried and Underground 

Piping and Tank Recommendations”

(LR-ISG-2015-01)

This LR-ISG replaces AMP XI.M41, 

“Buried and Underground Piping and 

Tanks,” and the associated FSAR 

Summary Description. The LR-ISG

provides revised guidance on 

managing aging effects associated 

with buried and underground piping 

and tanks.

SER Section 3.0.3.2.14
1-8

1.5 Summary – Closure of Open Items

As a result of its review of the LRA, including additional information submitted through 

June 8, 2016, the staff closed the following open items previously identified in the “Safety 

Evaluation Report with Open Items Related to the License Renewal of LaSalle County Station, 

Units 1 and 2,” dated February 29, 2016 (ADAMS Accession No. ML16053A439). No other 

open items remain to be addressed. An item is considered open if, in the staff’s judgment, it 

does not meet all applicable regulatory requirements at the time of the issuance of this SER. A 

summary of the basis for each closed open item is presented here.

Open Item 3.0.3.1.2-1: BWR Vessel ID Attachment Welds

The LRA describes the BWR Vessel ID Attachment Welds program as an existing program that 

is consistent with the program elements in GALL Report AMP XI.M4, “BWR Vessel ID 

Attachment Welds.” During the AMP audit, the staff reviewed documents relevant to the 

program, including ER-AB-331, Revision 14, and verified that program elements 1 through 6 are 

consistent with the corresponding program elements of GALL Report AMP XI.M4. However, as 

a result of the subsequent NRC Regional Inspector’s IP-71002 License Renewal Inspection at 

LSCS, the staff had an opportunity to review the applicant’s document ER-AB-331 again and 

noted that changes to the examination qualification requirements in Boiling Water Reactor 

Vessel and Internals Project (BWRVIP)-03, “Reactor Pressure Vessel and Internals 

Examination Requirements,” regarding enhanced visual examinations (EVT-1s) may have 

reduced the effective examination coverage to zero percent in some cases. Based on the AMP 

Audit Report dated September 22, 2015, the staff notes that the ER-AB-331 is the main 

implementing document for the applicant’s BWR Vessel ID Attachment Welds and BWR Vessel 

Internals AMPs. By letter dated February 16, 2016, the staff issued RAI B.2.1.4-1, requesting 

that the applicant provide clarification regarding the EVT-1 inspections performed at LSCS.

In its response dated February 25, 2016, the applicant provided a summary of the attachment 

welds examined by the BWR Vessel ID Attachment Welds program and the percent coverage of 

these examinations. In addition, the applicant stated that zero-percent examinations are 

unlikely, and it revised its procedures to enter this condition into the LSCS corrective action 

program if it were to happen. The staff’s evaluation of the response to RAI B.2.1.4-1 and the 

bases for closure of OI 3.0.3.1.2-1 are documented in SER Section 3.0.3.1.2.

Open Item 3.0.3.1.5-1: BWR Stress Corrosion Cracking

Based on information from the license renewal inspections at LSCS, it was unclear to the staff 

what examination coverage percentage the applicant considered as necessary for a weld to be 

credited as inspected in the BWR Stress Corrosion Cracking program. By letter dated 

February 16, 2016, the staff issued RAI B.2.1.7-3b to determine the percentage of examination 

coverage that the applicant considers for crediting a weld inspection in this program and to 

provide the technical bases for crediting examinations when the coverage obtained is less than 

90 percent.

In its response dated February 25, 2016, the applicant stated that the procedure for inservice 

inspections of welds will be revised to clarify the extent of evaluation for weld examinations that

are only credited under this program, when greater than 90 percent coverage is not achieved. 

An engineering technical evaluation will be required with a content comparable to a relief 

request, and such welds may be considered “inspected” if they have been examined to the 

maximum coverage attainable using the PDI (performance demonstration initiative) methods. 
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The staff’s evaluation of the response to RAI B.2.1.7-3b and the bases for closure of 

OI 3.0.3.1.5-1 are documented in SER Section 3.0.3.1.5.

1.6 Summary of Confirmatory Items

As a result of its review of the LRA, including additional information submitted through 

June 8, 2016, the staff determines that no confirmatory items that would require a formal 

response from the applicant exist.

1.7 Summary of Proposed License Conditions

Following the staff’s review of the LRA, including subsequent information and clarifications from 

the applicant, the staff identified two proposed license conditions.

(1) The information in the UFSAR supplement, submitted pursuant to 10 CFR 54.21(d), as 

revised during the license renewal application review process, and licensee commitments 

as listed in Appendix A of the “Safety Evaluation Report Related to the License Renewal 

of LaSalle County Station, Unit 1 and 2, are collectively the “License Renewal UFSAR 

Supplement.” This Supplement is henceforth part of the UFSAR, which will be updated in 

accordance with 10 CFR 50.71(e). As such, the licensee may make changes to the 

programs, activities, and commitments described in this Supplement, provided the 

licensee evaluates such changes pursuant to the criteria set forth in 10 CFR 50.59, 

“Changes, Tests and Experiments,” and otherwise complies with the requirements in that 

section.

(2) The License Renewal UFSAR Supplement, as updated by license condition [1] above, 

describes certain programs to be implemented and activities to be completed prior to the 

period of extended operation (PEO).

a. The applicant shall implement those new programs and enhancements to existing 

programs no later than 6 months prior to the PEO.

b. The applicant shall complete those activities by the 6-month date prior to PEO or the 

end of the last refueling outage prior to the PEO, whichever occurs later.

c. The applicant shall notify the NRC in writing within 30 days after having 

accomplished item (a) above and include the status of those activities that have been 

or remain to be completed in item (b) above.

The purpose of requiring the completion of implementation, inspection, and testing either before 

the end of the last refueling outage or before the 6-month timeframe is to ensure that the 

implementation of programs and completion of specific activities can be confirmed by the staff’s 

oversight process before each plant enters its respective period of extended operation.

LRA Appendix A, Section A.5, “License Renewal Commitment List,” contains commitments for 

license renewal and an associated schedule for when the applicant plans to implement or 

complete the commitments. Through the commitments in LRA Appendix A, Section A.5, the 

applicant will implement new programs, will implement enhancements to existing programs, and 

will also complete inspection or testing activities.

Because the applicant’s implementation schedule for some commitments, as provided originally 

in LRA Appendix A, Section A.5, could conflict with the implementation schedule intended by 

the generic second license condition described above, by letter dated December 14, 2015, the 
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staff issued RAI A.5-1, which requested that the applicant provide the expected date for 

implementing each commitment before the period of extended operation and state whether the 

implementation would be documented as a license condition or as a supplement to the UFSAR. 

By letter dated January 7, 2016, the applicant responded to RAI A.5-1 and provided a revision 

to LRA Appendix A, Sections A.1.0.1 and A.5, in which it specified the time period when each 

commitment would be implemented and where it would be documented. Specifically, the 

applicant stated:

• Implementation of new aging management programs and enhancements to existing 

aging management programs will be completed no later than six months prior to the 

respective period of extended operation (PEO) for each LaSalle County Station unit; and

• Inspection or testing activities identified for completion prior to the PEO will be 

completed either:

− no later than six months prior to the respective PEO for each LaSalle County 

Station unit, or

− prior to the end of the last refueling outage before the respective PEO for each 

unit, whichever occurs later.

The applicant also stated that, upon receipt of the renewed license, Appendix A of the LRA will 

be part of the LSCS UFSAR, which will be updated in accordance with 10 CFR 50.71(e).

The staff finds the applicant’s response to RAI A.5-1 acceptable because (1) the staff reviewed 

the applicant’s response and revision of LRA Appendix A and confirmed that the applicant 

identified those commitments that implement new programs and enhancements to existing 

programs and stated that these commitments will be implemented no later than 6 months before 

the period of extended operation, which is consistent with the second proposed license 

condition, (2) the staff also confirmed that, as part of its response, the applicant identified the 

commitments that complete inspection or testing activities and stated, consistent with the 

second proposed license condition, that these commitments will be implemented 6 months 

before the period of extended operation or by the end of the last refueling outage before the 

period of extended operation, whichever occurs later, and (3) all commitments in LRA 

Appendix A will be incorporated into the LSCS UFSAR. The staff’s concerns described in 

RAI A.5-1 are resolved.
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STRUCTURES AND COMPONENTS SUBJECT TO AGING 

MANAGEMENT REVIEW

2.1 Scoping and Screening Methodology

2.1.1 Introduction

Title 10 of the Code of Federal Regulations (CFR), Section 54.21, “Contents of Application –

Technical Information,” requires the applicant to identify the systems, structures and 

components (SSCs) within the scope of license renewal in accordance with 10 CFR 54.4(a). In 

addition, the license renewal application (LRA) must contain an integrated plant assessment 

(IPA). The IPA identifies and lists those structures and components (SCs), which are contained 

in the SSCs that are identified to be within the scope of license renewal, that are subject to an 

aging management review (AMR).

2.1.2 Summary of Technical Information in the Application

LRA Section 2.0, “Scoping and Screening Methodology for Identifying Structures and 

Components Subject to Aging Management Review, and Implementation Results,” provides the 

technical information required by 10 CFR 54.21(a). LRA Section 2.0 states, in part, that the 

applicant had considered the following in developing the scoping and screening methodology 

described in LRA Section 2.0:

• 10 CFR Part 54, “Requirements for Renewal of Operating Licenses for Nuclear Power 

Plants” (the Rule)

• Nuclear Energy Institute (NEI) 95-10, Revision 6, “Industry Guideline for Implementing 

the Requirements of 10 CFR Part 54 – The License Renewal Rule,” dated June 2005 

(NEI 95-10)

LRA Section 2.1, “Scoping and Screening Methodology,” describes the methodology used by 

Exelon Generation Company, LLC (Exelon or the applicant), to identify the SSCs at LaSalle 

County Station, Units 1 and 2 (LSCS), within the scope of license renewal (scoping) and the 

SCs subject to an AMR (screening).

2.1.3 Scoping and Screening Program Review

The staff evaluated the applicant’s scoping and screening methodology in accordance with the 

guidance in Section 2.1, “Scoping and Screening Methodology,” of NUREG-1800, Revision 2, 

“Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants”

(SRP-LR), dated December 2010. The following regulations provide the basis for the 

acceptance criteria used by the staff to assess the adequacy of the scoping and screening 

methodology used by the applicant to develop the LRA:

• 10 CFR 54.4(a), as it relates to the identification of SSCs within the scope of the Rule

• 10 CFR 54.4(b), as it relates to the identification of the intended functions of SSCs within 

the scope of the Rule
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• 10 CFR 54.21(a), as it relates to the methods used by the applicant to identify SCs 

subject to an AMR

The staff reviewed the information in LRA Section 2.1 to confirm that the applicant described a 

process for identifying SSCs that are within the scope of license renewal in accordance with the 

requirements of 10 CFR 54.4(a) and SCs that are subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)

In addition, the staff conducted a scoping and screening methodology audit at the LSCS facility 

located in LaSalle County, Illinois, during the week of March 9–13, 2015. The audit focused on 

ensuring that the applicant had developed and implemented adequate guidance to conduct the 

scoping and screening of SSCs in accordance with the methodology described in the LRA and 

the requirements of the Rule. The staff reviewed the project-level guidelines, technical basis 

documents, and implementing procedures that describe the applicant’s scoping and screening 

methodology. The staff conducted detailed discussions with the applicant on the 

implementation and control of the license renewal methodology, the quality practices used by 

the applicant during the LRA development, and the training of the applicant’s staff that 

participated in the LRA development.

On a sampling basis, the staff performed a review of scoping and screening results reports and 

supporting current licensing basis (CLB) information for portions of the essential cooling water

(ECW) system and corresponding structures. In addition, the staff performed walkdowns of 

selected portions of those systems and structures as a part of the sampling review of the 

implementation of the applicant’s 10 CFR 54.4(a)(2) scoping methodology.

2.1.3.1 Implementing Procedures and Documentation Sources Used for Scoping and 

Screening

Summary of Technical Information in the Application

The applicant had developed implementing procedures used to identify SSCs within the scope 

of license renewal and SCs subject to an AMR to implement the processes described in LRA 

Sections 2.0 and 2.1. Additionally, the applicant’s implementing procedures provide guidance

on the review and consideration of CLB documentation sources, relative to the requirements of 

10 CFR 54.4, “Scope,” and 10 CFR 54.21, “Contents of Application – Technical Information.”

LRA Section 2.1.2, “Information Sources Used for Scoping and Screening,” lists the following 

information sources for the license renewal scoping and screening process:

• updated final safety analysis report (UFSAR)

• fire protection report (FPR)

• environmental qualification (EQ) master list

• maintenance rule database

• engineering drawings

• controlled plant component database

Staff Evaluation

Scoping and Screening Implementing Procedures. The staff reviewed the applicant’s scoping 

and screening methodology implementing procedures, including license renewal guidelines, 

documents, and reports, as documented in the staff’s audit report, to ensure that the guidance is 
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consistent with the requirements of the Rule, the SRP-LR and Regulatory Guide 1.188,

Revision 1, “Standard Format and Content for Applications to Renew Nuclear Plant Operating 

Licenses,” dated September 2005, which endorses the use of NEI 95-10. The staff determined 

that the overall process used to implement the 10 CFR Part 54 requirements described in the 

implementing procedures, including license renewal guidelines, documents, and reports, is 

consistent with the Rule, the SRP-LR, and the endorsed industry guidance.

The applicant’s implementing procedures contain guidance for determining plant SSCs within 

the scope of the Rule and SCs contained in systems within the scope of license renewal that 

are subject to an AMR. During the review of the implementing procedures, the staff focused on 

the consistency of the detailed procedural guidance with information contained in the LRA, 

including the implementation of U.S. Nuclear Regulatory Commission (NRC) staff positions 

documented in the SRP-LR. After reviewing the LRA and supporting documentation, the staff 

determined that the scoping and screening methodology instructions are consistent with the 

methodology described in LRA Section 2.1 and that the methodology is sufficiently detailed in 

the implementing procedures to provide concise guidance on the scoping and screening 

process to be followed during the LRA activities.

Sources of Current Licensing Basis Information. The regulation at 10 CFR 54.21(a)(3) requires, 

for each SC determined to be subject to an AMR, demonstration that the effects of aging will be 

adequately managed so that the intended functions will be maintained consistent with the CLB 

for the period of extended operation. The regulation at 10 CFR 54.3(a) defines the CLB, in part, 

as the set of NRC requirements applicable to a specific plant and a licensee’s written 

commitments for ensuring compliance with, and operation within, applicable NRC requirements 

and the plant-specific design bases that are docketed and in effect. The CLB includes 

applicable NRC regulations, orders, license conditions, exemptions, technical specifications, 

and design basis information (documented in the most recent UFSAR). The CLB also includes 

licensee commitments remaining in effect that were made in docketed licensing 

correspondence, such as licensee responses to NRC bulletins, generic letters, and enforcement 

actions, and licensee commitments documented in NRC safety evaluations or licensee event 

reports. The staff considered the scope and depth of the applicant's CLB review to verify that 

the methodology is sufficiently comprehensive to identify SSCs within the scope of license 

renewal and SCs subject to an AMR.

During the scoping and screening methodology audit, the staff confirmed that the applicant’s 

detailed license renewal program guidelines specified the use of the CLB source information in 

developing scoping evaluations. The staff reviewed pertinent information sources used by the 

applicant, including the UFSAR, CLB documents, FPR, EQ master list, maintenance rule 

database, engineering drawings, and controlled plant component database.

During the audit, the staff discussed the applicant’s administrative controls for the controlled 

plant component database and the other information sources used to verify system information. 

These controls are described and implemented by plant procedures. Based on a review of the 

administrative controls and a sample of the system classification information contained in the 

applicable documentation, the NRC staff determined that the applicant has established 

adequate measures to control the integrity and reliability of system identification and safety 

classification data; therefore, the staff determined that the information sources used by the 

applicant during the scoping and screening process provided a controlled source of system and 

component data to support scoping and screening evaluations.
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In addition, the staff reviewed the implementing procedures and results reports used to support 

identification of SSCs that the applicant relied on to demonstrate compliance with the 

requirements of 10 CFR 54.4(a). The applicant’s license renewal program guidelines provided 

a listing of documents used to support scoping evaluations. The staff determined that the 

design documentation sources, which the applicant’s implementing procedures must use,

provided sufficient information to ensure that the applicant identified SSCs to be included within 

the scope of license renewal consistent with the plant’s CLB.

Conclusion

Based on its review of LRA Sections 2.0 and 2.1, the scoping and screening implementing 

procedures, and the results from the scoping and screening audit, the staff concludes that the 

applicant’s use of implementing procedures and consideration of document sources, including 

CLB information, is consistent with the Rule, the SRP-LR, and NEI 95-10 guidance and, 

therefore, is acceptable.

2.1.3.2 Quality Controls Applied to LRA Development

Staff Evaluation

The staff reviewed the quality controls used by the applicant to ensure that the scoping and 

screening methodology used to develop the LRA were adequate for the activity. The applicant 

used quality control processes during the LRA development to do the following:

• Perform scoping and screening activities using approved documents and procedures.

• Use databases to guide and support scoping and screening and to generate license 

renewal documents.

• Employ standard processes for scoping, screening, and LRA preparation.

• Use processes and procedures that incorporate preparation, review, comment, and 

owner acceptance.

• Incorporate industry lessons learned and requests for additional information (RAIs) from 

other LRA reviews.

• Perform external assessments, including a peer review and benchmarking to recent LRA

reviews.

• Perform internal management assessments.

The staff performed a review of implementing procedures and guides, examined the applicant’s 

documentation of activities in reports, reviewed the applicant’s activities that were performed to 

assess the quality of the LRA, and held discussions with the applicant’s license renewal 

management and staff. The staff determined that the applicant’s activities provide assurance 

that the LRA was developed consistent with the applicant’s license renewal program 

requirements.

Conclusion

On the basis of its review of pertinent LRA development guidance, discussion with the 

applicant’s license renewal staff, and review of the applicant’s documentation of the activities 

performed to assess the quality of the LRA, the staff concludes that the applicant’s quality 
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assurance activities are adequate to ensure that LRA development activities were performed in 

accordance with the applicant’s license renewal program requirements.

2.1.3.3 Training

Staff Evaluation

The staff reviewed the training process used by the applicant for license renewal project 

personnel to confirm that it was appropriate for the activity. As outlined in the implementing 

procedures, the applicant had required training for personnel participating in the development of 

the LRA and used trained and qualified personnel to prepare the scoping and screening 

implementing procedures and to perform scoping and screening activities.

License renewal project personnel had been trained using license renewal project procedures 

and other relevant license renewal information, as appropriate to their functions. Training topics 

had included 10 CFR Part 54, “Requirements for Renewal of Operating Licenses for Nuclear 

Power Plants,” relevant NRC and industry guidance documents, lessons learned from other 

LRA reviews, and applicable implementing procedures.

The staff discussed training activities with the applicant’s management and license renewal 

project personnel and performed a sampling review of applicable documentation. The staff 

determined that the applicant had developed and implemented adequate controls for the 

training of personnel performing LRA activities.

Conclusion

On the basis of discussions with the applicant’s license renewal personnel responsible for the 

scoping and screening process and its review of selected documentation in support of the 

process, the staff concludes that the applicant developed and implemented adequate 

procedures to train personnel to implement the scoping and screening methodology described 

in the applicant’s implementing procedures and the LRA.

2.1.3.4 Scoping and Screening Program Review Conclusion

On the basis of a review of information provided in LRA Sections 2.0 and 2.1, a review of the 

applicant’s scoping and screening implementing procedures, discussions with the applicant’s 

license renewal personnel, review of the quality controls applied to the LRA development, 

training of personnel participating in the LRA development, and the results from the scoping and 

screening methodology audit, the staff concludes that the applicant’s scoping and screening 

program is consistent with the SRP-LR and the requirements of 10 CFR Part 54 and, therefore, 

is acceptable.

2.1.4 Plant Systems, Structures, and Components Scoping Methodology

LRA Section 2.1, “Scoping and Screening Methodology,” describes the applicant’s methodology 

used to identify SSCs within the scope of license renewal pursuant to the requirements of the 

10 CFR 54.4(a) criteria. The LRA states that the scoping process identified the SSCs that are 

safety related and perform and support an intended function for responding to a design basis 

event (DBE), that are nonsafety related whose failure could prevent accomplishment of a 

safety-related function, or that support a specific requirement for one of the regulated events 
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applicable to license renewal. In addition, the LRA states that the scoping methodology used 

was consistent with 10 CFR Part 54 and with the industry guidance contained in NEI 95-10.

2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1)

Summary of Technical Information in the Application

The applicant addressed the methods used to identify SSCs that are included within the scope 

of license renewal, in accordance with the requirements of 10 CFR 54.4(a)(1) in LRA 

Section 2.1.5.1, “Safety-Related—10 CFR 54.4(a)(1),” which states:

At LSCS, the safety-related plant components are identified in controlled 

engineering drawings and summarized in the PassPort equipment database. 

The safety-related classifications in the LSCS PassPort equipment database 

were populated using a controlled procedure, with classification criteria 

consistent with the above 10 CFR 54.4(a)(1) criteria.

Staff Evaluation

In accordance with 10 CFR 54.4(a)(1), the applicant must consider all safety-related SSCs 

relied on to remain functional during and following a DBE to ensure the following functions: 

(1) the integrity of the reactor coolant pressure boundary (RCPB), (2) the ability to shut down 

the reactor and maintain it in a safe shutdown condition, or (3) the capability to prevent or 

mitigate the consequences of accidents that could result in potential offsite exposures 

comparable to those referred to in 10 CFR 50.34(a)(1); 10 CFR 50.67(b)(2); or 

10 CFR Part 100.11, “Determination of Exclusion Area, Low Population Zone, and Population 

Center Distance,” as applicable.

With regard to identification of DBEs, SRP-LR Section 2.1.3, “Review Procedures,” states:

The set of design basis events as defined in the rule is not limited to Chapter 15 

(or equivalent) of the UFSAR. Examples of design basis events that may not be 

described in this chapter include external events, such as floods, storms, 

earthquakes, tornadoes, or hurricanes, and internal events, such as a high 

energy line break. Information regarding design basis events as defined in 

10 CFR 50.49(b)(1) may be found in any chapter of the facility UFSAR, the 

Commission’s regulations, NRC orders, exemptions, or license conditions within 

the CLB. These sources should also be reviewed to identify systems, structures, 

and components that are relied on to remain functional during and following 

design basis events (as defined in 10 CFR 50.49(b)(1)) to ensure the functions 

described in 10 CFR 54.4(a)(1).

During the audit, the applicant stated that it evaluated the types of events listed in NEI 95-10 

(anticipated operational occurrences, design basis accidents (DBAs), external events, and 

natural phenomena) that were applicable to LSCS. The staff reviewed the applicant’s basis 

documents that describe design basis conditions in the CLB and address events defined by 

10 CFR 50.49(b)(1) and 10 CFR 54.4(a)(1). The UFSAR and basis documents discuss events,

such as internal and external flooding, tornados, and missiles. The staff concludes that the 

applicant’s evaluation of DBEs was consistent with the SRP-LR.
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The staff determined that the applicant performed scoping of SSCs for the 10 CFR 54.4(a)(1) 

criterion in accordance with the license renewal implementing procedures, which provide 

guidance for the preparation, review, verification, and approval of the scoping evaluations to 

ensure the adequacy of the results of the scoping process. The staff reviewed the implementing 

procedures governing the applicant’s evaluation of safety-related SSCs and sampled the 

applicant’s reports of the scoping results to ensure that the applicant applied the methodology in 

accordance with the implementing procedures. In addition, the staff discussed the methodology 

and results with the applicant’s personnel who were responsible for these evaluations.

The staff reviewed the applicant’s evaluation of the Rule and CLB definitions pertaining to 

10 CFR 54.4(a)(1) and determined that the applicant’s CLB definition of safety related met the 

definition of safety related specified in the Rule.

The staff reviewed a sample of the license renewal scoping results for the ECW system and 

corresponding structures to provide additional assurance that the applicant adequately 

implemented its scoping methodology with respect to 10 CFR 54.4(a)(1).

The staff verified that the applicant developed the scoping results for the sampled systems and 

structures consistently with the methodology, identified the SSCs credited for performing 

intended functions, and adequately described the basis for the results and the intended 

functions. The staff also confirmed that the applicant had identified and used pertinent 

engineering and licensing information to identify the SSCs that are required to be within the 

scope of license renewal in accordance with the 10 CFR 54.4(a)(1) criteria.

Conclusion

On the basis of its review of the LRA and the applicant’s implementing procedures and reports, 

review of a system on a sampling basis, and discussions with the applicant, the staff concludes 

that the applicant’s methodology for identifying safety-related SSCs relied on to remain 

functional during and following DBEs and for including the SSCs within the scope of license 

renewal is consistent with the SRP-LR and 10 CFR 54.4(a)(1) and, therefore, is acceptable.

2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2)

Summary of Technical Information in the Application

The applicant addressed the methods used to identify SSCs included within the scope of license 

renewal, in accordance with the requirements of 10 CFR 54.4(a)(2).

LRA Section 2.1.5.2, “Nonsafety-Related Affecting Safety-Related – 10 CFR 54.4(a)(2),” states, 

in part:

Functional Support for Safety-Related SSC[s] 10 CFR 54.4(a)(1) Functions

The LSCS UFSAR and other CLB documents were reviewed to identify

nonsafety-related systems or structures required to support satisfactory

accomplishment of a safety-related function. Nonsafety-related systems or

structures credited in CLB documents to support a safety-related function have 

been included within the scope of license renewal.
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Connected to and Provide Structural Support for Safety-Related SSCs

For nonsafety-related SSCs directly connected to safety-related SSCs the

nonsafety-related piping and supports, up to and including the first seismic or

equivalent anchor (such as a series of supports that have been evaluated as a

part of a plant-specific piping design analysis to ensure that forces and moments 

are restrained in three (3) orthogonal directions) beyond the safety/nonsafety 

interface, are within the scope of license renewal per 10 CFR 54.4(a)(2). The 

“first seismic or equivalent anchor” is defined such that the failure in the 

nonsafety-related pipe run beyond the first seismic or equivalent anchor will not 

render the safety-related portion of the piping unable to perform its intended 

function under CLB design conditions.

Potential for Spatial Interactions with Safety-Related SSCs

Nonsafety-related systems that are not connected to safety-related piping or

components, or are outside the structural support boundary for the attached

safety-related piping system, and have a spatial relationship such that their

failure could adversely impact the performance of a safety-related SSC intended 

function, must be evaluated for license renewal scope in accordance with 

10 CFR 54.4(a)(2) requirements.

The preventive option assumes potential spatial interaction in structures or

portions of structures that contain active or passive SSCs that have 

safety-related functions. The structures of concern for potential spatial 

interaction were identified based on a review of the CLB to determine which 

structures contained active or passive safety-related SSCs. Plant walkdowns 

were performed as required to confirm that all structures containing 

safety-related SSCs were identified. With the exception of the Turbine Building 

and Offgas Building, it was assumed that all nonsafety-related SSCs within these

structures were located in proximity to safety-related SSCs where potential

spatial interaction could occur.

The Turbine Building and Offgas Building have few areas containing 

safety-related SSCs. Mitigative features were used to prevent spatial interaction

between these safety-related SSCs and nonsafety-related SSCs in other areas. 

No credit was taken for separation by distance alone without a mitigative feature 

capable of preventing the spatial interaction. The mitigative features were 

included in the scope of license renewal.

Staff Evaluation

Regulatory Guide 1.188, Revision 1, endorses the use of NEI 95-10, Revision 6, which 

discusses the implementation of the staff’s position on 10 CFR 54.4(a)(2) scoping criteria, to 

include nonsafety-related SSCs that may have the potential to prevent satisfactory 

accomplishments of safety-related intended functions. This includes nonsafety-related SSCs 

connected to safety-related SSCs, nonsafety-related SSCs in proximity to safety-related SSCs,

and mitigative and preventative options related to nonsafety-related and safety-related SSCs 

interactions. LRA Section 1.5, “Application Structure,” states that the applicant’s methodology is 

consistent with the guidance contained in Revision 6 to NEI 95-10 Appendix F.
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In addition, the staff’s position (as discussed in SRP-LR Section 2.1.3.1.2, “Nonsafety-Related,” 

scoping review procedures) is that applicant should not consider hypothetical failures but rather 

should base their evaluation on the plant’s CLB, engineering judgment and analyses, and 

relevant operating experience. NEI 95-10 further describes operating experience as all 

documented plant-specific and industry-wide experience that can be used to determine the 

plausibility of a failure. Documentation would include NRC generic communications and event 

reports; plant-specific condition reports; industry reports, such as safety operational event 

reports; and engineering evaluations. The staff reviewed LRA Section 2.1.5.2 in which the 

applicant described the scoping methodology for nonsafety-related SSCs pursuant to 

10 CFR 54.4(a)(2). In addition, the staff reviewed the applicant’s implementing procedure and 

results report, which document the guidance and corresponding results of the applicant’s 

scoping review pursuant to 10 CFR 54.4(a)(2).

Nonsafety-Related SSCs Required to Perform a Function that Supports a Safety-Related SSC. 

The staff reviewed LRA Section 2.1.5.2 and the applicant’s 10 CFR 54.4(a)(2) implementing 

procedure that describe the method used to identify nonsafety-related SSCs that are required to 

perform a function that supports a safety-related SSC intended function within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(2). The staff confirmed that the applicant 

had reviewed the UFSAR, plant drawings, the controlled plant component database, and other 

CLB documents to identify the nonsafety-related systems and structures that function to support 

a safety-related system whose failure could prevent the performance of a safety-related 

intended function. The staff determined that the applicant had identified the nonsafety-related 

SSCs that perform a safety function or that support a safety system that would require the 

nonsafety-related SSC to be included within the scope of license renewal in accordance with 

10 CFR 54.4(a)(2).

The staff determined that the applicant’s methodology for identifying nonsafety-related systems 

that perform functions that support safety-related intended functions, for inclusion within the 

scope of license renewal, was in accordance with the guidance of the SRP-LR and the 

requirements of 10 CFR 54.4(a)(2).

Nonsafety-Related SSCs Directly Connected to Safety-Related SSCs. The staff reviewed LRA 

Section 2.1.5.2 and the applicant’s 10 CFR 54.4(a)(2) implementing procedure that describe the 

method used to identify nonsafety-related SSCs, which are directly connected to safety-related 

SSCs, within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The applicant 

had reviewed the safety- to nonsafety-related interfaces for each mechanical system to identify 

the nonsafety-related components located between the safety- to nonsafety-related interface 

and license renewal structural boundary.

The staff determined that the applicant had used a combination of the following to identify the 

portion of nonsafety-related piping systems to include within the scope of license renewal:

• seismic anchors

• equivalent anchors

• bounding conditions described in Revision 6 to NEI 95-10 Appendix F (base-mounted 

component, flexible connection, inclusion to the free end of nonsafety-related piping, 

inclusion of the entire piping run or a branch line off of a header where the moment of 

inertia of the header is greater than 7 times the moment of inertia of the branch)
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The staff determined that the applicant’s methodology for identifying and including 

nonsafety-related SSCs directly connected to safety-related SSCs, within the scope of license 

renewal, was in accordance with the guidance of the SRP-LR and the requirements of 

10 CFR 54.4(a)(2).

Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety-Related SSCs. 

The staff reviewed LRA Section 2.1.5.2 and the applicant’s 10 CFR 54.4(a)(2) implementing 

procedure that describe the method used to identify nonsafety-related SSCs, with the potential 

for spatial interaction with safety-related SSCs, within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(2). The staff determined that the applicant had, with the 

exception of the Turbine Building and Offgas Building discussed below, used a spaces 

approach to identify the portions of nonsafety-related systems with the potential for spatial 

interaction with safety-related SSCs. The spaces approach focused on the interaction between 

nonsafety-related and safety-related SSCs that are located in the same space, which was 

described in the LRA as a structure or a portion of a structure that contains active or passive 

safety-related SSCs.

The staff determined that for the Turbine Building and Offgas Building, each building has 

several locations containing safety-related SSCs. The applicant had performed a review of the 

safety-related SSCs within these buildings to determine whether the failure of nonsafety-related 

SSCs could impact the ability of safety-related SSCs to perform their intended functions. 

The applicant had identified certain safety-related SSCs located within a portion of a structure 

whose ability to perform its intended function could be impacted by the failure of 

nonsafety-related SSCs and included the nonsafety-related SSCs within the scope of license 

renewal. Additional safety-related SSCs were determined to be protected from the failure of 

nonsafety-related SSCs by mitigating features, such as pipe conduits or separation by a surface 

providing spray and drip shielding. The mitigating features were included within the scope of 

license renewal. The applicant determined that, for the remaining safety-related components, 

either the failure of the safety-related SSC would cause it to attain a fail-safe state or the 

component was identified as safety related in the plant component database but did not have a 

safety-related intended function; therefore, these components did not require the inclusion of 

nonsafety-related SSCs within the scope of license renewal.

The staff determined that the applicant’s methodology for identifying and including 

nonsafety-related SSCs, with the potential for spatial interaction with safety-related SSCs, within 

the scope of license renewal was in accordance with the guidance of the SRP-LR and the 

requirements of 10 CFR 54.4(a)(2).

Conclusion

On the basis of its review of the LRA and the applicant’s implementing procedures and reports, 

review of a system on a sampling basis, and discussions with the applicant, the staff concludes 

that the applicant’s methodology for identifying and including nonsafety-related SSCs whose 

failure could prevent satisfactory accomplishment of the intended functions of safety-related 

SSCs, within the scope of license renewal, is in accordance with the requirements of 

10 CFR 54.4(a)(2) and, therefore, is acceptable.
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2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3)

Summary of Technical Information in the Application

The applicant addressed the methods used to identify SSCs included within the scope of license 

renewal, in accordance with the requirements of 10 CFR 54.4(a)(3).

LRA Section 2.1.5.3, “Regulated Events—10 CFR 54.4(a)(3),” states:

In accordance with 10 CFR 54.4(a)(3), the systems, structures, and components 

within the scope of license renewal include: All systems, structures and 

components relied on in safety analyses or plant evaluations to perform a 

function that demonstrates compliance with the Commission’s regulations for fire 

protection (10 CFR 50.48), environmental qualification (10 CFR 50.49), 

pressurized thermal shock (10 CFR 50.61), anticipated transients without scram 

(10 CFR 50.62), and station blackout (10 CFR 50.63).

LRA Section 2.1.5.3 also states:

The regulation for pressurized thermal shock (10 CFR 50.61) is applicable to

pressurized water reactors only, and therefore not applicable to LSCS which is a 

boiling water reactor. For each of the four [applicable] regulations, a technical 

basis document was prepared to provide input into the scoping process. Each of 

the regulated event basis documents (described in Section 2.1.3.4 [of the LRA]) 

identify the systems and structures that are relied upon to demonstrate 

compliance with the applicable regulation. The basis documents also identify the 

source documentation used to determine the scope of components within the 

system that are credited to demonstrate compliance with each of the applicable 

regulated events. Guidance provided by the technical basis documents was 

incorporated into the system and structure scoping evaluations, to determine the 

SSCs credited for each of the regulated events. SSCs credited in the regulated 

events have been classified as satisfying criteria of 10 CFR 54.4(a)(3) and have 

been included within the scope of license renewal.

Staff Evaluation

The staff reviewed LRA Section 2.1.5.3, which describes the method used to identify, and to 

include within the scope of license renewal, those SSCs relied on in safety analyses or plant 

evaluations to perform a function that demonstrates compliance with the Commission’s 

regulations for fire protection (10 CFR 50.48, “Fire Protection”); EQ (10 CFR 50.49, 

“Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power 

Plants”); pressurized thermal shock (10 CFR 50.61, “Fracture Toughness Requirements for 

Protection Against Pressurized Thermal Shock Events”); anticipated transients without scram 

(ATWS) (10 CFR 50.62, “Requirements for Reduction of Risk from Anticipated Transients

Without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants”); and station 

blackout (SBO) (10 CFR 50.63, “Loss of All Alternating Current Power”). As part of this review 

during the scoping and screening methodology audit, the staff had discussions with the 

applicant and reviewed implementing procedures, technical basis documents, license renewal 

drawings, and scoping results reports. The staff determined that the applicant had evaluated

CLB information to identify SSCs that perform functions addressed in 10 CFR 54.4(a)(3) and 

had included these SSCs within the scope of license renewal as documented in the scoping 
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reports. In addition, the staff determined that the scoping report results referenced the 

information sources used for determining the SSCs credited for compliance with the events.

Fire Protection. The staff reviewed the applicant’s implementing procedure and technical basis 

document that describe the method used to identify SSCs within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(3) (10 CFR 50.48, “Fire Protection”). The implementing 

procedure describes a process that considered CLB information, including the UFSAR and the 

fire protection technical basis document. The staff reviewed applicable portions of the LRA, 

CLB information, and license renewal drawings to verify that the appropriate SSCs were 

included within the scope of license renewal. In addition, the staff reviewed a selected sample 

of scoping reports for the systems and structures identified in the technical basis document. 

Based on its review of the CLB documents and the sample report review, the staff determined 

that the applicant’s methodology was adequate for identifying and including SSCs credited in 

performing fire protection functions within the scope of license renewal in accordance with the 

requirements of 10 CFR 54.4(a)(3).

Environmental Qualification. The staff reviewed the applicant’s implementing procedure and 

technical basis document that describe the method used to identify SSCs within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(3) (10 CFR 50.49, EQ). The implementing 

procedure describes a process that considered CLB information, including the UFSAR and the 

EQ technical basis document. The staff reviewed applicable portions of the LRA, CLB 

information, EQ program documentation, and license renewal drawings to verify that the 

appropriate SSCs were included within the scope of license renewal. In addition, the staff 

reviewed a selected sample of scoping reports for the systems and structures identified in the 

technical basis document. Based on its review of the CLB documents and the sample report 

review, the staff determined that the applicant’s methodology was adequate for identifying and 

including SSCs credited in performing EQ functions within the scope of license renewal in 

accordance with the requirements of 10 CFR 54.4(a)(3).

Anticipated Transient without Scram. The staff reviewed the applicant’s implementing 

procedure and technical basis document that describe the method used to identify SSCs within 

the scope of license renewal in accordance with 10 CFR 54.4(a)(3) (10 CFR 50.62, ATWS). 

The implementing procedure describes a process that considered CLB information, including 

the UFSAR and the ATWS technical basis document. The staff reviewed portions of the 

applicable portions of the LRA, CLB information, and license renewal drawings to verify that the 

appropriate SSCs were included within the scope of license renewal. In addition, the staff 

reviewed a selected sample of scoping reports for the systems and structures identified in the 

technical basis document. Based on its review of the CLB documents and the sample report

review, the staff determined that the applicant’s methodology was adequate for identifying and 

including SSCs credited in performing ATWS functions within the scope of license renewal in 

accordance with the requirements of 10 CFR 54.4(a)(3).

Station Blackout. The staff reviewed the applicant’s implementing procedure and technical 

basis document that describe the method used to identify SSCs within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(3) (10 CFR 50.63, “Loss of All Alternating Current 

Power”). The implementing procedure describes a process that considered CLB information, 

including the UFSAR and the SBO technical basis document. The staff reviewed portions of the 

applicable portions of the LRA, CLB information, and license renewal drawings to verify that the 

appropriate SSCs were included within the scope of license renewal. In addition, the staff 

reviewed a selected sample of scoping reports for the systems and structures identified in the 

technical basis document. Based on its review of the CLB documents and the sample report 
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review, the staff determined that the applicant’s methodology was adequate for identifying and 

including SSCs credited in performing SBO functions within the scope of license renewal in 

accordance with the requirements of 10 CFR 54.4(a)(3).

Conclusion

On the basis of its review of the LRA and the applicant’s implementing procedures and reports, 

reviews of a system on a sampling basis, and discussions with the applicant, the staff concludes 

that the applicant’s methodology for identifying and including SSCs, which are relied on to 

remain functional during regulated events, is consistent with the SRP-LR and 10 CFR 54.4(a)(3)

and, therefore, is acceptable.

2.1.4.4 Plant Level Scoping of Systems and Structures

Summary of Technical Information in the Application

System and Structure Level Scoping. The applicant described the methods used to identify 

SSCs included within the scope of license renewal in accordance with the requirements of 

10 CFR 54.4(a) in LRA Section 2.0, which states:

This section describes the process for identifying structures and components

subject to aging management review in the LaSalle County Station (LSCS)

license renewal integrated plant assessment. For the systems, structures, and

components (SSCs) within the scope of license renewal, 10 CFR 54.21(a)(1)

requires the license renewal applicant to identify and list those structures and

components subject to Aging Management Review (AMR). 10 CFR 54.21(a)(2)

further requires that the methods used to implement the requirements of

10 CFR 54.21(a)(1) be described and justified.

Staff Evaluation

The staff reviewed the applicant’s methodology for identifying SSCs within the scope of license 

renewal to verify that it met the requirements of 10 CFR 54.4, “Scope.” The applicant had 

developed implementing procedures that describe the processes used to identify the systems 

and structures that are subject to 10 CFR 54.4 review, to determine whether the system or 

structure performed its intended functions consistent with the criteria of 10 CFR 54.4(a), and to 

document the activities in scoping results reports. The process defined the plant in terms of 

systems and structures and was completed for all systems and structures on site to ensure that

the entire plant was assessed.

The staff determined that the applicant had identified the SSCs within the scope of license 

renewal and documented the results of the scoping process in reports in accordance with the 

implementing procedures. The reports included a description of the structure or system, a 

listing of functions performed by the system or structure, identification of intended functions, the 

10 CFR 54.4(a) scoping criteria met by the system or structure, references, and the basis for the 

classification of the system or structure intended functions. During the audit, the staff reviewed 

a sampling of the implementing documents and reports and determined that the applicant’s 

scoping results contained an appropriate level of detail to document the scoping process.
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Conclusion

Based on its review of the LRA, implementing procedures, and a sampling of system scoping 

results reviewed during the audit, the staff concludes that the applicant’s methodology for 

identifying systems and structures within the scope of license renewal and their intended 

functions is consistent with the requirements of 10 CFR 54.4 and, therefore, is acceptable.

2.1.4.5 Mechanical Scoping

Summary of Technical Information in the Application

The applicant addressed the methods used to identify mechanical SSCs within the scope of 

license renewal in accordance with the requirements of 10 CFR 54.4(a).

LRA Section 2.1.5, “Scoping Procedure,” states, in part:

The scoping process was initially performed at the system and structure level, in 

accordance with the scoping criteria identified in 10 CFR 54.4(a). System and 

structure functions and intended functions were identified from a review of the 

source CLB documents. In scope boundaries were established and documented 

in the scoping evaluations, based on the identified intended functions. The in 

scope boundaries form the basis for identification of the in scope components, 

which is the first step in the screening process described in Section 2.1.6 [of the 

LRA].

LRA Section 2.1.5.5, “Scoping Boundary Determination,” states, in part:

Systems and structures that are included within the scope of license renewal are 

then further evaluated to determine the population of in scope structures and 

components. This part of the scoping process is also a transition from the

scoping process to the screening process. The process for evaluating

mechanical systems is different from the process for structures, primarily

because the plant design document formats are different. Mechanical systems

are depicted primarily on the system piping and instrumentation diagrams (P&ID) 

that show the system components and their functional relationships.

LRA Section 2.1.5.5 further states, in part:

For mechanical systems, the mechanical components that support the system 

intended functions are included within the scope of license renewal and are 

depicted on the applicable system piping and instrumentation diagram.

Staff Evaluation

The staff reviewed LRA Sections 2.1.5 and 2.1.5.5, implementing procedures, reports and the 

CLB source information associated with mechanical scoping. The staff determined that the CLB 

source information and the implementing procedure guidance used by the applicant were

acceptable to identify mechanical SSCs within the scope of license renewal. The staff 

conducted detailed discussions with the applicant's license renewal project personnel and 

reviewed documentation pertinent to the scoping process during the scoping and screening 

methodology audit. The staff assessed whether the applicant had appropriately applied the 
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scoping methodology outlined in the LRA and implementing procedures and whether the 

scoping results were consistent with CLB requirements. The staff determined that the 

applicant’s process was consistent with the description provided in LRA Sections 2.1.5 

and 2.1.5.5 and with the guidance in SRP-LR Section 2.1 and that it was adequately 

implemented.

On a sampling basis, the staff reviewed the applicant's scoping reports for the ECW System and 

the process used to determine whether the system and components met the scoping criteria of 

10 CFR 54.4, “Scope.” The staff reviewed the implementing procedures, verified that the 

applicant had used pertinent engineering and licensing information, and discussed the 

methodology and results with the applicant. As part of the review process, the staff evaluated 

the system’s documented intended functions and the process used to identify system 

component types. The staff verified that the applicant had identified and highlighted license 

renewal drawings to identify the license renewal boundaries in accordance with the 

implementing procedure guidance. Additionally, the staff determined that the applicant had 

independently verified the results in accordance with the implementing procedures. The staff 

confirmed that the applicant’s license renewal personnel who verified the results had performed 

independent reviews of the scoping reports and the applicable license renewal drawings.

The staff confirmed that the systems and components identified by the applicant were evaluated 

against the criteria of 10 CFR 54.4(a)(1), (a)(2), and (a)(3). The staff verified that the applicant 

had used pertinent engineering and licensing information to determine that SSCs were included 

within the scope of license renewal in accordance with the 10 CFR 54.4(a).

Conclusion

On the basis of its review of information contained in the LRA and implementing procedures and

the sampling review of scoping results, the staff concludes that the applicant’s methodology for 

identifying mechanical SSCs within the scope of license renewal is in accordance with the 

requirements of 10 CFR 54.4 and, therefore, is acceptable.

2.1.4.6 Structural Scoping

Summary of Technical Information in the Application

The applicant addressed the methods used to identify structural SSCs within the scope of 

license renewal in accordance with the requirements of 10 CFR 54.4(a).

LRA Section 2.1.5, “Scoping Procedure,” states, in part:

The scoping process was initially performed at the system and structure level, in 

accordance with the scoping criteria identified in 10 CFR 54.4(a). System and 

structure functions and intended functions were identified from a review of the 

source CLB documents. In scope boundaries were established and documented 

in the scoping evaluations, based on the identified intended functions. The in 

scope boundaries form the basis for identification of the in scope components, 

which is the first step in the screening process described in Section 2.1.6 [of the 

LRA].
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LRA Section 2.1.5.5, “Scoping Boundary Determination,” states, in part:

Systems and structures that are included within the scope of license renewal are 

then further evaluated to determine the population of in scope structures and 

components. This part of the scoping process is also a transition from the 

scoping process to the screening process.

LRA Section 2.1.5.5 further states, in part:

For structures, the structural components that are required to support the

intended function(s) of the structure, as described in the CLB, are included within 

the scope of license renewal. The structural components are identified from a 

review of applicable plant design drawings of the structure.

Staff Evaluation

The staff reviewed LRA Sections 2.1.5 and 2.1.5.5, implementing procedures, reports, and the 

CLB source information associated with structural scoping. The staff determined that the CLB 

source information and the implementing procedure guidance used by the applicant were

acceptable to identify structural SSCs within the scope of license renewal. The staff conducted 

detailed discussions with the applicant’s license renewal project personnel and reviewed 

documentation pertinent to the scoping process during the scoping and screening methodology 

audit. The staff assessed whether the applicant had appropriately applied the scoping 

methodology outlined in the LRA and implementing procedures and whether the scoping results 

were consistent with CLB requirements. The staff determined that the applicant’s process was 

consistent with the description provided in LRA Sections 2.1.5 and 2.1.5.5 and with the 

guidance in SRP-LR Section 2.1, and that it was adequately implemented.

On a sampling basis, the staff reviewed the applicant's scoping reports for the ECW System and 

corresponding structures and the process used to identify SCs that met the scoping criteria of 

10 CFR 54.4, “Scope.” The staff reviewed the implementing procedures, verified that the 

applicant had used pertinent engineering and licensing information, and discussed the 

methodology and results with the applicant. As part of the review process, the staff evaluated 

the structure’s documented intended functions and the process used to identify structural 

component types. Additionally, the staff determined that the applicant had verified the results in 

accordance with the implementing procedures. The staff confirmed that the applicant’s license 

renewal personnel who verified the results had performed independent reviews of the scoping 

reports and the applicable license renewal drawings. The staff confirmed that the SCs identified 

by the applicant were evaluated against the criteria of 10 CFR 54.4(a)(1), (a)(2), and (a)(3). The 

staff verified that the applicant had used pertinent engineering and licensing information to 

determine that systems and components were included within the scope of license renewal in 

accordance with the 10 CFR 54.4(a)

Conclusion

On the basis of its review of information contained in the LRA and implementing procedures and 

the sampling review of scoping results, the staff concludes that the applicant’s methodology for 

identifying structural SSCs within the scope of license renewal is in accordance with the 

requirements of 10 CFR 54.4 and, therefore, is acceptable.
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2.1.4.7 Electrical Scoping

Summary of Technical Information in the Application

LRA Section 2.1.5, “Scoping Procedure,” states, in part:

The scoping process was initially performed at the system and structure level, in 

accordance with the scoping criteria identified in 10 CFR 54.4(a). System and 

structure functions and intended functions were identified from a review of the 

source CLB documents. In scope boundaries were established and documented 

in the scoping evaluations, based on the identified intended functions. The in 

scope boundaries form the basis for identification of the in scope components, 

which is the first step in the screening process described in Section 2.1.6 [of the 

LRA].

LRA Section 2.1.5.5, “Scoping Boundary Determination,” states, in part:

Systems and structures that are included within the scope of license renewal are 

then further evaluated to determine the population of in scope structures and 

components. This part of the scoping process is also a transition from the 

scoping process to the screening process.

LRA Section 2.1.5.5 further states:

Electrical and I&C systems, and electrical components within mechanical 

systems, did not require further system evaluations to determine which 

components were required to perform or support the identified intended 

functions. A bounding scoping approach is used for electrical equipment. All 

electrical components within in scope systems were included within the scope of 

license renewal. In scope electrical components were placed into commodity 

groups and were evaluated as commodities during the screening process as 

described in Section 2.1.6 [of the LRA].

Staff Evaluation

The staff reviewed LRA Sections 2.1.5 and 2.1.5.5, implementing procedures, reports, and the 

CLB source information associated with electrical scoping. The staff determined that the CLB 

source information and implementing procedure guidance used by the applicant was acceptable 

to identify electrical SSCs within the scope of license renewal. The staff conducted detailed 

discussions with the applicant's license renewal project personnel and reviewed documentation 

pertinent to the scoping process during the scoping and screening methodology audit. The staff 

assessed whether the applicant had appropriately applied the scoping methodology outlined in 

the LRA and implementing procedures and whether the scoping results were consistent with 

CLB requirements. The staff determined that the applicant’s process was consistent with the 

description provided in LRA Sections 2.1.5 and 2.1.5.5 and with the guidance in SRP-LR 

Section 2.1 and that it was adequately implemented.

The staff noted that, after the scoping of electrical and instrumentation and control (I&C)

components was performed, the in-scope electrical components were categorized into electrical 

commodity groups. Commodity groups include electrical and I&C components with common 

characteristics. Component level intended functions of the component types were identified. As 
2-18

part of this review, the staff discussed the methodology with the applicant, reviewed the 

implementing procedures developed to support the review, and reviewed the scoping results for 

a sample of SSCs that were identified within the scope of license renewal. The staff determined 

that the applicant’s scoping included appropriate electrical and I&C components, as well as 

electrical and I&C components contained in mechanical or structural systems within the scope 

of license renewal on a commodity basis.

Conclusion

On the basis of its review of information contained in the LRA and implementing procedures and

the sampling review of scoping results, the staff concludes that the applicant’s methodology for 

identifying electrical SSCs within the scope of license renewal is in accordance with the 

requirements of 10 CFR 54.4, “Scope,” and, therefore, is acceptable.

2.1.4.8 Scoping Methodology Conclusion

On the basis of its review of information contained in the LRA and implementing procedures and 

a sampling review of scoping results, the staff concludes that the applicant’s scoping 

methodology was consistent with the guidance contained in the SRP-LR and identified those 

SSCs (1) that are safety related, (2) whose failure could affect safety-related intended functions, 

and (3) that are necessary to demonstrate compliance with the NRC’s regulations for fire 

protection, EQ, ATWS, and SBO. The staff concluded that the applicant’s methodology is 

consistent with the requirements of 10 CFR 54.4(a) and, therefore, is acceptable.

2.1.5 Screening Methodology

2.1.5.1 General Screening Methodology

Summary of Technical Information in the Application

The applicant addressed the methods used to identify SCs included within the scope of license 

renewal that are subject to an AMR in accordance with the requirements of 10 CFR 54.21, 

“Contents of Application – Technical Information,” in LRA Section 2.1.6, “Screening Procedure,”

and LRA Section 2.1.6.1, “Identification of Structures and Components Subject to AMR.” LRA 

Section 2.1.6.1 states, in part:

Structures and components that perform an intended function without moving

parts or without a change in configuration or properties are defined as passive for 

license renewal. Passive structures and components that are not subject to 

replacement based on a qualified life or specified time period are defined as

long-lived for license renewal. The screening procedure is the process used to

identify the passive, long-lived structures and components within the scope of

license renewal that are subject to aging management review.

NUREG–1800, “Standard Review Plan for Review of License Renewal

Applications for Nuclear Power Plants,” and NEI 95-10, Appendix B, were used

as the basis for the identification of passive structures and components. Most

passive structures and components are long-lived. In the few cases where a

passive component is determined not to be long-lived, such determination is

documented in the screening evaluation and, if applicable, on the associated

license renewal boundary drawing.
2-19

The LSCS structures and components subject to aging management review have 

been identified in accordance with the requirements of 10 CFR 54.21(a)(1) 

described above.

Staff Evaluation

In accordance with 10 CFR 54.21, each LRA must contain an IPA that identifies SCs that are 

within the scope of license renewal and that are subject to an AMR. The IPA must identify 

components that perform an intended function without moving parts or a change in configuration 

or properties (passive), as well as components that are not subject to periodic replacement 

based on a qualified life or specified time period (long lived). In addition, the IPA must include a 

description and justification of the methodology used to identify passive and long-lived SCs and 

a demonstration that the effects of aging on those SCs will be adequately managed so that the 

intended function(s) will be maintained under all design conditions imposed by the plant-specific 

CLB for the period of extended operation.

The staff reviewed the methodology used by the applicant to identify the mechanical, structural, 

and electrical SCs within the scope of license renewal that are subject to an AMR. The 

applicant implemented a process for determining which SCs were subject to an AMR in 

accordance with the requirements of 10 CFR 54.21(a)(1). The staff determined that the 

screening process evaluated the component types and commodity groups, included within the 

scope of license renewal, to determine which ones were long lived and passive and, therefore,

subject to an AMR. The staff reviewed, on a sampling basis, the screening results reports for 

ECW and associated structures. The applicant provided the staff with a detailed discussion of 

the processes used for each discipline and provided administrative documentation that 

described the screening methodology. Specific methodology for mechanical, structural, and

electrical SCs is discussed in the safety evaluation report (SER) Section 2.1.5.2.

Conclusion

On the basis of a review of the LRA, the implementing procedures, and a sampling of screening 

results, the staff concludes that the applicant’s screening methodology was consistent with the 

guidance contained in the SRP-LR and was capable of identifying passive, long-lived 

components within the scope of license renewal that are subject to an AMR. The staff 

concludes that the applicant’s process for determining the SCs that are subject to an AMR is 

consistent with the requirements of 10 CFR 54.21 and, therefore, is acceptable.

2.1.5.2 Mechanical Component Screening

Summary of Technical Information in the Application

The applicant addressed the methods used to identify mechanical SCs included within the 

scope of license renewal that are subject to an AMR in accordance with the requirements of 

10 CFR 54.21, “Contents of Application – Technical Information.” LRA Section 2.1.6.1 states, in 

part:

These system boundary drawings were reviewed to identify the passive, 

long-lived components, and the identified components were then entered into the 

license renewal database. Component listings from the Passport equipment 

database were also reviewed to confirm that all system components were 

considered. In cases where the system piping and instrumentation diagram did 
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not provide sufficient detail, such as for some large vendor supplied components 

(e.g., compressors, emergency diesel generators, the associated component

drawings or vendor manuals were also reviewed. Plant walkdowns were 

performed when required for confirmation.

Staff Evaluation

The staff reviewed the applicant’s methodology used for mechanical component screening as 

described in LRA Section 2.1.6.1, implementing procedures, basis documents, and the 

mechanical scoping and screening reports. The staff determined that the applicant used the 

screening process described in these documents along with the information contained in 

NEI 95-10 Appendix B and the SRP-LR to identify the mechanical SCs subject to an AMR.

The staff determined that the applicant had identified SCs that met the passive criteria in 

accordance with the guidance contained in NEI 95-10. In addition, the staff determined that the 

applicant had evaluated the identified passive commodities to determine that they were not 

subject to replacement based on a qualified life or specified time period (long lived) and that the 

remaining passive, long-lived components were subject to an AMR.

The staff performed a sample review to determine whether the screening methodology outlined 

in the LRA and implementing procedures was adequately implemented. The staff reviewed the 

ECW System screening report and basis documents, had discussions with the applicant, and 

verified proper implementation of the screening process.

Conclusion

On the basis of its review of information contained in the LRA, implementing procedures, and 

the sampled mechanical screening results, the staff concludes that the applicant’s methodology 

for identification of mechanical SCs within the scope of license renewal and subject to an AMR 

is in accordance with the requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable.

2.1.5.3 Structural Component Screening

Summary of Technical Information in the Application

The applicant addressed the methods used to identify structural SCs included within the scope 

of license renewal that are subject to AMR in accordance with the requirements of 

10 CFR 54.21, “Contents of Application – Technical Information.” LRA Section 2.1.6.1 states, in 

part:

The structure screening process also began with the results from the scoping

process. For in scope structures, the completed scoping packages include

written descriptions of the structure. If only selected portions of the structure are 

in scope, the in scope portions are described in the scoping evaluation. The 

associated structure drawings were reviewed to identify the passive, long-lived

structures and components, and the identified structures and components were 

then entered into the license renewal database. Plant walkdowns were

performed when required for confirmation.
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Staff Evaluation

The staff reviewed the applicant’s methodology used for structural component screening as 

described in LRA Section 2.1.6.1, implementing procedures, basis documents, and the 

structural scoping and screening reports. The staff determined that the applicant used the 

screening process described in these documents along with the information contained in 

NEI 95-10 Appendix B and the SRP-LR to identify the structural SCs subject to an AMR.

The staff determined that the applicant had identified structural SCs that met the passive criteria 

in accordance with NEI 95-10. In addition, the staff determined that the applicant evaluated the 

identified passive commodities to determine that they were not subject to replacement based on 

a qualified life or specified time period (long lived) and that the remaining passive, long-lived 

components were determined to be subject to an AMR.

The staff performed a sample review to determine whether the screening methodology outlined 

in the LRA and implementing procedures was adequately implemented. The staff reviewed the

ECW and associated structures screening report and basis documents, had discussions with

the applicant, and verified proper implementation of the screening process.

Conclusion

On the basis of its review of information contained in the LRA, implementing procedures, and 

the sampled structural screening results, the staff concludes that the applicant’s methodology to 

identify structural SCs within the scope of license renewal and subject to an AMR is in 

accordance with the requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable.

2.1.5.4 Electrical Component Screening

Summary of Technical Information in the Application

The applicant addressed the methods used to identify electrical SCs included within the scope 

of license renewal that are subject to AMR in accordance with the requirements of 

10 CFR 54.21, “Contents of Application – Technical Information.” LRA Section 2.1.6.1 states, in 

part:

Screening of electrical and I&C components within the in scope electrical, I&C,

and mechanical systems used a bounding approach as described in NEI 95-10. 

Electrical and I&C components for the in scope systems were assigned to

commodity groups. The commodities subject to an aging management review

are identified by applying the criteria of 10 CFR 54.21(a)(1). This method

provides the most efficient means for determining the electrical commodities

subject to an aging management review since many electrical and I&C 

components and commodities are active.

Staff Evaluation

The staff reviewed the applicant’s methodology used for electrical component screening as 

described in LRA Section 2.1.6.1, implementing procedures, basis documents, and the electrical 

scoping and screening reports. The staff confirmed that the applicant had used the screening 

process described in these documents along with the information contained in NEI 95-10 

Appendix B and the SRP-LR to identify the electrical SSCs subject to an AMR.
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The staff determined that the applicant had identified electrical commodity groups that met the 

passive criteria in accordance with NEI 95-10. In addition, the staff determined that the 

applicant evaluated the identified passive commodities to determine which ones were not 

subject to replacement based on a qualified life or specified time period (long lived) and that the 

remaining passive, long-lived components were determined to be subject to an AMR.

The staff performed a sample review to determine whether the screening methodology outlined 

in the LRA and implementing procedures was adequately implemented. During the scoping and 

screening methodology audit, the staff reviewed the electrical screening report and discussed 

the report with the applicant and verified proper implementation of the screening process.

The staff performed a sample review to determine whether the screening methodology outlined 

in the LRA and implementing procedures was adequately implemented. During the scoping and 

screening methodology audit, the staff reviewed electrical screening reports and basis 

documents, had discussions with the applicant, and verified proper implementation of the 

screening process.

Conclusion

On the basis of its review of information contained in the LRA, implementing procedures, and 

the sampled electrical screening results, the staff concludes that the applicant’s methodology to 

identify electrical SCs within the scope of license renewal and subject to an AMR is in 

accordance with the requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable.

2.1.5.5 Screening Methodology Conclusion

On the basis of its review of the LRA, the screening implementing procedures, discussions with 

the applicant’s staff, and a sample review of screening results, the staff concludes that the 

applicant’s screening methodology was consistent with the guidance contained in the SRP-LR 

and identified those passive, long-lived components within the scope of license renewal that are 

subject to an AMR. The staff concludes that the applicant’s methodology is consistent with the 

requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable.

2.1.6 Summary of Evaluation Findings

On the basis of its review of the information presented in LRA Section 2.1, the supporting 

information in the scoping and screening implementing procedures and reports, the information 

presented during the scoping and screening methodology audit, discussions with the applicant, 

and sample system reviews, the staff confirms that the applicant’s scoping and screening 

methodology is consistent with the requirements of 10 CFR 54.4, “Scope,” and 

10 CFR 54.21(a)(1). The staff also concludes that the applicant’s description and justification of 

its scoping and screening methodology are adequate to meet the requirements of 

10 CFR 54.21(a)(1). From this review, the staff concludes that the applicant’s methodology for 

identifying SSCs within the scope of license renewal and SCs subject to an AMR is acceptable.

2.2 Plant Level Scoping Results

2.2.1 Introduction

In LRA Section 2.1, the applicant described the methodology for identifying SSCs within the 

scope of license renewal. In LRA Section 2.2, the applicant used the scoping methodology to 
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determine which SSCs must be included within the scope of license renewal. The staff 

reviewed the plant level scoping results to determine whether the applicant has properly 

identified all systems and structures relied on to mitigate DBEs, as required by 

10 CFR 54.4(a)(1); systems and structures, the failure of which could prevent satisfactory 

accomplishment of any safety-related functions, as required by 10 CFR 54.4(a)(2); and systems 

and structures relied on in safety analyses or plant evaluations to perform functions required by 

regulations referenced in 10 CFR 54.4(a)(3).

2.2.2 Summary of Technical Information in the Application

In LRA Table 2.2-1, the applicant listed the LSCS systems, structures, and commodity groups 

that were evaluated to determine whether they were within the scope of license renewal. Based 

on the DBEs considered in the plant’s CLB, other CLB information relating to nonsafety-related 

systems and structures, and certain regulated events, the applicant identified plant level 

systems and structures within the scope of license renewal as defined by 10 CFR 54.4, “Scope.”

2.2.3 Staff Evaluation

In LRA Section 2.1, the applicant described its methodology for identifying systems and 

structures within the scope of license renewal and subject to an AMR. The staff reviewed the 

scoping and screening methodology and provides its evaluation in SER Section 2.1. To verify 

that the applicant properly implemented its methodology, the staff’s review focused on the 

implementation results shown in LRA Table 2.2-1 to confirm that there were no omissions of 

plant level systems and structures within the scope of license renewal.

The staff determined whether the applicant properly identified the systems and structures within 

the scope of license renewal in accordance with 10 CFR 54.4, “Scope.” The staff reviewed 

selected systems and structures that the applicant did not identify as within the scope of license 

renewal to verify whether the systems and structures have any intended functions requiring their 

inclusion within the scope of license renewal. The staff’s review of the applicant’s 

implementation was conducted in accordance with the guidance in SRP-LR Section 2.2, “Plant

Level Scoping Results.”

The staff sampled the contents of the UFSAR based on the systems and structures listed in 

LRA Table 2.2-1 to determine whether there were any systems or structures that may have 

intended functions within the scope of license renewal, as defined by 10 CFR 54.4, but were 

omitted from the scope of license renewal. The staff did not identify any omissions.

2.2.4 Conclusion

The staff reviewed LRA Section 2.2 and UFSAR supporting information to determine whether 

the applicant failed to identify any systems and structures within the scope of license renewal. 

The staff finds no such omissions. Based on its review, the staff concludes that there is 

reasonable assurance that the applicant has adequately identified the systems and structures 

within the scope of license renewal in accordance with 10 CFR 54.4.

2.3 Scoping and Screening Results: Mechanical Systems

This section documents the staff’s review of the applicant’s scoping and screening results for 

mechanical systems. Specifically, this section discusses systems within Mechanical Systems in 

the following LRA sections:
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• LRA Section 2.3.1, “Reactor Vessel, Internals, and Reactor Coolant System”

• LRA Section 2.3.2, “Engineered Safety Features Systems”

• LRA Section 2.3.3, “Auxiliary Systems”

• LRA Section 2.3.4, “Steam and Power Conversion System”

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the 

applicant properly implemented its methodology, the staff’s review focused on the 

implementation results. This focus allowed the staff to confirm that there were no omissions of 

mechanical system components that meet the scoping criteria and are subject to an AMR.

The staff’s evaluation of the information in the LRA was the same for all mechanical systems. 

The objective was to determine whether the applicant has identified, in accordance with 

10 CFR 54.4, “Scope,” components and supporting structures for mechanical systems that 

appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the 

applicant’s screening results to verify that all passive, long-lived components were subject to an 

AMR in accordance with 10 CFR 54.21(a)(1).

In its scoping evaluation, the staff reviewed the applicable LRA sections and drawings, focusing 

on components that have not been identified as within the scope of license renewal. The staff 

reviewed relevant licensing basis documents, including the UFSAR, for each mechanical 

system to determine whether the applicant has omitted from the scope of license renewal 

components with intended functions delineated under 10 CFR 54.4(a). The staff also reviewed 

the licensing basis documents to determine whether the LRA specified all intended functions 

delineated under 10 CFR 54.4(a). The staff requested additional information to resolve any 

omissions or discrepancies identified.

After its review of the scoping results, the staff evaluated the applicant’s screening results. 

For those SCs with intended functions, the staff sought to determine whether (1) the functions 

are performed with moving parts or a change in configuration or properties or (2) the SCs are 

subject to replacement after a qualified life or specified time period, as described in 

10 CFR 54.21(a)(1). For those meeting neither of these criteria, the staff sought to confirm that 

these SCs were subject to an AMR, as required by 10 CFR 54.21(a)(1). The staff requested 

additional information to resolve any omissions or discrepancies identified.

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System

LRA Section 2.3.1 identifies the Reactor Vessel, Internals, and Reactor Coolant System SCs 

subject to an AMR for license renewal. The applicant described the supporting SCs of the 

Reactor Vessel, Internals, and Reactor Coolant System in the following LRA sections:

• LRA Section 2.3.1.1, “Reactor Coolant Pressure Boundary System”

• LRA Section 2.3.1.2, “Reactor Vessel”

• LRA Section 2.3.1.3, “Reactor Vessel Internals”

The staff’s findings on review of LRA Sections 2.3.1.1 – 2.3.1.3 are provided in SER 

Sections 2.3.1.1 – 2.3.1.3, respectively.
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2.3.1.1 Reactor Coolant Pressure Boundary System

Summary of Technical Information in the Application

The Reactor Coolant Pressure Boundary (RCPB) System consists of those systems and 

components that are designed to provide the source of forced circulation of reactor coolant 

through the reactor core to remove the heat generated by fission. In addition, the RCPB 

provides a flowpath to the reactor vessel for feedwater, high pressure core spray (HPCS), low 

pressure core spray (LPCS), residual heat removal (RHR), reactor core isolation cooling 

(RCIC), reactor water cleanup (RWCU), and main steam system. The above systems in the 

RCPB consist of pressure-containing/retaining components, such as the American Society of 

Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI Class 1 and 

Class 2 piping and instrumentation. More detailed information of these pressure boundary and 

associated systems is provided in UFSAR Chapter 5 and Appendix G.

The RCPB license renewal scoping boundary begins at the piping attached to the RPV nozzle 

safe end to piping welds. The RPV nozzles, safe ends, and welds are included with the license 

renewal Reactor Vessel System. The RCPB boundary includes the piping connected to the 

10 recirculation inlet nozzles, 2 recirculation outlet nozzles, 4 MS nozzles, 6 feedwater nozzles, 

3 low pressure coolant injection (LPCI) nozzles, 10 instrumentation nozzles, 2 jet pump 

instrument nozzles, 1 HPCS nozzle, 1 LPCS nozzle, 1 standby liquid control (SLC) nozzle, 

1 bottom head drain nozzle, 1 reactor head vent nozzle, 1 reactor head spray nozzle, and the 

reactor vessel head seal leak detection nozzle. The RCPB includes the main reactor 

recirculation flowpath, which begins at the pump suction piping attached to the reactor vessel 

nozzles, continues through the suction piping, suction valves, recirculation pump casings, 

discharge valves, and discharge piping to return to the RPV nozzles.

LRA Table 2.3.1-1, “Reactor Coolant Pressure Boundary System,” identifies the component 

types within the scope of license renewal and subject to AMR.

The intended functions of the RCPB within the scope of license renewal include the following:

• Provide reactor coolant pressure boundary. The RCPB System forms a barrier to 

minimize the release of reactor coolant and radioactive material to the Reactor 

Buildings. The RCPB System, in conjunction with the Reactor Protection System, 

provides overpressure protection for the RCPB (10 CFR 54.4(a)(1)).

• Provide primary containment boundary. The RCPB System includes containment 

isolation valves (10 CFR 54.4(a)(1)).

• Sense process conditions and generate signals for reactor trip or engineered safety 

features actuations. The RCPB System includes instrumentation and process controls 

that provide input signals to the Primary Containment Isolation System, Reactor 

Protection System, and Emergency Core Cooling System (ECCS) (10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The RCPB System includes nonsafety-related fluid-filled lines 

within the Reactor Building and Primary Containment, which have the potential for 

spatial interaction with safety-related SSCs (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48), EQ 

(10 CFR 50.49), ATWS (10 CFR 50.62), and SBO (10 CFR 50.63) (10 CFR 54.4(a)(3)).
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Additional details on RCPB intended functions can be found in UFSAR references, UFSAR

Section 5, and UFSAR Appendix G.

Staff Evaluation

The staff reviewed the system functions described in LRA Section 2.3.1.1, license renewal 

boundary drawings, and UFSAR Sections 5.0 and 7.7.3. The staff used the evaluation 

methodology as described in guidance in SRP-LR Section 2.3 and SER Section 2.3.

The staff evaluated the system functions described in the LRA and UFSAR to verify that the 

applicant has not omitted from the scope of license renewal any components with intended 

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the 

applicant has identified as being within the scope of license renewal to verify that it has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

Conclusion

Based in its evaluation, the staff concludes that the applicant appropriately identified the RCPB 

components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also 

concludes that the applicant adequately identified the RCPB components subject to an AMR, as 

required by 10 CFR 54.21(a)(1).

The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify any 

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the 

staff’s review determined whether the applicant failed to identify any components subject to an 

AMR. On the basis of its review, the staff concludes that there is reasonable assurance that the 

applicant has adequately identified the RCPB within the scope of license renewal, as required 

by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.1.2 Reactor Vessel

Summary of Technical Information in the Application

LRA Section 2.3.1.2 states that the Reactor Vessel is a normally operating system and is 

designed to contain pressure and heat generated by the nuclear core and to transfer this heat to 

the reactor coolant. The Reactor Vessel consists of the cylindrical vessel shell, lower vessel 

head, vessel support skirt, closure head, nozzles and safe ends, and closure studs and nuts.

The Reactor Vessel interfaces with several other license renewal systems and components, 

including the Control Rod Drive (CRD) System, Neutron Monitoring System, Primary 

Containment, RCPB System, Reactor Vessel Internals, and Component Supports Commodity 

Group.

The purpose of the Reactor Vessel is to maintain the reactor vessel pressure boundary, provide 

structural support for the reactor vessel internals and core and, along with the Reactor Vessel 

Internals, provide a floodable volume. The Reactor Vessel provides a boundary to separate 

fission products from the environment.

The components within the Reactor Vessel license renewal scoping boundary are those that 

comprise the reactor vessel, including nozzles (with integral safe ends and thermal sleeves), 
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closure studs and nuts, and the vessel support skirt. The vessel top head includes one head 

vent nozzle, one head spray/RCIC nozzle, one spare nozzle, and four lifting lugs. The 

cylindrical portion of the vessel includes 1 flange seal leak detection line nozzle, 4 steam outlet 

nozzles, 6 feedwater inlet nozzles, 1 HPCS nozzle, 1 LPCS nozzle, 1 control rod drive hydraulic 

system return nozzle, 10 water level instrumentation nozzles, 3 RHR/LPCI nozzles, 

10 recirculation inlet nozzles, 2 recirculation outlet nozzles, and 2 jet pump instrument nozzles. 

The bottom head includes 1 core differential pressure/SLC nozzle, 1 drain nozzle, 185 control 

rode drive penetrations, and 55 incore flux monitor penetrations.

The system is required for plant startup, normal plant operation, and normal shutdown.

More details regarding the Reactor Vessel are provided in LRA Section 2.3.1.2 and UFSAR

Section 5.3.

The intended functions of the Reactor Vessel within the scope of license renewal include the 

following:

• Provide reactor coolant pressure boundary. The Reactor Vessel forms a barrier against 

the release of reactor coolant and radioactive material to the Reactor Building

(10 CFR 54.4(a)(1)).

• Maintain reactor core assembly geometry. The Reactor Vessel provides support to the 

Reactor Vessel Internals. The Reactor Vessel, along with the Reactor Vessel Internals, 

maintains a floodable volume within the reactor (10 CFR 54.4(a)(1)).

• Provide structural support or restraint to SSCs in the scope of license renewal. The 

reactor pressure vessel support skirt and stabilizer brackets provide structural support 

for the reactor vessel. The refueling bellows bracket provides support for the refueling 

bellows (10 CFR 54.4(a)(1)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48), ATWS

(10 CFR 50.62), and SBO (10 CFR 50.63) (10 CFR 54.4(a)(3)).

LRA Table 2.3.1-2, “Reactor Vessel, Components Subject to Aging Management Review,” lists 

the component types that require AMR and their intended functions.

Staff Evaluation

The staff reviewed the system functions described in LRA Section 2.3.1.2, license renewal 

boundary drawings, and UFSAR Section 5.3. The staff used the evaluation methodology 

described in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and UFSAR to verify that the 

applicant has not omitted from the scope of license renewal any components with intended 

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the 

applicant has identified as being within the scope of license renewal to verify that it has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).
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Conclusion

Based on its review of LRA Section 2.3.1.2 and the UFSAR, the staff concludes that the 

applicant appropriately identified the Reactor Vessel components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately 

identified the Reactor Vessel components subject to AMR, as required by 10 CFR 54.21(a)(1).

2.3.1.3 Reactor Vessel Internals

Summary of Technical Information in the Application

The Reactor Vessel Internals is a normally operating system within the Reactor Vessel that is 

designed to control the generation of heat in the reactor core, to transfer this heat to the reactor 

coolant, and to supply dry steam to the main steam system. The Reactor Vessel Internals 

include the core that contains fuel assemblies that generate the heat; control rods and CRD 

assemblies that control reactivity in the core; and neutron flux detector assemblies that monitor 

core reactivity, the core shroud, and associated supports and hardware core spray piping, 

incore instrumentation, and the steam dryer assembly.

The purpose of the Reactor Vessel Internals is to maintain reactor core assembly geometry, to 

achieve and maintain the reactor core subcritical for any mode of normal operation or event, to 

control reactivity in the nuclear reactor core, and to maintain core thermal and hydraulic limits.

More detailed information regarding the Reactor Vessel Internals information and its boundary 

are provided in UFSAR Sections 3.9.5 and 4.1.2.

The intended functions of the Reactor Vessel Internals within the scope of license renewal 

include the following:

• Maintain reactor core assembly geometry. The reactor internal components, in 

conjunction with the reactor pressure vessel, are designed to provide physical support to 

maintain fuel configuration and clearances to ensure core reactivity control and core 

cooling capability during normal and accident conditions (10 CFR 54.4(a)(1)).

• Introduce negative reactivity to achieve and maintain subcritical reactor condition. The 

control rods and CRD assemblies adjust the concentration of the neutron absorber in the 

core during normal operations and shutdown conditions (10 CFR 54.4(a)(1)).

• Introduce emergency negative reactivity to make the reactor subcritical. When a 

Reactor Protection System scram signal is received, high-pressure water is applied to 

the CRD assemblies to rapidly insert each control rod into the core. The core plate 

differential pressure and standby liquid control line provides a flowpath for injecting a 

neutron absorber into the reactor core when control rods are unavailable 

(10 CFR 54.4(a)(1)).

• Sense process conditions and generate signals for reactor trip or engineered safety 

features actuation. Neutron flux detectors within the reactor core initiate a Reactor 

Protection System scram signal to shut down the reactor upon a high flux condition

(10 CFR 54.4(a)(1)).

• Provide emergency core cooling where the equipment provides coolant directly to the 

core. The low pressure coolant injection couplings and core spray piping and spargers 
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distribute emergency core cooling flow within the shroud to the reactor core 

(10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The nonsafety-related steam dryer could interact with 

safety-related components (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48), ATWS 

(10 CFR 50.62), and SBO (10 CFR 50.63) (10 CFR 54.4(a)(3)).

LRA Table 2.3.1-3, “Reactor Vessel Internals,” lists the component types of the Reactor Vessel 

Internals that require AMR and their intended functions.

Additional details for components subject to AMR are provided in the UFSAR sections identified 

above.

Staff Evaluation

The staff reviewed the system functions described in LRA Section 2.3.1.3, license renewal 

boundary drawings, and UFSAR Sections 3.9.5 and 4.1.2. The staff used the evaluation 

methodology in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and UFSAR to verify that the 

applicant has not omitted from the scope of license renewal any components with intended 

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the 

applicant has identified as being within the scope of license renewal to verify that it has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

Conclusion

Based on its review of the LRA Section 2.3.1.3 and the UFSAR, the staff concludes that the 

applicant appropriately identified the Reactor Vessel Internals that are within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant 

adequately identified the Reactor Vessel Internals components subject to AMR, as required by 

10 CFR 54.21(a)(1).

2.3.2 Engineered Safety Features Systems

LRA Section 2.3.2 identifies the Engineered Safety Features Systems SCs subject to an AMR 

for license renewal. The applicant described the supporting SCs of the Engineered Safety 

Features Systems in the following LRA sections:

• LRA Section 2.3.2.1, “High Pressure Core Spray System”

• LRA Section 2.3.2.2, “Low Pressure Core Spray System”

• LRA Section 2.3.2.3, “Reactor Core Isolation Cooling System”

• LRA Section 2.3.2.4, “Residual Heat Removal System”

• LRA Section 2.3.2.5, “Standby Gas Treatment System”

The staff’s findings on review of LRA Sections 2.3.2.1 – 2.3.2.5 are in SER Sections 2.3.2.1 –

2.3.2.5, respectively.
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2.3.2.1 High Pressure Core Spray System

Summary of Technical Information in the Application

LRA Section 2.3.2.1 describes the High Pressure Core Spray (HPCS) System as a standby 

ECCS system designed to deliver cooling water to the RPV and to maintain fuel cladding 

temperature below fragmentation in the event of small and large pipe breaks within the RCPB. 

After a pipe break, the system delivers water to the RPV though core spray spargers to the top 

surface of the core and depressurizes the reactor.

The HPCS System consists of a single motor-driven pump and associated piping, valves, and 

spray spargers. The HPCS System receives cooling water supply from the suppression pool. 

The system operates automatically when it receives signals on reactor low water level or drywell

high pressure signal.

More details regarding the HPCS System are provided in LRA Section 7.3.1.2.1 and UFSAR

Section 6.3.2.2.1.

The intended functions of the HPCS System within the scope of license renewal include the 

following:

• Provide primary containment boundary. The HPCS System includes safety-related 

primary containment isolation valves on the HPCS suction from the suppression pool, 

HPCS relief valve discharge piping, and the HPCS full flow test and minimum flow lines 

(10 CFR 54.4(a)(1)).

• Provide emergency core cooling where the equipment provides coolant directly to the 

core. The HPCS System provides core cooling following a break in the reactor coolant 

pressure boundary by delivering water from the suppression pool through nozzles in a 

circular sparger located above and around the core periphery (10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The HPCS System contains nonsafety-related water-filled lines 

in the Reactor Building that have potential spatial and structural interactions with 

safety-related SSCs (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48), EQ 

(10 CFR 50.49), and SBO (10 CFR 50.63) (10 CFR 54.4(a)(3)).

LRA Table 2.3.2-1, “HPCS System,” lists the components that are subject to an AMR. 

Additional details for components subject to an AMR are provided in the UFSAR sections

identified above.

Staff Evaluation

The staff reviewed the system functions described in LRA Section 2.3.2.1, license renewal 

drawings, and UFSAR Sections 6.3.2.2.1 and 7.3.1.2.1. The staff used the evaluation 

methodology in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and UFSAR to verify that the 

applicant has not omitted from the scope of license renewal any components with intended 

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the 
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applicant has identified as being within the scope of license renewal to verify that it has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

Conclusion

Based on its evaluation, the staff concludes that the applicant appropriately identified the HPCS

SSCs within the scope of license renewal as required by 10 CFR 54.4(a). The staff also 

concluded that the applicant adequately identified HPCS SSCs subject to an AMR as required 

by 10 CFR 54.21(a)(1).

2.3.2.2 Low Pressure Core Spray System

Summary of Technical Information in the Application

LRA Section 2.3.2.2 describes the Low Pressure Core Spray System (LPCS) as a standby 

system designed to provide core cooling following a break in the RCPB that would rapidly 

depressurize the reactor vessel. The LPCS is also designed to provide core cooling following a 

small break in which the automatic depressurization system (ADS) or HPCS has operated to

lower the reactor vessel pressure to the operating range of the LPCS. The system 

accomplishes these tasks by delivering water from the suppression pool to the RPV through 

nozzles in a circular sparger (separate from the HPCS sparger) located above and around the 

core periphery.

The LPCS is automatically actuated by reactor vessel low water level or drywell high pressure, 

or can be manually actuated from the control room. The ADS is interlocked with the LPCS by 

means of pressure switches located in the pump discharge piping upstream of the pump 

discharge check valves. The pump discharge pressure is used as a permissive for automatic 

initiation of ADS. This ensures that the LPCS pump has received electrical power, has started, 

and is capable of delivering water into the vessel prior to vessel depressurization.

The LPCS includes safety-related primary containment isolation valves on the LPCS suction 

from the suppression pool, the LPCS relief valve discharge piping, and the LPCS full flow test 

and minimum flow lines.

For further details, see LRA Section 2.3.2.2 and UFSAR Section 6.3.2.2.3.

The intended functions of the LPCS system within the scope of license renewal include the 

following:

• Provide primary containment boundary. The LPCS includes safety-related primary 

containment isolation valves on the LPCS suction from the suppression pool, LPCS 

relief valve discharge piping, and the LPCS full flow test and minimum flow lines

(10 CFR 54.4(a)(1)).

• Provide emergency core cooling where the equipment provides coolant directly to the 

core. The LPCS provides core cooling following a break in the reactor coolant pressure 

boundary by delivering water from the suppression pool through nozzles in a circular 

sparger located above and around the core periphery (10 CFR 54.4(a)(1)).
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• Sense process conditions and generate signals for reactor trip or engineered safety 

features actuation. LPCS pump discharge pressure is used as a permissive for 

automatic initiation of ADS (10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The LPCS contains nonsafety-related water-filled lines in the 

Reactor Building that have potential spatial interactions with safety-related SSCs 

(10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48), 

EQ (10 CFR 50.49), and SBO (10 CFR 50.63) (10 CFR 54.4(a)(3)).

LRA Table 2.3.2-2, “Low Pressure Core Spray System,” lists the components that are subject to 

an AMR.

Additional details for components subject to AMR are provided in the UFSAR sections identified 

above.

Staff Evaluation

The staff reviewed the system functions described in LRA Section 2.3.2.2, license renewal 

boundary drawings, and UFSAR Sections 6.3.2.2.3 and 7.3.1.2.2. The staff used the evaluation 

methodology in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and the UFSAR and verified that 

the applicant has not omitted from the scope of license renewal any components with intended 

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the 

applicant has identified as being within the scope of license renewal to verify that it has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

Conclusion

Based on its evaluation, the staff concludes that the applicant appropriately identified the LPCS 

SSCs within the scope of license renewal as required by 10 CFR 54.4(a). The staff also 

concluded that the applicant adequately identified LPCS SSCs subject to an AMR as required 

by 10 CFR 54.21(a)(1).

2.3.2.3 Reactor Core Isolation Cooling System

Summary of Technical Information in the Application

The Reactor Core Isolation Cooling (RCIC) System is a standby system designed to prevent 

reactor fuel from overheating under conditions in which (1) the reactor vessel is isolated and 

maintained in the hot standby condition, (2) the reactor vessel is isolated and accompanied by 

loss of the coolant flow from the reactor feedwater system, or (3) the reactor vessel is shut down 

under condition of loss of the normal feedwater system and before operation of the shutdown 

cooling system. The RCIC System is a nonsafety system; therefore, it has no safety design 

bases. However, it is included in license renewal because it supplies makeup water to the 

reactor vessel when it is isolated.
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The RCIC System operates automatically to maintain sufficient coolant in the reactor vessel 

when it is isolated under the conditions described above. During operation, the turbine-driven 

pump takes suction from the cycled condensate storage tank or suppression pool and injects 

water into the RPV via the head spray nozzle of the RPV. There is an automatic suction source 

switchover to the suppression pool when the cycled condensate storage tank is exhausted.

The RCIC System consists of a turbine-driven pump, piping, valves, accessories, and 

instrumentation capable of delivering makeup water to the reactor vessel to maintain sufficient 

reactor water inventory and adequate core cooling. The RCIC System is automatically initiated 

at a predetermined low reactor water level, or it can be manually initiated. The RCIC turbine 

steam supply comes from the RPV just upstream of the main steam isolation valves (MSIVs).

More details regarding the RCIC System are provided in LRA Section 2.3.1.3 and UFSAR 

Sections 5.4.6 and 7.4.1.

The intended functions of the RCIC System within the scope of license renewal include the 

following:

• Remove residual heat from the reactor coolant system. The RCIC System is capable of 

maintaining sufficient coolant inventory in the reactor vessel in case of an isolation with a 

loss of main feedwater flow (10 CFR 54.4(a)(1)).

• Provide primary containment boundary. The RCIC System includes safety-related 

primary containment isolation valves on the RCIC suction from the suppression pool, 

HPCS relief valve discharge piping, and the RCIC full flow test and minimum flow lines 

(10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The RCIC System includes nonsafety-related water-filled lines in 

the Reactor Buildings that have the potential for spatial interactions (spray or leakage) or 

structurally interact with safety-related SSCs (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48), 

EQ (10 CFR 50.49), and SBO (10 CFR 50.63) (10 CFR 54.4(a)(3)).

LRA Table 2.3.2-3 lists the component types for the RCIC System that require an AMR and their 

intended functions.

Additional details for components subject to AMR are provided in the UFSAR sections identified 

above.

Staff Evaluation

The staff reviewed the system functions described in LRA Section 2.3.2.3, license renewal 

boundary drawings, and UFSAR Sections 5.4.6 and 7.4.1. The staff used the evaluation 

methodology in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and the UFSAR and verified that 

the applicant has not omitted from the scope of license renewal any components with intended 

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the 

applicant has identified as being within the scope of license renewal to verify that it has not 
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omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

Conclusion

Based on its evaluation, the staff concludes that the applicant appropriately identified the RCIC 

SSCs within the scope of license renewal as required by 10 CFR 54.4(a). The staff also 

concluded that the applicant adequately identified RCIC SSCs subject to an AMR as required by 

10 CFR 54.21(a)(1).

2.3.2.4 Residual Heat Removal System

Summary of Technical Information in the Application

The Residual Heat Removal (RHR) System operates in three modes: (1) LPCI mode, 

(2) shutdown cooling and reactor vessel head spray mode, and (3) steam condensing mode. 

The LPCI function of the RHR is designed to provide cooling to the reactor core when the 

reactor pressure is low, such as for a large loss-of-coolant accident (LOCA) break. However, 

LPCI operation extends to a small break LOCA when it operates in conjunction with the ADS 

and HPCS Systems. This mode of operation is an integral part of the RHR System, and it

operates during normal shutdown and cooldown. The shutdown cooling and RPV head spray 

mode maintains the reactor core in a cold shutdown condition and meets the requirements of 

long-term heat removal. This mode is used to remove decay heat and to cool the reactor for 

maintenance and refueling. According to the LSCS UFSAR, an onsite review was performed 

and it deleted the steam condensing mode of operation, the details of which are provided in 

Section 5.4.7.2.2.3 of the UFSAR.

More details regarding the RHR System are provided in LRA Section 2.3.1.4 and UFSAR 

Sections 5.4.7 and 6.3.2.

The intended functions of the RHR System within the scope of license renewal include the 

following:

• Provide primary containment boundary. The RHR System provides safety-related 

primary containment isolation capability on containment spray discharge, suppression 

pool suction, and test return lines penetrating the primary containment

(10 CFR 54.4(a)(1)).

• Remove residual heat from the reactor coolant system. The RHR System removes 

decay and sensible heat from the reactor primary system (10 CFR 54.4(a)(1)).

• Provide emergency core cooling where the equipment provides coolant directly to the 

core. The RHR System provides water from the suppression pool to be injected directly 

into the core region of the reactor vessel following a LOCA (10 CFR 54.4(a)(1)).

• Provide emergency heat removal from primary containment and provide containment 

pressure control. The RHR System provides for maintaining the suppression pool 

temperature below required limits following a reactor blowdown. The RHR System also 

provides for spraying the drywell and suppression pool vapor spaces to maintain internal 

pressure below design limits (10 CFR 54.4(a)(1)).
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• Sense process conditions and generate signals for reactor trip or engineered safety 

features actuation. The RHR System provides for associated actuation and system 

protection logic for engineered safety features operation (10 CFR 54.4(a)(1)).

• Ensure adequate cooling in the spent fuel pool to maintain stored fuel within acceptable 

temperature limits. The RHR System provides additional cooling capacity for fuel pool 

cooling (10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The RHR System contains nonsafety-related fluid-filled lines 

within the Reactor Buildings that have the potential for spatial interaction with 

safety-related SSCs (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48), 

EQ (10 CFR 50.49), and SBO (10 CFR 50.63) (10 CFR 54.4(a)(3)).

LRA Table 2.3.2-4 lists the RHR System component types that require an AMR and their 

intended functions.

Additional details for components subject to an AMR are provided in the UFSAR sections

identified above.

Staff Evaluation

The staff reviewed the system functions described in LRA Section 2.3.2.4, license renewal 

drawings, and UFSAR Sections 5.4.7, 6.3.1, and 6.3.2. The staff used the evaluation 

methodology in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff evaluated the system functions described in the LRA and the UFSAR and verified that 

the applicant has not omitted from the scope of license renewal any components with intended 

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the 

applicant has identified as being within the scope of license renewal to verify that it has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

Conclusion

Based on its evaluation, the staff concludes that the applicant appropriately identified the RHR 

SSCs within the scope of license renewal as required by 10 CFR 54.4(a). The staff also 

concluded that the applicant adequately identified RHR System SSCs subject to an AMR as 

required by 10 CFR 54.21(a)(1).

2.3.2.5 Standby Gas Treatment System

Summary of Technical Information in the Application

LRA Section 2.3.2.5 states that the purpose of the Standby Gas Treatment (SGT) System is to 

reduce the amount of halogen and particulate in gases leaking from the primary containment, 

which are potentially present in the secondary containment following an accident. The system 

can also be used as an alternate method to purge the primary containment. The SGT System 

also controls releases from postulated fuel-handling accidents.
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When the system is initiated, it takes suction from the secondary containment and treats the air, 

which is then released to the environment through the plant stack at an elevated release point. 

The SGT System maintains a slightly negative secondary containment pressure in order to 

prevent untreated air leakage from being released to the environment. The SGT System is 

safety related and powered from essential buses. The SGT System functions during a design 

basis LOCA with a simultaneous loss of offsite power. The system is normally in standby, and 

automatically starts and operates during DBAs.

Two independent SGT subsystems are shared between Units 1 and 2. Each subsystem 

consists of ductwork, dampers, charcoal filter train, and isolation and control dampers, 

interconnecting pipes, and associated instrumentation. The charcoal filter trains consist of a 

filter unit fan and cooling fan, a demister, an electric heater, a prefilter bank, two high-efficiency 

particulate air filter banks, and a charcoal adsorber.

The intended functions of the SGT System within the scope of license renewal include the 

following:

• Control and treat radioactive materials released to the secondary containment. The 

SGT System maintains a negative pressure within secondary containment, and reduces 

halogen and particulate concentrations in gases potentially present in the secondary 

containment following an accident prior to release to the environment 

(10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The SGT System includes nonsafety-related piping that 

structurally interacts with safety-related SSCs, and water-filled components that have 

the potential for spatial interactions (spray or leakage) with safety-related SSCs 

(10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49)

(10 CFR 54.4(a)(3)).

LRA Table 2.3.2-5 identifies the SGT System component types within the scope of license 

renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.2.5, UFSAR Sections 6.5.1 and 7.3.8, LRA Table 3.2.2-5, 

and the license renewal boundary drawings using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and the UFSAR 

to verify that the applicant has not omitted from the scope of license renewal any components 

with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant has identified as being within the scope of license renewal to 

verify that it has not omitted any passive and long-lived components subject to an AMR in 

accordance with the requirements of 10 CFR 54.21(a)(1).
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Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the SGT System mechanical components within the scope of license 

renewal as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately 

identified the system components subject to an AMR in accordance with the requirements in 

10 CFR 54.21(a)(1).

2.3.3 Auxiliary Systems

LRA Section 2.3.3 identifies the Auxiliary Systems SCs subject to an AMR for license renewal. 

The applicant described the supporting SCs of the Auxiliary Systems in the following LRA 

sections:

• LRA Section 2.3.3.1, “Closed Cycle Cooling Water System”

• LRA Section 2.3.3.2, “Combustible Gas Control System”

• LRA Section 2.3.3.3, “Compressed Air System”

• LRA Section 2.3.3.4, “Control Rod Drive System”

• LRA Section 2.3.3.5, “Control Room Ventilation System”

• LRA Section 2.3.3.6, “Cranes, Hoists and Refueling Equipment System”

• LRA Section 2.3.3.7, “Demineralized Water Makeup System”

• LRA Section 2.3.3.8, “Diesel Generator and Auxiliaries System”

• LRA Section 2.3.3.9, “Drywell Pneumatic System”

• LRA Section 2.3.3.10, “Electrical Penetration Pressurization System”

• LRA Section 2.3.3.11, “Essential Cooling Water System”

• LRA Section 2.3.3.12, “Fire Protection System”

• LRA Section 2.3.3.13, “Fuel Pool Cooling and Storage System”

• LRA Section 2.3.3.14, “Nonessential Cooling Water System”

• LRA Section 2.3.3.15, “Nonsafety-Related Ventilation System”

• LRA Section 2.3.3.16, “Plant Drainage System”

• LRA Section 2.3.3.17, “Primary Containment Ventilation System”

• LRA Section 2.3.3.18, “Process Radiation Monitoring System”

• LRA Section 2.3.3.19, “Process Sampling and Post Accident Monitoring System”

• LRA Section 2.3.3.20, “Radwaste System”

• LRA Section 2.3.3.21, “Reactor Water Cleanup System”

• LRA Section 2.3.3.22, “Safety-Related Ventilation System”

• LRA Section 2.3.3.23, “Standby Liquid Control System”

• LRA Section 2.3.3.24, “Suppression Pool Cleanup System”

• LRA Section 2.3.3.25, “Traversing Incore Probe System”

The staff’s findings on review of LRA Sections 2.3.3.1 – 2.3.3.25 are in SER Sections 2.3.3.1 –

2.3.3.25, respectively.

2.3.3.1 Closed Cycle Cooling Water System

Summary of Technical Information in the Application

The Closed Cycle Cooling Water (CCW) System includes the reactor building closed cooling 

water (RBCCW) system and turbine building closed cooling water (TBCCW) system. The CCW 
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System is in scope for license renewal. However, portions of the CCW System do not perform 

intended functions and are not in scope. The CCW System is a normally operating closed 

cooling water system designed to provide cooling water to various plant components.

The purpose of the RBCCW portion of the CCW System is to provide cooling water to various 

components in the Reactor Building, Primary Containment and Offgas Building. The system 

accomplishes this by circulating demineralized and chemically treated cooling water through 

these components and by transferring the heat to the plant service water system through the 

RBCCW heat exchangers.

The purpose of the TBCCW portion of the CCW System is to provide cooling water to various 

components in the Turbine Building. The system accomplishes this function by circulating 

demineralized and chemically treated cooling water through these components and by 

transferring the heat to the plant’s service water system through the TBCCW heat exchangers. 

The TBCCW portion of the CCW does not perform an intended function and is not in scope for 

license renewal.

The intended functions of the CCW System within the scope of license renewal include the 

following:

• Provide primary containment boundary. The system includes safety-related primary 

containment isolation valves (10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. It contains nonsafety-related water-filled lines in the Reactor 

Building, Primary Containment, and Auxiliary Building that provide structural support or 

that have potential spatial interactions with safety-related SSCs (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49). The system 

contains components that are environmentally qualified (10 CFR 54.4(a)(3)).

LRA Table 2.3.3-1 identifies the CCW System component types within the scope of license 

renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.1, UFSAR Sections 9.2.3 and 9.2.8, and the license 

renewal boundary drawings using the evaluation methodology discussed in SER Section 2.3 

and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did not identify the 

need for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the CCW System mechanical components within the scope of license 

renewal as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately 

identified the system components subject to an AMR in accordance with the requirements in 

10 CFR 54.21(a)(1).
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2.3.3.2 Combustible Gas Control System

Summary of Technical Information in the Application

The Combustible Gas Control (CGC) System includes the nitrogen supply system, containment 

vent and purge system, and the hydrogen recombiner system. The CGC System is a standby 

system designed to ensure that primary containment integrity is not threatened by the possibility 

of combustion of combustible gases following a LOCA. The CGC System is within the scope of 

license renewal. However, portions of the CGC System are not required to perform intended 

functions and are not included in the scope of license renewal.

LRA Section 2.3.3.2 states that the purpose of the CGC System includes inerting primary 

containment with nitrogen, purging containment with air to permit maintenance, controlling 

containment pressure, and controlling combustible gas concentrations after a LOCA.

The purpose of the nitrogen supply system is to provide a supply of gaseous nitrogen to the 

primary containment on both units to maintain an inert atmosphere within primary containment. 

Liquid nitrogen, which is stored in tanks, is vaporized and is provided to either unit in high-flow 

mode for inerting and in low-flow mode for normal makeup to maintain an inert atmosphere at a 

slight positive pressure. The nitrogen supply system is nonsafety related, does not support any 

intended functions, and is not in scope for license renewal.

The purpose of the containment vent and purge system is to supply nitrogen from the nitrogen 

supply system or air from the Reactor Building to Primary Containment and to vent displaced 

containment atmosphere through a purge air filter train or the SGT System before discharge to 

the environment. The portions of the containment vent and purge system that maintain the 

primary or secondary containment boundary are safety related, designed to seismic Category I 

requirements, and are in scope for license renewal.

The purpose of the hydrogen recombiner system is to provide mixing that prevents combustible 

concentrations of hydrogen from accumulating in low-flow areas within the drywell. The 

hydrogen recombiner system is comprised of two redundant hydrogen recombiner packages 

that can service either unit. During post-accident conditions, when hydrogen levels in 

containment are elevated, flow is established from the drywell air space through a blower that is 

part of the recombiner package to the suppression chamber air space. The hydrogen 

recombining function of the hydrogen recombiners is abandoned in place and not credited for 

reducing hydrogen concentration inside containment. The hydrogen recombiner system is 

safety-related, designed to seismic Category I requirements, and is in scope for license renewal.

The intended functions of the CGC System within the scope of license renewal include the 

following:

• Provide primary containment boundary. The CGC System includes piping and isolation 

valves that form the primary containment boundary (10 CFR 54.4(a)(1)).

• Provide secondary containment boundary. The CGC System includes piping and 

isolation valves in the primary containment vent and purge flow paths that form the 

secondary containment boundary (10 CFR 54.4(a)(1)).

• Provide emergency heat removal from primary containment and provide containment 

pressure control. The CGC System includes flow paths from primary containment that 

are used to vent primary containment for pressure control (10 CFR 54.4(a)(1)).
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• Control combustible gas mixtures in the primary containment atmosphere. The CGC 

System is credited with establishing and maintaining an inert atmosphere within primary 

containment during power operation. The CGC System also includes equipment that 

provides mixing of the containment atmosphere to prevent combustible mixtures of 

hydrogen and oxygen from forming following an accident (10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. Some portions of nonsafety-related piping are relied on to 

preserve the structural support intended function of the safety-related piping used for 

purging, inerting, and containment isolation. Some portions of the discharge and drain 

piping from the hydrogen recombiners may be liquid-filled and have a potential for 

spatial interaction with safety-related equipment within the Reactor Building 

(10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49). The CGC 

System includes equipment that is environmentally qualified to remain functional during 

post-accident conditions (10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for SBO (10 CFR 50.63). The CGC 

System includes primary containment isolation valves that are required to close to 

mitigate an SBO event (10 CFR 54.4(a)(3)).

LRA Table 2.3.3-2 identifies the CGC System component types within the scope of license 

renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.2; UFSAR Sections 6.2.5, 7.3.5, 9.4.10, and 9.5.9; and

the license renewal boundary drawings using the evaluation methodology discussed in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff 

identified an area in which additional information was necessary to complete the review of the 

applicant‘s scoping and screening results.

One review method used by the staff is to confirm the inclusion of all components subject to an 

AMR by reviewing the results of the screening of components within the license renewal 

boundary. In RAI 2.3.3.2-1, the staff notes that it could not locate continuations of piping within 

the scope of license renewal during its review of the drawings and locations indicated in the 

table below and, therefore, could not verify acceptable scoping of SSCs.

License Renewal Boundary Drawing 

Number and Location Continuation Issue

LR-LAS-M-130 Sheet 1, location A/B-8 212o and 30o continuations at the containment side of 

penetrations M-102 and M-95, respectively, were not 

provided.

LR-LAS-M-130 Sheet 2, location A/B-8 212o and 30o continuations at the containment side of 

penetrations M-102 and M-95, respectively, were not 

provided.

The NRC requested that the applicant provide sufficient information to locate the license 

renewal boundary. If the continuation cannot be shown on license renewal boundary drawings, 

the applicant must provide additional information describing the extent of the scoping boundary 
2-41

and must verify whether there are additional component types subject to an AMR between the 

continuation and the termination of the scoping boundary. If the scoping classification of a 

section of the piping changes over the continuation, the applicant must provide additional 

information to clarify the change in scoping classification.

In its response letter dated August 26, 2015, the applicant stated that the piping segments at 

primary containment penetrations M-102 and M-95 extend inside the primary containment air 

space and end at the open-ended piping.

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.2-1 acceptable 

because the applicant provided the location of the scoping boundary and stated that there are 

no additional components or component types subject to AMR. Therefore, the staff’s concern 

described in RAI 2.3.3.2-1 is resolved.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, RAI response, and license renewal boundary drawings, the staff concludes 

that the applicant appropriately identified the CGC System mechanical components within the 

scope of license renewal as required by 10 CFR 54.4(a). The staff also concludes that the 

applicant adequately identified the system components subject to an AMR in accordance with 

the requirements in 10 CFR 54.21(a)(1).

2.3.3.3 Compressed Air System

Summary of Technical Information in the Application

The Compressed Air System (CAS) includes the service air plant system and the instrument air 

plant system. The CAS is in scope for license renewal. However, portions of the CAS are not 

required to perform intended functions and are not in scope. The CAS is primarily a 

nonsafety-related system that is designed for continuous operation.

LRA Section 2.3.3.3 states the purpose of the normally operating CAS is to provide compressed 

air for station use.

The purpose of the service air subsystem is to supply compressed air for operating pneumatic 

equipment; air operated controls; maintenance services; and interruptible equipment, such as 

tank mixing air spargers.

The purpose of the instrument air system is to supply compressed air for air-operated control 

devices and instruments outside the drywell.

A portion of the CAS performs a safety-related function. The portion of the service air piping 

that penetrates primary containment and the associated primary containment isolation valves 

are safety-related components that are relied on to provide the primary containment boundary.

The intended functions of the CAS within the scope of license renewal include the following:

• Provide primary containment boundary. The CAS contains safety-related primary 

containment isolation valves and piping that penetrates the primary containment 

(10 CFR 54.4(a)(1)).
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• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The CAS includes nonsafety-related piping and components 

that have the potential for structural interactions with safety-related SSCs 

(10 CFR 54.4(a)(2)).

LRA Table 2.3.3-3 identifies the CAS component types within the scope of license renewal and 

subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.3, UFSAR Section 9.3.1, and the license renewal 

boundary drawings using the evaluation methodology discussed in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. On the basis of its review, the staff did not identify the need 

for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the CAS mechanical components within the scope of license renewal as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the system components subject to an AMR in accordance with the requirements in 

10 CFR 54.21(a)(1).

2.3.3.4 Control Rod Drive System

Summary of Technical Information in the Application

LRA Section 2.3.3.4 states that the primary safety-related purpose of the Control Rod Drive 

(CRD) System is to support rapid insertion of negative reactivity into the reactor core to shut 

down the reactor under accident or transient conditions by simultaneously inserting all control 

rods. The CRD System is also used to manage core reactivity and control reactor power during 

normal reactor operation by inserting or withdrawing control rods at a controlled rate, one rod at 

a time. The CRD System also supplies makeup to the reactor vessel water level reference leg 

condensing chambers and a low-flow rate of cool, clean, high-pressure purge water to reactor 

recirculation pump seals and RWCU pumps.

The intended functions of the CRD System within the scope of license renewal include the 

following:

• Introduce negative reactivity to achieve or maintain a subcritical reactor condition. 

The hydraulic control units (HCUs) provide the motive force to the control rod drive 

mechanisms to rapidly insert control rods during a scram event (10 CFR 54.4(a)(1)).

• Provide primary containment boundary. The directional control valves on the HCUs 

provide a containment isolation function from the CRD insert and withdrawal lines 

(10 CFR 54.4(a)(1)).

• Sense process conditions and generate signals for reactor trip or engineered safety 

features actuation (10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The CRD System includes nonsafety-related water-filled, 
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pressure-retaining piping and equipment within the Reactor Building and Auxiliary 

Building that have the potential for spatial and structural interaction with safety-related 

equipment (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48). The 

CRD System includes equipment that is credited by fire safe shutdown analysis to shut 

down the reactor via the scram function (10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49). The CRD 

System includes instrumentation and equipment that is required to be environmentally 

qualified (10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for ATWS (10 CFR 50.62). The CRD 

System includes solenoid valves that receive signals from the plant alternate rod 

insertion system to provide an alternate means of venting the scram air header and 

cause insertion of control rods (10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for SBO (10 CFR 50.63). The SBO 

analysis credits the CRD System with successfully inserting all control rods upon receipt 

of scram initiation signals from the reactor protection system (10 CFR 54.4(a)(3)).

LRA Table 2.3.3-4 identifies the CRD System component types within the scope of license 

renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.4, UFSAR Section 4.6, and the license renewal boundary 

drawings using the evaluation methodology discussed in SER Section 2.3 and the guidance in 

SRP-LR Section 2.3. On the basis of its review, the staff identified an area in which additional 

information was necessary to complete the review of the applicant‘s scoping and screening 

results.

In RAI 2.3.3.4-1, the staff notes that it could not locate seismic or equivalent anchors between 

the safety and nonsafety interface and the end of the 10 CFR 54.4(a)(2) scoping boundary on 

the following drawings:

• LR-LAS-M-100-4 (B-2) downstream of safety-related valve 1C11-F381

• LR-LAS-M-146-4 (B-1) downstream of safety-related valve 2C11-F381

• LR-LAS-M-93-1 (B-8) upstream of safety-related valve 1B33-F017A

• LR-LAS-M-139-1 (B-8) upstream of safety-related valve 2B33-F017A

• LR-LAS-M-100-3 and LR-LAS-M-146-3 (C-4, 5, 6, and 7) upstream of safety-related 

valves 5, 3, 4, and 9

• LR-LAS-M-100-5 and LR-LAS-M-146-6 (E-1, B-4, C-4, E-4, F-4, and E-8) upstream of 

safety-related valve 7 (six places)
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The NRC requested that the applicant provide additional information to locate the seismic or 

equivalent anchors between the safety and nonsafety interface and the end of the 

10 CFR 54.4(a)(2) scoping boundary.

In its response letter dated August 26, 2015, the applicant provided the location of additional 

equivalent anchors or clarified the location of existing anchors to the end of the 

10 CFR 54.4(a)(2) scoping boundary.

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.4-1 acceptable 

because the applicant provided the location of additional equivalent anchors or clarified the 

location of existing anchors. Therefore, the staff’s concern described in RAI 2.3.3.4-1 is 

resolved.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, RAI response, and license renewal boundary drawings, the staff concludes 

that the applicant appropriately identified the CRD System mechanical components within the 

scope of license renewal as required by 10 CFR 54.4(a). The staff also concludes that the 

applicant adequately identified the system components subject to an AMR in accordance with 

the requirements in 10 CFR 54.21(a)(1).

2.3.3.5 Control Room Ventilation System

Summary of Technical Information in the Application

LRA Section 2.3.3.5 states that the purpose of the Control Room Ventilation (CRV) System is to 

ensure habitability inside the control rooms and auxiliary electrical equipment rooms during all 

normal and abnormal station operating conditions. The CRV System ensures that the control 

room operators are safe against postulated releases of radioactive materials, noxious gases, 

smoke, and steam. In addition the environment in the control rooms and auxiliary electrical 

equipment rooms is maintained in order to ensure the integrity of the contained safety-related 

controls and equipment during all station operating conditions. The CRV license renewal 

system consists of the control room area ventilation plant system, the auxiliary electric 

equipment room ventilation plant system, the refrigeration plant system, and the breathing air 

plant system.

The intended functions of the CRV System within the scope of license renewal include the 

following:

• Provide centralized area for control and monitoring of nuclear safety-related equipment. 

The primary purpose of the CRV System is to maintain environmental conditions and 

ensure the safety and comfort of operating personnel in the control room. The system 

also monitors for the presence of ammonia, radioactive contamination, and smoke and 

provides a filtered fresh air supply as necessary in response to these conditions 

(10 CFR 54.4(a)(1)).

• Maintain emergency temperature limits within areas containing safety-related 

components. The CRV System maintains environmental conditions to ensure the 

operability of safety-related equipment in the control rooms and auxiliary electric 

equipment rooms (10 CFR 54.4(a)(1)).
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• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The CRV System contains nonsafety-related liquid-filled 

components, specifically the cooling coil drip pans, which have the potential for spatial 

interactions with safety-related SSCs (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48). The 

CRV System is relied on to maintain a habitable environment and to ensure the 

operability of safety-related components in the control rooms and auxiliary equipment 

rooms during a fire safe shutdown event (10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49). The CRV system 

contains components that are environmentally qualified (10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for SBO (10 CFR 50.63). The CRV 

system is relied on to maintain a habitable environment and to ensure the operability of 

safety-related components in the control rooms and auxiliary electrical equipment rooms 

during SBO recovery (10 CFR 54.4(a)(3)).

LRA Table 2.3.3-5 identifies the CRV System component types within the scope of license 

renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.5 using the evaluation methodology described in SER 

Section 2.3 and the UFSAR and the guidance in SRP-LR Section 2.3. On the basis of its 

review, the staff did not identify the need for any additional information. During its review, the 

staff evaluated the system functions described in the LRA and UFSAR to verify that the 

applicant has not omitted from the scope of license renewal any components with intended 

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the 

applicant has identified as being within the scope of license renewal to verify that it has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the CRV System components within the scope of license renewal as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the system components subject to an AMR as required by 10 CFR 54.21(a)(1).

2.3.3.6 Cranes, Hoists and Refueling Equipment System

Summary of Technical Information in the Application

LRA Section 2.3.3.6 states the purpose of the Cranes, Hoists and Refueling Equipment System 

is to safely move material and equipment to support operations and maintenance activities. 

The Cranes, Hoists and Refueling Equipment System accomplishes this through compliance 

with NUREG-0612, “Control of Heavy Loads at Nuclear Power Plants: Resolution of Generic 
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Technical Activity A-36,” dated July 1980, and administrative controls so that damage from a 

postulated heavy load drop does not prevent safe shutdown of the reactor.

The Cranes, Hoists and Refueling Equipment System is a standby system comprised of load 

handling bridge cranes, jib cranes, lifting devices, monorails, and hoists provided throughout the 

facility and designed to support operation and maintenance activities. Also included are 

equipment that handles fuel and other light loads above fuel and other safety-related 

components in support of reactor refueling. The Cranes, Hoists and Refueling Equipment 

System is in scope for license renewal. Portions of the Cranes, Hoists and Refueling 

Equipment System are not required to perform intended functions and are not in scope.

The intended functions of the Cranes, Hoists and Refueling Equipment System within the scope 

of license renewal include the following:

• Provide physical support, shelter, and protection for safety-related SSCs. The reactor 

building crane is safety-related and seismically qualified and is used to transport heavy 

loads over irradiated fuel and above or near safety-related components 

(10 CFR 54.4(a)(1)).

• Provide a safe means for handling safety-related components and loads above or near 

safety-related components. The Cranes, Hoists and Refueling Equipment System

components within the scope of license renewal handle equipment or fuel above or near 

safety-related components or spent fuel (10 CFR 54.4(a)(2)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The nonsafety-related cranes, hoists and refueling equipment 

that are in scope provide a safe means for handling loads above or near safety-related 

components (10 CFR 54.4(a)(2)).

LRA Table 2.3.3-6 identifies the Cranes, Hoists and Refueling Equipment System component 

types within the scope of license renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.6 and UFSAR Section 9.1.4 and Appendix O using the 

evaluation methodology discussed in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

On the basis of its review, the staff did not identify the need for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Cranes, Hoists and Refueling Equipment System mechanical 

components within the scope of license renewal as required by 10 CFR 54.4(a). The staff also 

concludes that the applicant adequately identified the system components subject to an AMR in 

accordance with the requirements in 10 CFR 54.21(a)(1).
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2.3.3.7 Demineralized Water Makeup System

Summary of Technical Information in the Application

The Demineralized Water Makeup System includes the domestic water, the makeup 

demineralizer, and the well water plant systems. The Demineralized Water Makeup System is 

in scope for license renewal. However, portions of the Demineralized Water Makeup System

are not required to perform or support intended functions and are not included in the scope of 

license renewal.

LRA Section 2.3.3.7 states the purpose of the normally operating Demineralized Water Makeup

System is to provide water from onsite wells; purify the stored well water; and provide it for 

various uses throughout the plant, including potable and domestic use and high-purity 

reactor-grade water for makeup to the clean and cycled condensate storage tanks and various 

plant systems.

The purpose of the well water system is to provide a source of groundwater to supply plant 

needs. The well water system accomplishes this by pumping water from two onsite deep wells 

and filtering the water for storage in the 350,000-gal well water storage tank.

The purpose of the makeup demineralizer system is to purify the water stored in the well water 

storage tank and to make it suitable for use for makeup to the clean and cycled condensate 

storage tanks. The makeup demineralizer system accomplishes this by using demineralizers 

and filters to purify water to meet reactor-grade water quality requirements.

The purpose of the domestic water system is to provide potable water for domestic use on site. 

The domestic water system accomplishes this by processing water from the well water storage 

tank. Water for domestic consumption is chlorinated and filtered to meet drinking water 

standards.

The intended function of the Demineralized Water Makeup System within the scope of license 

renewal includes the following:

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The Demineralized Water Makeup System contains 

nonsafety-related liquid-filled lines in the Reactor Building and Auxiliary Building, which 

have potential spatial interactions with safety-related SSCs (10 CFR 54.4(a)(2)).

LRA Table 2.3.3-7 identifies the Demineralized Water Makeup System component types within 

the scope of license renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.7; UFSAR Sections 1.2.3.6.4, 2.4.13.1.3, 9.2.4, and 9.2.5;

and the license renewal boundary drawings using the evaluation methodology discussed in SER

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for additional information.
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Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Demineralized Water Makeup System mechanical components 

within the scope of license renewal as required by 10 CFR 54.4(a). The staff also concludes 

that the applicant adequately identified the system components subject to an AMR in 

accordance with the requirements in 10 CFR 54.21(a)(1).

2.3.3.8 Diesel Generator and Auxiliaries System

Summary of Technical Information in the Application

The Diesel Generator and Auxiliaries System consists of the following plant systems: the diesel 

generator system, diesel oil transfer system, fire seals and fuel storage, and the technical 

support center diesel. The Diesel Generator and Auxiliaries System also includes the security 

diesel.

The Diesel Generator and Auxiliaries System uses five diesel engines to power electric 

generators. The system includes two diesel generators for each LSCS unit and a diesel 

generator that can be aligned to busses that supply power to loads on both units. One of the 

diesel generators for each unit has the primary purpose to supply emergency power to the 

HPCS pump motor. The Diesel Generator and Auxiliaries System is designed for physical 

separation and redundancy so that no single active failure can prevent the system from 

performing its safety-related function and remaining functional during and following a safe 

shutdown earthquake seismic event. Each diesel generator includes self-contained auxiliary 

support systems that include starting air, closed cooling water, engine lubricating oil, 

combustion air intake and exhaust, and diesel fuel oil storage and transfer.

The purpose of the diesel generator system is to provide a source of electrical power that is not 

dependent on offsite sources and that is capable of supplying sufficient power to those electrical 

loads, which are required to support the simultaneous safe shutdown of both units, coincident 

with a LOCA on one unit.

The purpose of the fuel oil storage, transfer, and delivery system is to provide a sufficient 

volume of clean, high-quality fuel to support 7 days of continuous operation following all design 

bases accidents. The fuel oil system also includes the fuel storage, transfer and delivery 

system for the two diesel-driven fire pumps that is interconnected to the HPCS diesel storage 

tanks. The fuel oil system for the fire pumps is nonsafety-related but supports compliance with 

regulations for fire protection by supporting the distribution of water used for suppression of 

fires.

The fuel oil system also includes the fuel storage, transfer, and delivery system for the security 

diesel generator and Technical Support Center diesel generator. These fuel oil systems are 

independent of the fuel oil systems that supply fuel to the five emergency diesel generators and 

the diesel-driven fire pumps.

The intended functions of the Diesel Generator and Auxiliaries System within the scope of 

license renewal include the following:
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• Provide motive power to safety-related components. The Diesel Generator and 

Auxiliaries System is required to power safety-related equipment in the event that 

normal offsite power sources are not available (10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The Diesel Generator and Auxiliaries System includes 

nonsafety-related fluid-filled lines in the diesel rooms that have the potential for spatial 

interactions with safety-related SSCs. The starting air system includes 

nonsafety-related piping that is in scope to provide a seismic anchor credited for 

structural support of safety-related piping (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for SBO (10 CFR 50.63). The Diesel 

Generator and Auxiliaries System provides an alternate power source required to cope 

with an SBO event to support safe shutdown and decay heat removal for the blacked out 

unit for the required coping duration (10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48). The 

Diesel Generator and Auxiliaries System provides power to safe shutdown equipment in 

the event of a loss of offsite power coincident with the postulated fire for several 

analyzed fire safe shutdown methods. The Diesel Generator and Auxiliaries System 

also provides the fuel oil supply to the diesel-driven fire water pumps that support the 

distribution of water used for fire suppression (10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49). The Diesel 

Generator and Auxiliaries System includes safety-related components located within 

areas of the plant that may have harsh environments and, therefore, have environmental 

qualifications (10 CFR 54.4(a)(3)).

LRA Table 2.3.3-8 identifies the Diesel Generator and Auxiliaries System component types 

within the scope of license renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.8; UFSAR Sections 7.3.6, 8.3.1, and 9.5.4 through 9.5.8;

and the license renewal boundary drawings using the evaluation methodology discussed in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Diesel Generator and Auxiliaries System mechanical components 

within the scope of license renewal as required by 10 CFR 54.4(a). The staff also concludes 

that the applicant adequately identified the system components subject to an AMR in 

accordance with the requirements in 10 CFR 54.21(a)(1).
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2.3.3.9 Drywell Pneumatic System

Summary of Technical Information in the Application

LRA Section 2.3.3.9 states the purpose of the Drywell Pneumatic System (DPS) is to provide a 

supply of gas for operation of pneumatic devices and for purging of the Traversing Incore Probe 

(TIP) indexing mechanisms located inside the primary containment. The DPS accomplishes 

this by drawing gas from inside the primary containment and processing it through filters, 

compressors, coolers, separators, dryers, and receivers before distributing the gas to users 

inside the primary containment. The DPS includes individual safety-related accumulators of 

sufficient capacity to provide for the operation of the MSIVs, main steam safety/relief valves, 

and ADS valves in the event of a loss of the normal nonsafety-related gas supply. The DPS 

also includes a safety-related backup compressed gas system for the ADS accumulators 

consisting of two compressed nitrogen bottle banks and an emergency pressurization station 

that provide a long-term pneumatic supply to the ADS valves to support post-accident reactor 

decay heat removal.

The intended functions of the DPS within the scope of license renewal include the following:

• Provide primary containment boundary. The DPS includes safety-related containment 

isolation valves (10 CFR 54.4(a)(1)).

• Provide motive power to safety-related components. The DPS provides a supply of gas 

for operation of the MSIVs, main steam safety/relief valves, and ADS valves following a 

DBA (10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The DPS contains nonsafety-related water-filled lines in the 

Reactor Building that have potential spatial interactions with safety-related SSCs. 

The DPS also contains nonsafety-related gas-filled lines relied on to preserve the 

structural support intended function of the system (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48). The 

function of providing gas for ADS valve operation is credited for fire safe shutdown 

(10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49). The DPS 

contains components that are environmentally qualified (10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for SBO (10 CFR 50.63). The function of 

providing gas for ADS valve operation is credited for SBO coping (10 CFR 54.4(a)(3)).

LRA Table 2.3.3-9 identifies the DPS component types within the scope of license renewal and 

subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.9 and UFSAR Section 9.3.1 using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. On the 

basis of its review, the staff did not identify the need for additional information.
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Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the DPS mechanical components within the scope of license renewal as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the system components subject to an AMR in accordance with the requirements in 

10 CFR 54.21(a)(1).

2.3.3.10 Electrical Penetration Pressurization System

Summary of Technical Information in the Application

LRA Section 2.3.3.10 states that the purpose of the Electrical Penetration Pressurization (EPP) 

System is to provide a means to manually supply nitrogen to electrical penetration assemblies 

for Unit 2. The electrical penetration assemblies provide continuity of electric circuits through 

the containment building wall while maintaining containment integrity. The assemblies are 

pressurized internally with nitrogen to minimize moisture intrusion and condensation. This 

ensures that the connected electrical equipment performs as required and ensures containment 

leak-tightness.

The intended function of the EPP System within the scope of license renewal includes the 

following:

• Provide primary containment boundary. The EPP System components connect directly 

to the LSCS, Unit 2, electrical penetration assemblies and have the potential for 

structural interaction (10 CFR 54.4(a)(1)).

LRA Table 2.3.3-10 identifies the EPP System component types within the scope of license 

renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.10; UFSAR Sections 6.2.6.2 and 3.8.1.1 and Table 3.2-1;

and the license renewal boundary drawings using the evaluation methodology discussed in SER

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the EPP System mechanical components within the scope of license 

renewal as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately 

identified the system components subject to an AMR in accordance with the requirements in 

10 CFR 54.21(a)(1).
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2.3.3.11 Essential Cooling Water System

Summary of Technical Information in the Application

LRA Section 2.3.3.11 states the purpose of the Essential Cooling Water (ECW) System is to 

circulate lake water from the ultimate heat sink (UHS) to the RHR System heat exchangers, 

diesel generator coolers, core standby cooling system (CSCS) area coolers, LPCS System 

pump motor cooling coils, and RHR pump seal coolers by circulating cooling water from the 

UHS to the component coolers and returning the heated water to the UHS. The ECW System is 

a standby system.

Another function of the ECW System includes providing a source of emergency makeup water 

for fuel pool cooling and containment flooding water for post-accident recovery by providing 

water from the UHS to the spent fuel pool emergency makeup pumps. Flooding of the 

containment is accomplished by providing water from the UHS to the containment.

The intended functions of the ECW System within the scope of license renewal include the 

following:

• Remove residual heat from the reactor coolant system. The ECW System provides

cooling to equipment that removes decay heat from the reactor during normal operation 

and accident conditions (10 CFR 54.4(a)(1)).

• Provide heat removal from safety-related heat exchangers. The ECW System removes 

heat from the RHR heat exchangers and ECCS pump seal and motor coolers during 

normal operation and accident conditions (10 CFR 54.4(a)(1)).

• Provide emergency heat removal from primary containment and provide containment 

pressure control. The ECW System removes heat from the RHR heat exchangers 

during transient and accident conditions. The ECW System provides containment 

flooding water for post-accident recovery (10 CFR 54.4(a)(1)).

• Maintain emergency temperature limits within areas containing safety-related 

components. The ECW System removes heat from secondary containment equipment 

compartments that house ECCS and ECW components (10 CFR 54.4(a)(1)).

• Ensure adequate cooling in the spent fuel pool to maintain stored fuel within acceptable 

temperature limits. The ECW System provides a source of emergency makeup water 

for fuel pool cooling (10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The ECW System contains nonsafety-related fluid-filled lines in 

the Auxiliary Building, which provide structural support or have potential spatial 

interactions with safety-related SSC (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48). The 

ECW System provides cooling to equipment that is credited with maintaining reactor 

level and cooling the reactor and containment for fire safe shutdown 

(10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49). The ECW 

System includes components that are environmentally qualified (10 CFR 54.4(a)(3)).
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• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for SBO (10 CFR 50.63). The ECW 

System provides cooling for equipment that is credited with maintaining reactor water 

injection and for containment heat removal for SBO coping (10 CFR 54.4(a)(3)).

LRA Table 2.3.3-11 identifies the ECW System component types within the scope of license 

renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.11; UFSAR Sections 2.5.5.2.5, 9.2.1, and 9.2.6; and the 

license renewal boundary drawings using the evaluation methodology discussed in SER

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff 

identified an area in which additional information was necessary to complete the review of the 

applicant’s scoping and screening results.

In RAI 2.3.3.11-1, the staff notes that drawings LR-LAS-M-87-3 (E-6) and LR-LAS-M-134-3 

(D-6) show 10 CFR 54.4(a)(1) piping (1DG15D 2 and 2DG15D 2) whose scope changes to 

10 CFR 54.4(a)(2) without a change in piping classification. The NRC requested that the 

applicant provide sufficient information to clarify the change in scoping classification.

In its response letter dated August 26, 2015, the applicant stated that piping components 

downstream of the safety-related valves 1DG039 and 2DG039 are not ASME Code 

components, are not safety related, and do not have a 10 CFR 54.4(a)(1) intended function. 

These piping components have 10 CFR 54.4(a)(2) intended functions to provide structural 

support of attached piping with 10 CFR 54.4(a)(1) intended functions and to provide a leakage 

boundary for nearby components that have 10 CFR 54.4(a)(1) intended functions. The piping 

upstream of these valves are ASME Code Class 3 components and tested to ASME Code 

Section XI requirements.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.2-2 acceptable 

because the applicant clarified the reason for the change in scope from 10 CFR 54.4(a)(1) to 

10 CFR 54.4(a)(2) for piping and components downstream of valves 1DG039 and 2DG039. 

Therefore, the staff’s concern described in RAI 2.3.3.11-1 is resolved.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, RAI response, and license renewal boundary drawings, the staff concludes 

that the applicant appropriately identified the ECW System mechanical components within the 

scope of license renewal as required by 10 CFR 54.4(a). The staff also concludes that the 

applicant adequately identified the system components subject to an AMR in accordance with 

the requirements in 10 CFR 54.21(a)(1).

2.3.3.12 Fire Protection System

Summary of Technical Information in the Application

LRA Section 2.3.3.12 states that the purpose of the Fire Protection System is to prevent fires 

from starting, quickly detect any fires, quickly suppress fires in hazard areas, prevent the spread 

of a fire by use of barriers, and provide firefighting capability for manual fire extinguishment. 
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The Fire Protection System is common to both Units 1 and 2 and is designed to provide 

detection and suppression of a fire at the plant. The Fire Protection System is 

nonsafety-related, but it provides detection and suppression equipment and design features that 

support the safe shutdown of the plant. The Fire Protection System includes water, carbon 

dioxide (CO2), and halon fire suppression systems. It also includes active and passive features, 

such as fire doors, dampers, penetration seals, fire wraps, fire barrier walls and slabs, and 

flammable fluid retention curbs and walls to prevent the spread of a fire.

The fire water system provides cooling lake water to the plant fire hydrants, the water sprinkler 

systems, spray systems, deluge systems, and the hose valve stations. The system is normally 

kept pressurized by two fire protection jockey pumps. If a system demand occurs, the motor 

driven intermediate fire pump is automatically activated. If the system demand exceeds the 

capacity of this pump, the pressure decreases in the fire water system, thereby automatically 

starting a diesel-driven fire pump. If demand is in excess of the capability of a single diesel fire 

pump or if there is a pump failure, the second diesel driven fire pump is started automatically. 

If these pumps are unavailable, the plant Nonessential Cooling Water System service water 

system pumps may be used as a backup to provide the system demand. The fire pumps take 

suction from the service water tunnel in the Lake Screen House and supply water to the yard 

ring header. The fire hydrant system is supplied by separate header connections to each of the 

two diesel driven fire pumps. The yard loop is sectionalized, thus permitting independence of 

each unit if desired. Fire protection water is distributed to the hydrants, hose stations, and water 

suppression systems in the plant from the yard fire main loop, which encircles the power block.

Multiple headers from the outside fire loop are brought into the building complex to feed the 

standpipes, hose stations and sprinkler, spray and deluge water systems. Wet standpipes for 

hose stations are located throughout the plant to allow use of fire hoses to support local fire 

brigade activity. Wet pipe sprinkler operation is initiated automatically when ambient 

temperature exceeds the melting point of the fusible links of the sealed sprinklers, causing the 

spray heads to open. Preaction sprinkler system operation is actuated by area fire detectors 

that open deluge valves supplying fusible element sprinkler heads, which melt when local 

ambient temperatures rise due to a fire. System actuation transmits alarm signals to the main 

control room.

An automatic CO2 flooding extended discharge system is provided for each of the five diesel 

generator rooms. Each system is activated by a fixed temperature rise detector system and 

may also be manually activated. The CO2 systems consist of a common refrigerated storage 

unit and associated piping, headers, and valves to the five diesel generator rooms. Hose reels 

are also provided for manually fighting fires. Audible and visual predischarge alarms warn that 

the CO2 flooding system is about to actuate so that personnel may leave the area. Actuation of 

the CO2 flooding system automatically shuts down the local fans and closes the local dampers 

in the ventilation system. The CO2 storage unit also provides CO2 for fire suppression in the 

main generator Alterrex housings and purge gas for the main generators.

Halon fire suppression systems are used in the plant computer room in the south service 

building, in quality assurance archives in the north service building, and in the records storage 

building. Audible and visual predischarge alarms warn that the halon system is about to actuate 

so that personnel may leave the area. Actuation of the halon system automatically shuts down 

the local fans and closes the local dampers in the ventilation system.

The Fire Protection System includes features to isolate safety-related systems from 

unacceptable fire hazards. Barriers, such as walls, floors, ceilings, fire doors, fire dampers, 
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cable and piping penetration seals, and ventilation seals, are used to isolate the safety-related 

systems. In addition, curbs and walls are provided to minimize the spread of flammable fluids in 

the event of a spill.

The Fire Protection System license renewal boundary begins in the Lake Screen House, where 

the fire pumps take suction from the service water tunnel and supply water to the fire main ring 

header and yard fire hydrants, and extends into the building fire distribution piping for hose 

station standpipes, water spray subsystems, water sprinkler subsystems, and water deluge 

subsystems throughout the plant. Included is the interface with the Nonessential Cooling Water

System that provides a source of fire water in the event the fire water pumps are not available. 

The CO2 fire suppression subsystem begins at the CO2 storage unit and extends via distribution 

piping to each of the five diesel generator rooms and hose reels.

The intended functions of the Fire Protection System within the scope of license renewal include 

the following:

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The Fire Protection System includes nonsafety-related SSCs 

with the potential for spatial and structural interaction with safety-related equipment in 

the Reactor Buildings, Auxiliary Building, Turbine Buildings, Diesel Generator Buildings, 

and Offgas Building (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48). The 

Fire Protection System provides the capability to control postulated fires in plant areas to 

maintain safe shutdown ability (10 CFR 54.4(a)(3)).

LRA Table 2.3.3-12 identifies the Fire Protection System component types that are within the 

scope of license renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.12 and the relevant LRA drawings using the evaluation 

methodology described in the SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff also reviewed UFSAR Section 9.5.1, “Fire Protection System,” and the FPR, which 

describe the fire protection program at LSCS and explain how it complies with the requirements 

of 10 CFR 50.48, “Fire Protection,” and the guidelines of Branch Technical Position (BTP) 

Auxiliary Systems Branch (ASB) 9.5-1.

The staff also reviewed the following fire protection documents cited in the CLB listed in the 

LSCS, Units 1 and 2, Operating License Conditions 2.C(25) and 2.C(15), respectively:

• NUREG-0519, “Safety Evaluation Report Related to the Operation of LaSalle County 

Station, Units 1 and 2,” dated March 1981

• NUREG-0519, Supplement 2, “Safety Evaluation Report Related to the Operation of 

LaSalle County Station, Units 1 and 2,” dated February 1982

• NUREG-0519, Supplement 3, “Safety Evaluation Report Related to the Operation of 

LaSalle County Station, Units 1 and 2,” dated April 1982
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• NUREG-0519, Supplement 5, “Safety Evaluation Report Related to the Operation of 

LaSalle County Station, Units 1 and 2,” dated August 1983

• NUREG-0519, Supplement 7, “Safety Evaluation Report Related to the Operation of 

LaSalle County Station, Units 1 and 2,” dated December 1983

• NUREG-0519, Supplement 8, “Safety Evaluation Report Related to the Operation of 

LaSalle County Station, Units 1 and 2,” dated March 1984

• LaSalle Unit 1 License Amendment 1, dated June 18, 1982

• LaSalle Unit 1 License Amendment 18, dated August 8, 1984

• LaSalle Unit 1 License Amendment 23, dated May 22, 1985

• LaSalle Unit 1 License Amendment 44, dated June 20, 1986

• LaSalle Unit 1 License Amendment 127, dated June 10, 1998

• LaSalle Unit 2 License Amendment 11, dated May 22, 1985

• LaSalle Unit 2 License Amendment 14, dated October 2, 1985

• LaSalle Unit 2 License Amendment 112, dated June 10, 1998

• “NRC Evaluation of the Consequences of Postulated Failures of 1 Hour Fire Rated 

Darmatt KM-1 Fire Barrier under Seismic Loading at LaSalle County Station, Units 1 

and 2,” dated March 29, 1996

During its review, the staff evaluated the system functions described in the LRA and UFSAR

Section 9.5.1 to verify that the applicant had not omitted from the scope of license renewal any 

components with intended functions pursuant to 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as within the scope of license renewal to verify that the 

applicant had not omitted any passive or long-lived components subject to an AMR in 

accordance with 10 CFR 54.21(a)(1).

During its review of LRA Section 2.3.3.12, the staff identified areas in which additional 

information was necessary to complete its review of the applicant’s scoping and screening 

results. The applicant responded to the staff’s RAIs as discussed below.

In RAI 2.3.3.12-1 of its letter dated June 8, 2015, the staff noted that LRA boundary drawing 

LR-LAS-M-78, Sheet 1, shows flame arrestors at location E4 and E5 and CO2 fire suppression 

system components at locations C4 and C5 as out of scope (i.e., not colored in green). 

The staff requested that the applicant verify whether the above fire protection systems and 

components are in the scope of license renewal in accordance with 10 CFR 54.4(a) and 

whether they are subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are 

excluded from the scope of license renewal and are not subject to an AMR, the staff requested 

that the applicant provide justification for the exclusion.

In a letter dated July 1, 2015, the applicant responded to RAI 2.3.3.12-1 by stating the following:

The flame arrestors, shown in the center of boundary drawing LR-LAS-M-78, 

Sheet 1 (E4 and E5), are part of the plant hydrogen system supporting the main 

generator. The flame arrestors are provided in the plant hydrogen system vent to 

the turbine building roof. The plant hydrogen system is part of the license 

renewal Main Generator and Auxiliaries System. The Main Generator and 
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Auxiliaries System and its components do not perform license renewal intended 

functions and are not included in the scope of license renewal. The flame 

arrestors are not in scope for 10 CFR 54.4(a)(3) license renewal since they are 

not required to meet the regulations for fire protection. The flame arrestors in the 

plant hydrogen system vent do not perform a license renewal intended function. 

Therefore, the flame arrestors are not within the scope of license renewal and 

are not subject to an AMR.

The carbon dioxide components associated with carbon dioxide vaporizer shown 

on boundary drawing LR-LAS-M-78, Sheet 1 (C4 and C5) support the main 

turbine generators with a supply of carbon dioxide (CO2) in a high flow gaseous 

state. The purge gas portion of the plant carbon dioxide system, which is part of 

the license renewal Fire Protection System, is not in scope. The CO2 is used to 

purge the hydrogen from the generator prior to filling with air in support of 

performing maintenance. Additionally, the CO2 is used to purge the air prior to 

filling with hydrogen when returning the generator to service. The CO2 purges 

prevent a combustible mixture of hydrogen and oxygen at the start and 

completion of routine maintenance. These CO2 components are not in scope for 

10 CFR 54.4(a)(3) license renewal since they are not required to meet the 

regulations for fire protection. CO2 purges for hydrogen and for air in support of 

maintenance are not a license renewal intended function. Therefore, the CO2

components in support of the turbine generator hydrogen subsystem are not 

within the scope of license renewal and are not subject to AMR.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.12-1 acceptable. The 

applicant clarified that the flame arrestors in drawing LR-LAS-M-78, Sheet 1, locations E4 and 

E5, are part of the plant hydrogen venting system for the main turbine generator and auxiliaries 

system and that they perform no license renewal intended function for 10 CFR 54.4(a)(3) and 

are not required for compliance with 10 CFR 50.48. Therefore, they are not within the scope of 

license renewal and subject to an AMR. The flame arrestors in question were correctly 

excluded from the scope of license renewal and are not subject to an AMR because they are 

not fire protection SSCs. Therefore, the staff’s concern described in RAI 2.3.3.12-1 is resolved. 

The staff noted that flame arrestors in drawing LR-LAS-M-85, Sheet 1, locations E5 and E7 

(diesel generator day tanks and diesel fuel storage tanks), are highlighted in green. These 

flame arrestors are included in LRA scoping Table 2.3.3-8 with AMR results in LRA 

Table 3.3.2-8.

Based on its review, the staff finds the applicant response to RAI 2.3.3.12-1 acceptable because 

the applicant clarified that the CO2 system components at locations C4 and C5 in drawing 

LR-LAS-M-78, Sheet 1, support the main turbine generators and are used to purge the 

hydrogen from the generator before filling with air in support of performing maintenance and that 

they have no license renewal intended function for 10 CFR 54.4(a)(3) and are not required for 

compliance with 10 CFR 50.48. Therefore, they are not within the scope of license renewal and 

subject to an AMR. The CO2 system components at locations C4 and C5 in drawing 

LR-LAS-M-78, Sheet 1, in question were correctly excluded from the scope of license renewal 

and are not subject to an AMR because these are not fire protection SSCs, although the CO2

system components in question share a common CO2 supply tank with the plant CO2 fire 

suppression system. Therefore, the staff’s concern described in RAI 2.3.3.12-1 is resolved.

In RAI 2.3.3.12-2 of its letter dated June 8, 2015, the staff stated that the LRA Tables 2.3.3-12 

and 3.3.2-12 do not include the following fire protection components:
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• standpipe risers

• fire suppression system filter housings

• smoke and heat vent housings

• fire barrier coatings and wraps

The staff requested that the applicant verify whether the fire protection components listed above 

are in the scope of license renewal in accordance with 10 CFR 54.4(a) and whether they are 

subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope 

of license renewal and are not subject to an AMR, the staff requested that the applicant provide 

justification for the exclusion.

In a letter dated July 1, 2015, the applicant responded to RAI 2.3.3.12-2 by stating the following:

Standpipe Risers – Standpipe risers are within the scope of license renewal and 

are subject to an AMR. Standpipe risers are included in LRA Table 3.3.2–12 as 

carbon steel piping, piping components, and piping elements with a pressure 

boundary intended function.

Fire Suppression System Filter Housings – Fire suppression filter housings are 

within the scope of license renewal and are subject to an AMR. They are 

included in LRA Table 3.3.2-12 as carbon steel piping, piping components, and 

piping elements with a pressure boundary intended function.

Smoke and Heat Vent Housings – Smoke and heat vent housings are located in 

the LSCS Turbine Building roof. These smoke and heat vent housings are not 

relied upon in safety analyses or plant evaluations to perform a function that 

demonstrates compliance with the Commission’s regulations for Fire Protection, 

specifically considering the regulations applicable to LSCS’s current licensing 

basis: 10 CFR 50.48, Branch Technical Position (BTP) ASB 9.5-1, Appendix R 

to Part 50 – Fire Protection Program for Nuclear Power Facilities, and the 

associated Safety Evaluation Report for LSCS Fire Protection. The BTP 

discusses smoke and heat vents in support of manual fire fighting for some 

areas, such as cable spreading rooms, diesel fuel oil storage areas, and 

switchgear rooms. It does not discuss the Turbine Building smoke and heat 

vents in this regard. The Turbine Building roof smoke and heat vent housings 

are discussed in the UFSAR and Fire Protection Report. There is no connection 

between the BTP manual fire fighting support statement and the Turbine Building 

roof vent housing discussions. The UFSAR and Fire Protection report 

information is provided for completeness of the area description and does not 

imply that the vent housings are required or credited for implementation of 

regulatory requirements. The smoke and heat vent housings are not 

safety-related nor relied upon to remain functional during design basis events, 

and the failure of these nonsafety-related components would not prevent the 

accomplishment of safety-related functions. The smoke and heat vent housings 

are not relied upon to demonstrate compliance with the Commission’s 

regulations for Environmental Qualification, Anticipated Transient Without Scram, 

or Station Blackout. Therefore, the smoke and heat vent housings do not 

perform a license renewal intended function. They are not in scope for license 

renewal and therefore are not subject to AMR.
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Fire Barrier Coatings and Wraps – Fire barrier coatings and wraps are within the 

scope of license renewal and are subject to an AMR. They are included in LRA 

Table 3.3.2–12 as aluminum silicate, ceramic fiber, and pyrocrete Fire Barriers 

(For Steel Components) with a fire barrier intended function.

In reviewing the applicant’s response to the RAI, the staff finds that the applicant has addressed 

and resolved each item in the RAI, as discussed in the following paragraphs.

Although the description of the “standpipe raisers” and “fire suppression system filter housings”

items in LRA Table 2.3.3-12 does not list these components specifically, the applicant stated 

that it considers these items to be included with the “carbon steel piping, piping components, 

and piping elements” in LRA AMR Table 3.3.2-12 with a pressure boundary intended function.

The applicant stated that the Turbine Building smoke and heat vents do not have fire protection

intended functions required for compliance with 10 CFR 50.48. Additionally, the applicant 

stated that the Turbine Building smoke and heat vents are not relied on in safety analyses or 

plant evaluations to perform a function that demonstrates compliance with the Commission’s 

regulations for fire protection, specifically considering the regulations applicable to the LSCS’s 

CLB. The licensee concluded that the smoke and heat vent housings are not within the scope 

of license renewal and are not subject to an AMR.

The staff finds the applicant’s response contrary to the UFSAR and Revision 6 to the FPR, 

which include the original LSCS fire protection program as the CLB. FPR Section H.3.5.3, 

“Turbine Operating Floor and Heater Bay – Fire Zone 5A3,” subsection entitled, “Description,”

states, in part:

Fusible link type heat and smoke vents are provided on the turbine building roof. 

The criteria for sizing these vents is a vent ratio of one to one hundred for the 

combined floor area of the main turbine floor and the heater bay. Motorized 

outside doors are provided for intake air for heat and smoke venting.

FPR Section H.3.5.3, subsection entitled, “Safety-Related Equipment,” states that “[t]his zone 

contains safety related HVAC monitoring instrumentation.”

Additionally, FPR Section H.3.5.3, subsection entitled, “Design-Basis Fire,” states:

The design-basis fire would be contained within the turbine building. It is 

possible for oil, in the unlikely event of a line rupture, to leak down to the zone 

below; however, that zone is completely protected by automatic sprinklers. The 

automatic sprinklers are designed to extinguish an oil fire and the automatic 

smoke and heat vents would prevent heat from building up and causing any 

flashover.

Fire Zone 5A3 contains safety-related heating, ventilation, and air conditioning (HVAC)

monitoring instrumentation and equipment, and the fire protection system consists of the 

automatic sprinkler system and automatic smoke and heat vents noted above. According to the 

LSCS’s FPR, following an oil fire in Fire Zone 5A3, automatic smoke and heat vents would 

prevent heat from building up and causing any flashover. Based on the LSCS CLB, Turbine 

Building smoke and heat vents were credited to meet the guidance of BTP ASB 9.5-1. The 

Turbine Building automatic smoke and heat vent housings should not be excluded from the 

scope of license renewal on the basis that they are not required to function during a fire or that 
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they are not required for compliance to 10 CFR 50.48, without factoring in the CLB. Further, the 

staff stated that the Turbine Building smoke and heat vent housings in question must be 

managed during the period of extended operation to comply with 10 CFR 50.48 (in accordance 

with the CLB) as stated in 10 CFR 54.4(a)(3).

In RAI 2.3.3.12-2a of its letter dated August 27, 2015, the staff requested that the applicant 

provide information to demonstrate that the effects of aging will be adequately managed so that 

the intended function(s) will be maintained consistent with the CLB for the period of extended 

operation as required by 10 CFR 54.21(a)(3).

In a letter dated September 17, 2015, the applicant responded to RAI 2.3.3.12-2a by stating the 

following:

The Turbine Building smoke and heat vents are added to the scope of license 

renewal. They are active components, and are not subject to aging management 

review. The Turbine Building smoke and heat vent housings are passive 

components, and are added to the scope of the Structures Monitoring (B.2.1.34) 

aging management program to specifically identify these components. The 

program is enhanced to include the smoke and vent housings in the program 

scope. These components will be inspected for loss of material.

LRA Sections 2.3.3.12 and 2.4.13, LRA Table 2.4-13, LRA Table 3.5.2-13, LRA 

Appendix A, Section A.2.1.34, and LRA Appendix B, Section B.2.1.34 are revised 

as shown in Enclosure B to include aging management of these components. 

LRA Table A.5, Commitment 34 is revised as shown in Enclosure C to reflect this 

change.

Based on its review, the staff finds the applicant response to RAI 2.3.3.12-2a acceptable 

because the applicant clarified that the Turbine Building heat vents are within the scope of 

license renewal and are subject to an AMR (only housings). The staff confirmed that the 

Turbine Building heat vent housings are included in LRA Table 2.4-13 as subject to an AMR in 

LRA Table 3.5.2-13. The staff’s concern described in RAI 2.3.3.12-2a is resolved.

The fire barriers coatings and wraps are included in LRA AMR Table 3.3.2-12 under the 

component type aluminum silicate, ceramic fiber, and pyrocrete fire barriers for steel 

components with a fire barrier intended function.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.12-2 acceptable 

because the applicant provided clarification that the fire protection system and components 

listed above are within the scope of license renewal and are subject to an AMR as required by 

10 CFR 54.4(a) and 54.21(a)(1), respectively. The staff’s concern described in RAI 2.3.3.12-2 

is resolved.

In RAI 2.3.3.12-3 of its letter dated June 8, 2015, the staff stated that LRA Section 2.3.3.16 and 

Table 2.3.3-16, “Components Subject to Aging Management Review,” of the LRA does not 

include fire water and oil floor drains as a component type subject to an AMR. The staff 

requested that the applicant verify whether the fire water floor drains and Diesel Generator 

Building oil floor drains are subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they 

are not subject to an AMR, the staff requests that the applicant provide justification for the 

exclusion.
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In a letter dated July 1, 2015, the applicant responded to RAI 2.3.3.12-3 by stating the following:

Fire water floor drains in the Auxiliary Building, Diesel Generator Building, and 

Turbine Building, and oil floor drains in the Diesel Generator Building are 

included in the scope of license renewal and are subject to an AMR. The drains 

are included in LRA Table 3.3.2–16 as carbon steel piping, piping components, 

and piping elements with a pressure boundary intended function. The internal 

environment is waste water which is defined, in part, in NUREG–1801 Table IX.D 

as water collected in floor drains that may contain contaminants including oil.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.12-3 acceptable 

because the applicant clarified that the water floor drains in the Auxiliary Building, Diesel 

Generator Building, and Turbine Building and that the oil floor drains in the Diesel Generator 

Building are included in the scope of license renewal and are subject to an AMR under item

carbon steel piping, piping components, and piping elements in LRA AMR Table 3.3.2-16. 

The staff confirmed that the water and oil floor drains are included in LRA Table 3.3.2-16, “Plant 

Drainage System,” under the component type “carbon steel piping, piping components, and 

piping elements.” Note that the water and oil floor drains are included in LRA Table 3.3.2-16, as 

“carbon steel piping, piping components, and piping elements,” with an indoor waste water 

environment. The GALL Report defines the term “waste water” as “[r]adioactive, potentially 

radioactive, or non-radioactive waters that are collected from equipment and floor drains. 

Waste water may contain contaminants, including oil and boric acid, depending on location, as 

well as originally treated water that is not monitored by a chemistry program.” Therefore, the 

staff’s concern described in RAI 2.3.3.12-3 is resolved.

LRA Section 2.3.3.12 includes physical plant design features that consist of fire barrier walls 

and slabs, fire barrier penetration seals, fire doors and dampers, fire wraps, and flammable fluid 

retention curbs and walls in the system evaluation boundary. This includes fire dampers in the 

Reactor Buildings, Turbine Buildings, Auxiliary Building, Lake Screen House, Radwaste 

Building, and Diesel Generator Buildings. Further, LRA Section 2.3.3.12 states that fire damper 

housings are subject to an AMR and that the fire barrier function of all fire damper housings is 

evaluated with the Fire Protection System for license renewal AMR. The pressure boundary 

function of the fire damper housings, if applicable, is evaluated with the appropriate ventilation 

system. Furthermore, LRA Section 2.3.3.12 states that the dampers are active components and 

are not subject to an AMR. The Fire Protection System includes fire-rated doors in the Reactor 

Buildings, Turbine Buildings, Auxiliary Building, and Diesel Generator Buildings. Air supervised 

pre-action sprinkler systems are provided with individual air compressors to maintain air 

pressure.

LRA Section 2.3.3.12 states that the diesel engine for the diesel driven fire pumps contains 

active components and is, therefore, not subject to an AMR. The staff confirmed that the diesel 

engine for diesel-driven fire pumps does not meet the AMR criteria of 10 CFR 54.21(a)(1)(i). 

SRP-LR Table 2.1-5, “Typical Structures, Components, and Commodity Groups, and 

10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment,” provides a list of typical 

SCs and identifies whether they meet 10 CFR 54.21(a)(1)(i). Table 2.1-5 indicates that fire 

pump diesel engines are not subject to an AMR.

LRA Section 2.3.3.12 indicates that the fuel oil supply piping and diesel fuel fire pump day tank 

for the fire pump diesel engines are evaluated in LRA Section 2.3.3.8, “Diesel Generator and 

Auxiliaries System.” The staff confirmed that the diesel fuel fire pump day tank for the fire pump 

diesel engines is included in LRA Table 2.3.3-8.
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LRA Section 2.3.3.12 indicates that LRA Section 2.3.3.14, “Nonessential Cooling Water 

System,” included traveling water screens within the scope of license renewal and subject to an 

AMR. The staff confirmed that the traveling water screens are included in LRA Table 2.3.3-14 

as subject to an AMR in LRA Section 3.3.2-19.

LRA Section 2.3.3.12 indicates that the halon fire suppression system that services the 

computer room in the south service building and the records storage areas in the north service 

building and records storage building is not subject to an AMR. Further, LRA Section 2.3.3.12 

states that these areas do not contain any safety-related equipment and that the halon systems 

do not perform or support an intended function in accordance with 10 CFR 54.4(a)(3). The staff 

confirmed that the halon fire suppression system and components do not meet the license 

renewal intended function in accordance with 10 CFR 54.4(a)(3). Further, LRA Section 2.3.3.15 

indicates that CO2 supply piping to the main generator Alterrex housings and purge gas for the 

main generators provides for asset protection and does not perform or support an intended 

function in accordance with 10 CFR 54.4(a)(3); therefore, it need not be included in the scope of 

license renewal.

LRA Section 2.4.5, “Lake Screen House,” includes the service water tunnel structure where fire 

pumps take suction and supply water to the yard ring header. LRA Section 2.4.5 states that the 

Lake Screen House meets the scoping criteria of 10 CFR 54.4, “Scope.” The purpose of the 

Lake Screen House is to provide structural support, shelter, protection, and access to 

submerged CSCS pond water for Seismic Category I safety-related concrete structural 

components and mechanical components under postulated environmental and DBA loading 

conditions. The Lake Screen House also provides a water-retaining boundary for the Cooling 

Lake. The Lake Screen House also provides structural support, shelter, protection, and access 

to Cooling Lake water for non-Seismic Category I plant equipment and components, including 

fire protection pumps and associated piping, valves, and related equipment. The Lake Screen 

House is within the scope of license renewal and is subject to an AMR. The staff confirmed that 

the Lake Screen House structural components subject to an AMR are included in LRA

Table 2.4-5 with AMR results in LRA Table 3.5.2-5.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR Section 9.5.1, “Fire Protection System,” and license renewal boundary 

drawings, the staff concludes that the applicant has appropriately identified the fire protection 

system components within the scope of license renewal as required by 10 CFR 54.4(a). The 

staff also concludes that the applicant has adequately identified the system components subject 

to an AMR in accordance with the requirements in 10 CFR 54.21(a)(1).

2.3.3.13 Fuel Pool Cooling and Storage System

Summary of Technical Information in the Application

LRA Section 2.3.3.13 states that the purpose of the Fuel Pool Cooling and Storage System is to 

maintain the fuel stored in the spent fuel pools and new fuel storage vault in a safe subcritical 

configuration by removing decay heat from spent fuel assemblies stored in the spent fuel pools, 

maintaining fuel pool water temperature and level within required limits, purifying water in the 

spent fuel pools, and minimizing contamination and radiation exposure from fission and 

corrosion product buildup in the spent fuel pool water. The Fuel Pool Cooling and Storage 
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System also supports filling and draining of the reactor wells and dryer/separator pits in support 

of refueling operations.

The Fuel Pool Cooling and Storage System is a normally operating system designed to provide 

an environment to safely and temporarily store new and used nuclear fuel and consumable 

reactor internal components including control rods and nuclear instrumentation. The Fuel Pool 

Cooling and Storage System includes the spent fuel storage racks, defective fuel storage racks, 

control rod blade storage racks within the spent fuel storage pools, and new fuel storage racks. 

The Fuel Pool Cooling and Storage System also includes skimmer surge tanks; heat 

exchangers; pumps; water purifying loops; discharge diffusers within the fuel pools; and 

associated valves, piping components, and instrumentation. The Fuel Pool Cooling and 

Storage System is in scope for license renewal. However, portions of the system are not 

required to perform intended functions and are not in scope.

The intended functions of the Fuel Pool Cooling and Storage System within the scope of license 

renewal include the following:

• Ensure adequate cooling in the spent fuel pool to maintain stored fuel within acceptable 

temperature limits. The Fuel Pool Cooling and Storage System includes safety-related 

equipment to circulate and cool the fuel pool water inventory and maintain adequate 

water inventory (10 CFR 54.4(a)(1)).

• Prevent criticality of fuel assemblies stored in the spent fuel pool. The spent fuel storage 

racks maintain new and spent nuclear fuel in a subcritical configuration, with at least a 

5-percent subcriticality margin (10 CFR 54.4(a)(1)).

• Provide protection for safe storage of new and spent fuel. The spent fuel storage racks 

provide physical support, shelter, and protection for new and spent nuclear fuel 

(10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The system includes nonsafety-related piping that has the 

potential to spatially and structurally interact with safety-related components located in 

the Reactor Building and Auxiliary Building (10 CFR 54.4(a)(2)).

LRA Table 2.3.3-13 identifies the Fuel Pool Cooling and Storage System component types 

within the scope of license renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.13, UFSAR Sections 7.7.12 and 9.1, and the license 

renewal boundary drawings using the evaluation methodology discussed in SER Section 2.3 

and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff identified an area 

in which additional information was necessary to complete the review of the applicant‘s scoping 

and screening results.

In RAI 2.3.3.13-1, the staff notes that Unit 1 drawing LR-LAS-M-98-1 shows 10 CFR 54.4(a)(1) 

piping whose scope changed to 10 CFR 54.4(a)(2) without a change in piping classification at 

the following locations in the table below:

LR-LAS-M-98, Sheet-1, Location Piping ID

Location C-2 1FC87A upstream of valve 1FC130
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LR-LAS-M-98, Sheet-1, Location Piping ID

Location C-5 1FC19AA downstream of valve 1FC118

Location C-8 1FC110A upstream of valve 1FC141

Location B-8 1FC01DA downstream of valve 1FC139A

Location A-8 1FC01DB downstream of valve 1FC139B

Similarly for Unit 2, drawing LR-LAS-M-144, Sheet-1, shows 10 CFR 54.4(a)(1) piping whose 

scope changed to 10 CFR 54.4(a)(2) without a change in piping classification at the following 

locations in the table below:

LR-LAS-M-144, Sheet-1, Location Piping ID

Location C-1 2FC11DA upstream of valve 2FC141

Location B-1 2FC01DA downstream of valve 2FC139A

Location B-1 2FC01DB downstream of valve 2FC139B

Location C-4 2FC19AA downstream of valve 2FC118

Location C-7 2FC87A upstream of valve 2FC130

The NRC requested that the applicant provide sufficient information to clarify the change in 

scoping classification.

In its response letter dated August 26, 2015, the applicant stated that these piping sections are 

properly scoped as being in scope for 10 CFR 54.4(a)(2) intended functions to provide structural 

support for attached piping and to provide a leakage boundary for nearby components that have 

10 CFR 54.4(a)(1) intended functions. These piping sections are classified within the LSCS 

current design basis as nonsafety-related and they do not have 10 CFR 54.4(a)(1) intended 

functions.

The applicant referred to the LSCS System Safety Boundary Document for the Fuel Pool 

Cooling Filter and Demineralizer (FC) System, which states that the normal fuel pool cooling 

loops are not safety related, are designed as a non-seismic and electrical non-1E system, but 

are designed and procured to ASME Code Section III standards. UFSAR Table 3.2-1, Sheet 8, 

Section XX, “Fuel Pool Cooling and Cleanup System,” and associated notes 4a, 4b, 5, and 18 

provide design bases information that is consistent with the information discussed in the System 

Safety Boundary Document for the Fuel Pool Cooling Filter and Demineralizer (FC) System.

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.13-1 acceptable 

because the applicant provided clarification for the scoping changes. The design and licensing 

basis information cited by the applicant provides the basis for the scoping classification changes 

from 10 CFR 54.4(a)(1) to 10 CFR 54.4(a)(2). Therefore, the staff’s concern described in 

RAI 2.3.3.13-1 is resolved.

The staff noted that Unit 1 drawing LR-LAS-M-98-1 (C-7) shows a 10 CFR 54.4(a)(2) 

line 1FC11DC 10 downstream of a 10 CFR 54.4(a)(1) valve 1FC086 whose scope changed to 

10 CFR 54.4(a)(2), whereas the piping classification changed to “Class C,” indicating 

safety-related piping.

Unit 2 drawing LR-LAS-M-144-1 (C-2) shows a 10 CFR 54.4(a)(2) line 2FC11DC 10 

downstream of a 10 CFR 54.4(a)(1) valve 2FC086 whose scope changed to 10 CFR 54.4(a)(2), 

whereas the piping classification changed to “Class C,” indicating safety-related piping.
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The applicant was requested, through RAI 2.3.3.13-2, to provide sufficient information to clarify 

the change in scoping classifications.

In its response letter dated August 26, 2015, the applicant stated that these piping sections are 

properly scoped as being in scope for a 10 CFR 54.4(a)(2) intended functions to provide 

structural support for attached piping and to provide a leakage boundary for nearby components 

that have 10 CFR 54.4(a)(1) intended functions. These piping sections are classified within the 

LSCS current design basis as nonsafety-related and do not have 10 CFR 54.4(a)(1) intended 

functions.

The applicant referred to the LSCS System Safety Boundary Document for the Fuel Pool 

Cooling Filter and Demineralizer (FC) System, which states that the normal fuel pool cooling 

loops are not safety-related, are designed as a nonseismic and electrical non-1E system, but 

are designed and procured to ASME Code Section III standards. These classifications for this 

piping are consistent with UFSAR Table 3.2-1, Sheet 8, Section XX, and associated notes 4a, 

4b, 5, and 18.

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.13-2 acceptable 

because the applicant clarified the scoping changes. The design and licensing basis 

information cited by the applicant provides the basis for the license renewal scoping 

classification changes from 10 CFR 54.4(a)(1) to 10 CFR 54.4(a)(2). Therefore, the staff’s 

concern described in RAI 2.3.3.13-2 is resolved.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, RAI responses, and license renewal boundary drawings, the staff concludes 

that the applicant appropriately identified the Fuel Pool Cooling and Storage System mechanical 

components within the scope of license renewal as required by 10 CFR 54.4(a). The staff also 

concludes that the applicant adequately identified the system components subject to an AMR in 

accordance with the requirements in 10 CFR 54.21(a)(1).

2.3.3.14 Nonessential Cooling Water System

Summary of Technical Information in the Application

The Nonessential Cooling Water System consists of the circulating water, service water, screen 

wash, chemical feed, gland water, and lake makeup and blowdown systems.

LRA Section 2.3.3.14 states that the purpose of the Nonessential Cooling Water System is to 

provide cooling water to the main condensers and other plant heat exchangers. The 

Nonessential Cooling Water System is in scope for license renewal. However, portions of the 

Nonessential Cooling Water System are not required to perform intended functions and are not 

included in the scope of license renewal. The Nonessential Cooling Water System is a normally 

operating system.

LRA Section 2.3.3.14 states that the purposes of Nonessential Cooling Water plant systems are 

as follows:

• The purpose of the circulating water system is to provide the condensers with a 

continuous supply of cooling water.
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• The purpose of the service water system is to supply cooling water for the 

turbine-generator and miscellaneous HVAC loads, fuel pool cooling, and the heat 

exchangers in the TBCCW and RBCCW systems.

• The purpose of the screen wash system is to provide water to wash and remove debris 

from the traveling screens in the Lake Screen House.

• The purpose of the chemical feed system is to minimize the macroscopic biological 

fouling and microbiologically-influenced corrosion in plant systems.

• The purpose of the gland water system is to provide cooling water to plant equipment.

• The purpose of the lake makeup and blowdown system is to maintain an acceptable 

water level in the Cooling Lake, control dissolved solids in the Cooling Lake water, and 

dilute and discharge low-level radioactive wastes.

The intended functions of the Nonessential Cooling Water System within the scope of license 

renewal include the following:

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The system contains nonsafety-related fluid-filled lines in the 

Reactor Building, Turbine Building, and Auxiliary Building that have the potential for 

spatial interactions with safety-related SSCs (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48). The 

system provides a source of fire water and provides a credited backup in the event that

the diesel fire pumps are unavailable (10 CFR 54.4(a)(3)).

LRA Table 2.3.3-14 identifies the Nonessential Cooling Water System component types within 

the scope of license renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.14; UFSAR Sections 9.2.2, 9.2.12, and 10.4.5; and the 

license renewal boundary drawings using the evaluation methodology discussed in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Nonessential Cooling Water System components within the scope of 

license renewal as required by 10 CFR 54.4(a). The staff also concludes that the applicant 

adequately identified the system components subject to an AMR in accordance with the 

requirements in 10 CFR 54.21(a)(1).

2.3.3.15 Nonsafety-Related Ventilation System

Summary of Technical Information in the Application

LRA Section 2.3.3.15 states that the purpose of the Nonsafety-Related Ventilation (NSV) 

System is a normally operating system designed to maintain a favorable environment for plant 
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equipment and personnel while preventing the spread of contamination in the plant. The NSV 

System consists of various ventilation plant systems and the station heat recovery plant system.

The NSV System provides ventilation to the following plant areas:

• Auxiliary Building equipment areas

• Auxiliary Building laboratory

• Lake Screen House

• machine shop

• Offgas Building

• Radwaste Building

• Service Building

• Service Building storeroom

• interim radwaste storage facility

• River Screen House

• QA records vault

• 345-kV relay house

The NSV System also includes the station heating and recovery plant system, which recycles 

heat from ventilation exhaust air to preheat ventilation intake air in the winter time, and provides 

supplemental cooling in the summer time.

The intended function of the NSV System for license renewal is to maintain leakage boundary 

integrity to preclude system interactions. This system is not required to operate to support 

license renewal intended functions and is in scope for potential spatial interaction. In addition, 

the intended function is to resist nonsafety-related SSC failure that could prevent satisfactory 

accomplishment of a safety-related function. The NSV System includes nonsafety-related 

water-filled piping and components located in the Auxiliary Building that have the potential for 

spatial interactions (spray or leakage) with safety-related SSCs (10 CFR 54(a)(2)).

The NSV System is not in scope under 10 CFR 54.4(a)(1) because no portions of the system 

are safety-related or are relied on to remain functional during and following DBEs. The NSV 

System meets 10 CFR 54.4(a)(2) because failure of nonsafety-related portions of the system 

could prevent satisfactory accomplishment of a function(s) identified for 10 CFR 54.4(a)(1). The 

NSV System is not in scope under 10 CFR 54.4(a)(3) because it is not relied on in safety 

analyses or plant evaluations to perform a function that demonstrates compliance with the 

Commission’s regulations for fire protection (10 CFR 50.48), EQ (10 CFR 50.49), ATWS 

(10 CFR 50.62), and SBO (10 CFR 50.63).

The intended function of the NSV System within the scope of license renewal includes the 

following:

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The NSV system includes nonsafety-related water-filled piping 

and components located in the Auxiliary Building that have the potential for spatial 

interactions (spray or leakage) with safety-related SSCs (10 CFR 54.4(a)(2)).

LRA Table 2.3.3-15 identifies the NSV System component types within the scope of license 

renewal and subject to an AMR.
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Staff Evaluation

The staff reviewed LRA Section 2.3.3.15, the UFSAR, and LRA Table 2.3.3-15 using the 

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has not omitted from the scope of license renewal any components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant has identified as being within the scope of license renewal to 

verify that it has not omitted any passive and long-lived components subject to an AMR in 

accordance with the requirements of 10 CFR 54.21(a)(1).

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant 

appropriately identified the NSV System components within the scope of license renewal as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the system components subject to an AMR as required by 10 CFR 54.21(a)(1).

2.3.3.16 Plant Drainage System

Summary of Technical Information in the Application

The Plant Drainage System includes components from the following plant systems:

• equipment and floor drainage systems

• HVAC equipment drain system

• generator vent and drain system

• roof drain system

• wastewater treatment system

• sewage treatment system

LRA Section 2.3.3.16 states that the purpose of the normally operating Plant Drainage System 

is to collect various liquid wastes generated in the operation of the plant. The Plant Drainage 

System is in scope for license renewal. However, portions of the Plant Drainage System are not 

required to perform intended functions and are not in scope.

The purposes of the Plant Drainage System plant systems are as follows:

• The purpose of the equipment and floor drainage system is to collect radioactive,

nonradioactive, and oily liquid wastes generated in the operation of the plant. The 

system collects waste liquids from their points of origin and transfers them for eventual 

processing. Radioactive, nonradioactive, and oily wastes are segregated and processed 

separately.

• The purpose of the HVAC equipment drain system is to prevent water accumulation 

within HVAC ventilation units. The HVAC equipment drain system collects condensate 

from the ventilation unit plenums and drains it for eventual processing. The HVAC 

equipment drain system is not required to operate to support license renewal intended 

functions. Only the exposed, nonembedded portions of the HVAC equipment drain 

system, which have potential spatial interaction with safety-related equipment in the 
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Reactor Building, Auxiliary Building, and Turbine Building, perform a license renewal 

intended function and are in scope for potential spatial interaction.

• The purpose of the generator vent and drain system is to collect equipment leakoff and 

drainage from the main turbine and associated components. The generator vent and 

drain system collects leakoff and drainage and transfers them for eventual processing. 

The generator vent and drain system does not perform a license renewal intended 

function.

• The purpose of the roof drain system is to prevent the accumulation of precipitation on 

plant building roofs. The roof drain system collects roof drainage and discharges it into 

the storm drain system. The roof drain system is not required to operate to support 

license renewal intended functions. Only the exposed, nonembedded portions of the 

roof drain branch lines and headers, which have potential spatial interaction with 

safety-related equipment in the Reactor Building, Auxiliary Building, and Diesel 

Generator Building, perform a license renewal intended function and are in scope for

potential spatial interaction.

• The purpose of the wastewater treatment system is to process the station’s wastewater 

to comply with state and Federal U.S. Environmental Protection Agency guidelines 

regulating the effluent returned to the cooling lake. The wastewater system processes 

plant waste water through oil separators, equalization tanks, flocculator-clarifier tanks, 

and media filters before releasing it through the cooling lake discharge flume. The 

wastewater treatment system does not perform a license renewal intended function.

• The purpose of the sewage treatment system is to collect and process plant sewage to 

meet the effluent quality limits set by the Illinois Environmental Protection Agency. 

The sewage treatment system collects sanitary waste through the sanitary waste drain 

system and transfers the waste to lift stations for processing through primary and 

secondary aerated lagoon cells. The sewage treatment system is not required to 

operate to support license renewal intended functions. Only the exposed, 

nonembedded portions of the sanitary waste drain system, which have potential spatial 

interaction with safety-related equipment in the Auxiliary Building, perform a license 

renewal intended function and are in scope for potential spatial interaction.

The intended functions of the Plant Drainage System within the scope of license renewal 

include the following:

• Provide primary containment boundary. The system includes safety-related primary 

containment isolation valves (10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The nonsafety-related floor drain system in the Reactor Building 

is credited for the mitigation of flooding as a result of a high-energy line break (HELB) or 

a moderate-energy line break. Additionally, the nonsafety-related drywell drain lines that 

are routed through the suppression chamber airspace before exiting the primary 

containment are in scope to ensure their pressure boundary integrity to prevent drywell 

to suppression chamber bypass leakage (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49). The system 

contains components that are environmentally qualified (10 CFR 54.4(a)(3)).
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• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48). The 

floor drain systems in the Auxiliary Building, Diesel Generator Building, and Turbine 

Building are credited for the removal of fire water from areas containing safe shutdown 

equipment. The floor drain system in the Diesel Generator Building is credited to 

prevent the accumulation of oil in areas containing safe shutdown equipment 

(10 CFR 54.4(a)(3)).

LRA Table 2.3.3-16 identifies the Plant Drainage System component types within the scope of 

license renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.16, UFSAR Section 9.3.3, and the license renewal 

boundary drawings using the evaluation methodology discussed in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. On the basis of its review, the staff identified an area in which 

additional information was necessary to complete the review of the applicant’s scoping and 

screening results.

In RAI 2.3.3.16-1, the staff notes on drawing LR-LAS-M-142-1 (A-4) that the staff could not 

locate seismic or equivalent anchors between the safety and nonsafety interface at the F.4.c 

termination symbol (valve 2E12-F070) and the end of the 10 CFR 54.4(a)(2) scoping boundary. 

The NRC requested that the applicant provide additional information to locate the seismic or 

equivalent anchors between the safety and nonsafety interface and the end(s) of the 

10 CFR 54.4(a)(2) scoping boundary.

In its response letter dated August 26, 2015, the applicant provided the location of additional 

equivalent anchors.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.16-1 acceptable 

because the applicant provided the location of additional equivalent anchors to the end of the 

10 CFR 54.4(a)(2) scoping boundary. Therefore, the staff’s concern described in 

RAI 2.3.3.16–1 is resolved.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, RAI response, and license renewal boundary drawings, the staff concludes 

that the applicant appropriately identified the Plant Drainage System mechanical components 

within the scope of license renewal as required by 10 CFR 54.4(a). The staff also concludes 

that the applicant adequately identified the system components subject to an AMR in 

accordance with the requirements in 10 CFR 54.21(a)(1).

2.3.3.17 Primary Containment Ventilation System

Summary of Technical Information in the Application

LRA Section 2.3.3.17 states that the purpose of the Primary Containment Ventilation (PCV) 

System is to maintain a suitable environment inside the drywell for equipment operation and 

longevity. It is a normally operating system designed to limit the maximum average temperature 

of the air to maintain drywell air temperature within equipment operating limits. The PCV 
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System is in scope for license renewal; however, portions of the PCV System are not required 

to perform intended functions and are not in scope. A portion of the PCV System performs a 

safety-related function. The chilled water piping that penetrates primary containment and the 

associated primary containment isolation valves are safety-related components that are relied 

on to provide the primary containment boundary and are also environmentally qualified.

The intended functions of the PCV System within the scope of license renewal include the 

following:

• Provide primary containment boundary. The PCV System contains safety-related 

primary containment isolation valves in the chilled water piping to and from the drywell 

(10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The PCV System includes nonsafety-related water-filled piping 

and components that have the potential for spatial interactions (spray or leakage) with 

safety-related SSCs (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49). The PCV 

System contains components associated with the primary containment isolation valves 

that are environmentally qualified (10 CFR 54.4(a)(3)).

LRA Table 2.3.3-17 identifies the PCV System component types within the scope of license

renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.17 using the evaluation methodology described in SER

Section 2.3, the UFSAR, and the guidance in SRP-LR Section 2.3. During its review, the staff 

evaluated the system functions described in the LRA and UFSAR to verify that the applicant has 

not omitted from the scope of license renewal any components with intended functions 

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant 

identified as within the scope of license renewal to verify that the applicant has not omitted any 

passive and long-lived components subject to an AMR in accordance with the requirements of 

10 CFR 54.21(a)(1).

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant 

appropriately identified the PCV System components within the scope of license renewal as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified all the components 

subject to an AMR in accordance with the requirements in 10 CFR 54.21(a)(1).

2.3.3.18 Process Radiation Monitoring System

Summary of Technical Information in the Application

LRA Section 2.3.3.18 states that the purposes of the Process Radiation Monitoring System are

to monitor the level of radioactivity of various process liquid and gas lines that can serve as 

discharge routes for radioactive materials; provide indication and record of detected levels; and,
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for certain systems, support the prevention of an uncontrolled release of radioactive liquids, 

gases, and particulates by providing isolation signals to the monitored systems.

The normally operating Process Radiation Monitoring System consists of safety-related and 

nonsafety-related portions and is in scope for license renewal. However, portions of the 

Process Radiation Monitoring System are not required to perform intended functions and are 

not in scope.

The Process Radiation Monitoring System consists of the following monitors:

• main steam line radiation monitors

• Reactor Building ventilation exhaust radiation monitors

• fuel floor vent plenum exhaust radiation monitors

• control room ventilation intake radiation monitors

• standby gas treatment stack effluent monitor

• RHR service water effluent radiation monitors

• service water effluent radiation monitor

• liquid radwaste effluent radiation monitor

• RBCCW radiation monitor

• off-gas pre-treatment monitor

• off-gas post-treatment monitor

• off-gas carbon bed vault monitor

• station vent stack effluent radiation monitor

The intended functions of the Process Radiation Monitoring System within the scope of license 

renewal include the following:

• Sense process conditions and generate signals for reactor trip or engineered safety 

features actuation. The Process Radiation Monitoring System monitors plant processes 

for radiation level and initiates appropriate protective action to limit the potential release 

of radioactive materials. The reactor building ventilation exhaust and fuel floor vent 

plenum exhaust radiation monitors initiate primary and secondary containment isolation 

and initiate the SGT system. The CRV intake radiation monitors isolate the normal 

outside air supply (10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. Some nonsafety-related portions of the system provide 

structural restraint or support for safety-related components. Some nonsafety-related 

portions of the system are liquid-filled and have the potential for spatial interaction with 

safety-related equipment in the Reactor and Auxiliary Buildings (10 CFR 54.4(a)(2)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The station vent stack wide-range radiation monitor is credited 

to sense process conditions and to generate signals to actuate control room alarms to 

prompt operator actions in response to a radioactive gas waste system leak or abnormal 

operational transient (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49). The process 

radiation monitoring system includes safety-related electrical equipment that is 

environmentally qualified to remain functional during post-accident conditions 

(10 CFR 54.4(a)(3)).
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LRA Table 2.3.3-18 identifies the Process Radiation Monitoring System component types within 

the scope of license renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.18; UFSAR Sections 6.4, 7.1.2, 7.3.4, 7.6.1, 7.7.14, 9.4.1, 

and 11.5; and the license renewal boundary drawings using the evaluation methodology 

discussed in SER Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its 

review, the staff did not identify the need for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Process Radiation Monitoring System mechanical components 

within the scope of license renewal as required by 10 CFR 54.4(a). The staff also concludes 

that the applicant adequately identified the system components subject to an AMR in 

accordance with the requirements in 10 CFR 54.21(a)(1).

2.3.3.19 Process Sampling and Post Accident Monitoring System

Summary of Technical Information in the Application

The Process Sampling and Post Accident Monitoring System consists of the containment 

monitoring system, process sampling system, and post-accident sampling system.

LRA Section 2.3.3.19 states the purposes of the Process Sampling and Post Accident 

Monitoring System are to provide indication of critical parameters within containment; to obtain 

representative samples from process streams and convey them to central sample stations for 

use in minimizing leakage, spillage, and potential radiation exposure during normal operations;

and to collect liquid and gaseous samples of the reactor coolant and containment atmosphere 

following a post-accident condition. The Process Sampling and Post Accident Monitoring 

System is a normally operating system.

The purpose of the containment monitoring system is to provide indication and alarms for the 

following containment parameters during normal and abnormal operating conditions:

• drywell and suppression chamber pressure

• drywell, suppression chamber, and suppression pool temperature

• suppression pool and containment flooding water levels

• drywell and suppression chamber oxygen and hydrogen concentrations

• drywell gross radiation and drywell and suppression chamber airborne radiation levels

The purpose of the process sampling portion of the system is to provide the capability for 

sampling various process systems during normal plant power operation and shutdown 

conditions. It accomplishes this purpose by taking representative samples from various process 

lines.

The purpose of the post-accident sampling portion of the system is to obtain representative 

liquid and gas grab samples from the reactor coolant system and within containments for 

radiological and chemical analysis under accident conditions.
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The intended functions of the Process Sampling and Post Accident Monitoring System within 

the scope of license renewal include the following:

• Sense process conditions and generate signals for reactor trip or engineered safety 

features actuation. The system includes containment pressure instrumentation that 

actuates a reactor trip and an actuation of the ECCS and primary and secondary 

containment isolation (10 CFR 54.4(a)(1)).

• Provide primary containment boundary. The system includes piping and isolation valves 

that are part of the primary containment boundary (10 CFR 54.4(a)(1)).

• Control combustible gas mixtures in the primary containment atmosphere. The system 

includes equipment that samples the containment atmosphere and provides indication of 

oxygen and hydrogen concentration (10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. Some portions of the nonsafety-related Process Sampling and 

Post-Accident Monitoring System are relied on to preserve the structural support 

intended function of the safety-related piping used for sampling and instrumentation and 

for containment isolation. Some portions of the sampling system may be liquid-filled and 

have the potential for spatial interaction with safety-related equipment in the Reactor and 

Auxiliary Buildings (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48). 

Suppression pool instrumentation for level and temperature supports fire safe shutdown 

requirements (10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49). Containment 

monitoring instrumentation is required to remain functional following a design basis 

LOCA (10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for SBO (10 CFR 50.63). Suppression 

pool instrumentation for level and temperature supports SBO under coping requirements 

(10 CFR 54.4(a)(3)).

LRA Table 2.3.3-19 identifies the Process Sampling and Post Accident Monitoring System 

component types within the scope of license renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.19; UFSAR Sections 7.5.2, 9.3.2, and 11.5.5; and the 

license renewal boundary drawings using the evaluation methodology discussed in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Process Sampling and Post Accident Monitoring System mechanical 

components within the scope of license renewal as required by 10 CFR 54.4(a). The staff also 
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concludes that the applicant adequately identified the system components subject to an AMR in 

accordance with the requirements in 10 CFR 54.21(a)(1).

2.3.3.20 Radwaste System

Summary of Technical Information in the Application

The Radwaste System includes the liquid radwaste system, gaseous radwaste system, and 

solid radwaste system.

The purpose of the liquid radwaste system is to collect, monitor, and process all potentially 

radioactive liquid wastes produced by the station. The waste/equipment drain processing 

subsystem collects and processes high-purity (low-conductivity) sources of radioactive liquid 

waste, such as plant equipment drains. This water is treated by settling, filtration, and 

demineralization and is returned for station reuse through the cycled condensate storage tank. 

The liquid radwaste plant system includes the following subsystems:

• waste/equipment drain processing subsystem

• floor drain processing subsystem

• chemical waste subsystem

• laundry waste subsystem

• sludge subsystem

The purpose of the solid radwaste plant system is to process all radioactive wet solid wastes 

produced by the station. The solid radwaste system accomplishes this by receiving, 

dewatering, solidifying, packaging, handling, and providing temporary storage for radioactive 

wet solid wastes, such as expended demineralizer resins and spent precoat material, before 

offsite shipment and disposal. The solid radwaste system also receives, decontaminates,

and/or compacts, and provides temporary storage for, all radioactive dry wastes produced by 

the station before offsite shipment and disposal.

The purpose of the gaseous radwaste plant system is to process and control the release of 

gaseous radioactive wastes to the site environment. The gaseous radwaste system 

accomplishes this through the use of high-temperature catalytic recombining, holdup for decay, 

high-efficiency particulate filtration, and charcoal adsorption before discharge to the station vent 

stack.

The intended function of the Radwaste System within the scope of license renewal is:

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The Radwaste System contains nonsafety-related fluid-filled 

lines in the Reactor Building and Auxiliary Building, which have potential spatial 

interactions with safety-related SSCs (10 CFR 54.4(a)(2)).

LRA Table 2.3.3-20 identifies the Radwaste System component types within the scope of 

license renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.20; UFSAR Sections 11.2, 11.3, and 11.4; and the license 

renewal boundary drawings using the evaluation methodology discussed in SER Section 2.3 
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and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did not identify the 

need for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified Radwaste System mechanical components within the scope of license 

renewal as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately 

identified the system components subject to an AMR in accordance with the requirements in 

10 CFR 54.21(a)(1).

2.3.3.21 Reactor Water Cleanup System

Summary of Technical Information in the Application

LRA Section 2.3.3.21 states that the purpose of the Reactor Water Cleanup (RWCU) System is 

to remove solid and dissolved impurities from recirculated reactor coolant; discharge excess 

reactor water during startup, shutdown, and hot standby conditions; minimize temperature 

gradients in the recirculation piping and vessel during periods of low flow rates; and conserve 

reactor heat. The RWCU System accomplishes these operations by forced circulation of 

reactor coolant through regenerative and nonregenerative heat exchangers and filter

demineralizers. The RWCU System also provides for monitoring the durability and 

effectiveness of noble metal compounds deposited on reactor vessel and piping surfaces by 

processing reactor coolant through a material monitoring system and a data acquisition system.

The intended functions of the RWCU System within the scope of license renewal include the 

following:

• Provide reactor coolant pressure boundary. The RWCU System includes a 

safety-related remote manual-operated valve on the return line to the reactor to provide 

long-term leakage control in the event of a piping failure in the RWCU System 

(10 CFR 54.4(a)(1)).

• Provide primary containment boundary. The RWCU System includes a safety-related 

remote manual-operated primary containment isolation valve on the return line to the 

reactor (10 CFR 54.4(a)(1)).

• Sense process conditions and generate signals for reactor trip or engineered safety 

features actuation. The RWCU System includes safety-related flow elements and 

instrumentation for the determination of RWCU System high differential flow. The high 

differential flow signal is an indication of leakage or a break in RWCU piping and is used 

to automatically isolate the RWCU System from the reactor coolant pressure boundary 

(10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The RWCU System contains nonsafety-related high-energy and 

moderate-energy lines in the Reactor Building and Auxiliary Building, which provide 

structural support or have potential spatial interactions with safety-related SSCs 

(10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48). The 

RWCU blowdown flow control valve, RWCU discharge to main condenser valve, and 
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RWCU drain to waste surge tanks valve are credited as high-low pressure interfaces for 

fire safe shutdown (10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49). The RWCU 

System includes an environmentally qualified remote manual-operated valve on the 

return line to the reactor (10 CFR 54.4(a)(3)).

LRA Table 2.3.3-21 identifies the RWCU System component types within the scope of license 

renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.21, UFSAR Section 5.4.8, and the license renewal 

boundary drawings using the evaluation methodology discussed in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. On the basis of its review, the staff identified an area in which 

additional information was necessary to complete the review of the applicant’s scoping and 

screening results.

In RAI 2.3.3.21-1, the staff notes that Unit 1 drawing LR-LAS-M-97-1 shows 10 CFR 54.4(a)(1) 

piping whose scope changes to 10 CFR 54.4(a)(2), whereas the piping classification changes to 

“Class C,” indicating ASME Section III Class 3 piping at the following locations:

LR-LAS-M-97, Sheet-1, Location Piping ID

Location E-7 Line 1RT01C 4 downstream of valve 1G33-F004

Location F-4 Line 1RT06B 4 downstream of valve 1G33-F040

Similarly for Unit 2, drawing LR-LAS-M-143, Sheet-1, shows 10 CFR 54.4(a)(1) piping whose 

scope changed to 10 CFR 54.4(a)(2), whereas the piping classification changes to “Class C,”

indicating ASME Section III Class 3 piping at the following locations:

LR-LAS-M-143, Sheet-1, Location Piping ID

Location E-7 2RT01C 4 downstream of valve 2G33-F004

Location F-4 2RT06B 4 downstream of valve 2G33-F040

The NRC requested that the applicant provide sufficient information to clarify the change in 

scoping classification.

In its response letter, dated August 26, 2015, the applicant stated that these piping sections are 

properly scoped as being in scope for 10 CFR 54.4(a)(2) intended functions. These piping 

sections are classified within the LSCS current design basis as nonsafety-related, and they do 

not have 10 CFR 54.4(a)(1) intended functions.

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.21-1 acceptable 

because the applicant clarified that the piping sections designated with Quality Group 

Classification “C” (ASME Code Section III, Class 3) listed in RAI 2.3.3.21-1 are outside of the 

RCPB and primary containment boundary and are nonsafety-related, are nonseismic, and do 

not have 10 CFR 54.4(a)(1) intended functions. Therefore, the staff’s concern described in 

RAI 2.3.3.21–1 is resolved.
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Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, RAI response, and license renewal boundary drawings, the staff concludes 

that the applicant appropriately identified the RWCU System mechanical components within the 

scope of license renewal as required by 10 CFR 54.4(a). The staff also concludes that the 

applicant adequately identified the system components subject to an AMR in accordance with 

the requirements in 10 CFR 54.21(a)(1).

2.3.3.22 Safety-Related Ventilation System

Summary of Technical Information in the Application

LRA Section 2.3.3.22 states that the Safety-Related Ventilation (SRV) System is a normally 

operating system designed to provide a favorable environment for plant equipment and 

personnel while preventing the spread of contamination in the plant. The SRV System also 

includes dampers and ductwork that are part of the secondary containment boundary. The SRV 

System is in scope for license renewal. The SRV license renewal system consists of the 

following plant systems:

• Reactor Building ventilation system

• ECCS equipment cooling ventilation system

• diesel generator room ventilation system

• switchgear heat removal system

• Turbine Building ventilation system

The intended functions of the SRV System within the scope of license renewal include the 

following:

• Maintain emergency temperature limits within areas containing safety-related 

components (10 CFR 54.4(a)(1)).

• Provide secondary containment boundary (10 CFR 54.4(a)(1)).

• Provide a pathway to the station vent stack for the potential release of fission products 

following certain abnormal operating conditions (10 CFR 54.4(a)(2)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48), EQ

(10 CFR 40.49), and SBO (10 CFR 50.63) (10 CFR 54.4(a)(3)).

LRA Table 2.3.3-22 identifies the SRV System component types within the scope of license 

renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.22, the UFSAR, and LRA Table 2.3.3-22 using the 

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has not omitted from the scope of license renewal any components with 
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intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant has identified as being within the scope of license renewal to 

verify that it has not omitted any passive and long-lived components subject to an AMR in 

accordance with the requirements of 10 CFR 54.21(a)(1).

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant 

appropriately identified the SRV System components within the scope of license renewal as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the system components subject to an AMR as required by 10 CFR 54.21(a)(1).

2.3.3.23 Standby Liquid Control System

Summary of Technical Information in the Application

LRA Section 2.3.3.23 states that the primary purpose of the Standby Liquid Control (SLC) 

System is to shut down the reactor independent of the CRD System. The SLC System 

accomplishes this operation by injecting sodium pentaborate solution directly into the reactor 

vessel to absorb thermal neutrons. The SLC System operation is also credited during a LOCA

to maintain suppression pool water pH at acceptable levels to minimize the radiological release 

to the environment. The SLC System is capable of satisfying the requirements of the system 

generic design basis, as well as the requirement for the reduction of risks from an ATWS as 

specified in 10 CFR 50.62, “Requirements for Reduction of Risk from Anticipated Transients 

Without Scram (ATWS) Events for Light- Water-Cooled Nuclear Power Plants.”

The SLC System is a standby system that is manually operated to shut down the reactor if the 

normal reactivity control provisions become inoperative. The system is designed to bring the 

reactor to a shutdown condition at any time in core life independent of control rod insertion 

capability. The most severe requirement for which the system is designed is shutdown from a 

full power operating condition assuming complete failure of the CRD System to respond to a 

scram signal. The SLC System is in scope for license renewal. However, portions of the SLC 

System are not required to perform intended functions and are not in scope.

The intended functions of the SLC System within the scope of license renewal include the 

following:

• Introduce emergency negative reactivity to make the reactor subcritical. The SLC 

System provides backup capability for reactivity control, independent of normal reactivity 

control provisions in the nuclear reactor, to be able to shut down the reactor if the normal 

control becomes inoperative (10 CFR 54.4(a)(1)).

• Control and treat radioactive materials released to the secondary containment. In the 

event of a LOCA, the SLC System is manually initiated from the control room to pump 

sodium pentaborate into the reactor to maintain the suppression pool pH at a level of 7.0 

or higher to minimize iodine releases from primary containment to the environment 

(10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The SLC System includes nonsafety-related fluid-filled lines in 
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the Reactor Building, which have the potential for spatial and structural interaction with 

safety-related SSCs (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for ATWS (10 CFR 50.62). The SLC 

System injects sodium pentaborate solution into the reactor to achieve shutdown for 

mitigation of an ATWS (10 CFR 54.4(a)(3)).

LRA Table 2.3.3-23 identifies the SLC System component types within the scope of license 

renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.23, UFSAR Section 5.4.8, and the license renewal 

boundary drawings using the evaluation methodology discussed in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. On the basis of its review, the staff did not identify the need 

for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the SLC System mechanical components within the scope of license 

renewal as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately 

identified the system components subject to an AMR in accordance with the requirements in 

10 CFR 54.21(a)(1).

2.3.3.24 Suppression Pool Cleanup System

Summary of Technical Information in the Application

LRA Section 2.3.3.24 states that the purpose of the Suppression Pool Cleanup (SPC) System is 

to provide a means of improving the quality of the water in the suppression pool and transferring 

suppression pool water to the reactor well and the dryer-separator well in support of refueling 

operations. The SPC System can also be used to transfer suppression pool water to the main 

condenser. The SPC System does not have safety-related functions. The SPC System is in 

scope for license renewal. However, portions of the SPC System are not required to perform 

intended functions and are not in scope.

The intended function of the SPC System within the scope of license renewal is:

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The SPC System contains nonsafety-related fluid-filled lines in 

the Reactor Buildings, Turbine Buildings, and Auxiliary Building that have potential 

spatial interactions with safety-related SSCs (10 CFR 54.4(a)(2)).

LRA Table 2.3.3-24 identifies the SPC System component types within the scope of license 

renewal and subject to an AMR.
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Staff Evaluation

The staff reviewed LRA Section 2.3.3.24, UFSAR Section 9.2.11, and the license renewal 

boundary drawings using the evaluation methodology discussed in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. On the basis of its review, the staff did not identify the need 

for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the SPC System mechanical components within the scope of license 

renewal as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately 

identified the system components subject to an AMR in accordance with the requirements in 

10 CFR 54.21(a)(1).

2.3.3.25 Traversing Incore Probe System

Summary of Technical Information in the Application

LRA Section 2.3.3.25 states the primary purpose of the Traversing Incore Probe (TIP) System is 

to measure local neutron flux at various locations throughout the core in support of calibrating 

the Local Power Range Monitor (LPRM) Neutron Monitoring System detectors. The TIP System 

accomplishes its purpose by using neutron monitoring detectors and positioning systems 

capable of moving the flux detectors to various locations in the core corresponding to the 

locations of the LPRM detectors. The moveable TIP detectors generate signals that are 

processed to indicate local power in the vicinity of each LPRM detector. The TIP System is in 

scope for license renewal. However, portions of the TIP System are not required to perform 

intended functions and are not in scope.

The intended function of the TIP System within the scope of license renewal is:

• Provide primary containment boundary. The TIP System ball valves, shear valves, and 

TIP tubing between the shear valves and the primary containment penetrations form a 

primary containment boundary (10 CFR 54.4(a)(1)).

LRA Table 2.3.3-25 identifies the TIP System component types within the scope of license 

renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.3.25, UFSAR Section 7.7.6.4, and the license renewal 

boundary drawings using the evaluation methodology discussed in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. On the basis of its review, the staff did not identify the need 

for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA and UFSAR, the staff concludes that the applicant appropriately identified the TIP

System mechanical components within the scope of license renewal as required by 
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10 CFR 54.4(a). The staff also concludes that the applicant adequately identified the system 

components subject to an AMR in accordance with the requirements in 10 CFR 54.21(a)(1).

2.3.4 Steam and Power Conversion System

LRA Section 2.3.4 identifies the Steam and Power Conversion System SCs subject to an AMR 

for license renewal. The applicant described the supporting SCs of the Steam and Power 

Conversion System in the following LRA sections:

• LRA Section 2.3.4.1, “Condensate System”

• LRA Section 2.3.4.2, “Condenser and Air Removal System”

• LRA Section 2.3.4.3, “Feedwater System”

• LRA Section 2.3.4.4, “Main Steam System”

• LRA Section 2.3.4.5, “Main Turbine and Auxiliaries System”

The staff’s findings on review of LRA Sections 2.3.4.1 – 2.3.4.5 are in SER Sections 2.3.4.1 –

2.3.4.5, respectively.

2.3.4.1 Condensate System

Summary of Technical Information in the Application

The Condensate System consists of the acid feed and caustic handling (no longer used and not 

in scope), clean condensate, condensate and condensate booster, condensate polishing, cycled 

condensate gland water, and cycled condensate systems.

LRA Section 2.3.4.1 states that the purpose of the Condensate System is to provide filtered and 

demineralized condensate from the condenser hotwell to the Feedwater System. The 

Condensate System also provides for the storage of clean and cycled condensate water for use 

in normal plant operations and refueling operations. The Condensate System is in scope for 

license renewal. However, portions of the Condensate System are not required to perform 

intended functions and are not in scope. The Condensate System is a normally operating 

system.

LRA Section 2.3.4.1 states that the purposes of Condensate System plant systems are as 

follows.

• The purpose of the clean condensate system is to provide clean (noncontaminated) 

reactor-grade water to various plant systems by distributing clean condensate from the 

clean condensate storage tank to plant equipment and water service connections 

located in the Turbine Building, Radwaste Building, Offgas Building, Service Building, 

Auxiliary Building, Reactor Building, Diesel Generator Building, and other areas in the 

plant.

• The purpose of the condensate and condensate booster systems is to provide a means 

of transferring water from the condenser hotwell to the suction of the reactor feed 

pumps.

• The purpose of the condensate polishing system is to remove dissolved and suspended 

solids from the condensate to maintain high-quality reactor feedwater by processing 

condensate through prefilters and condensate demineralizers.
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• The purpose of the gland water system is to provide gland water to various 

nonsafety-related plant pumps by providing cycled condensate from the cycled 

condensate gland seal head tank to each pump gland.

• The purpose of the cycled condensate system is to provide the necessary source of 

condensate (potentially contaminated) to various systems in the plant and to provide 

additional water for online and refueling activities by distributing condensate from the 

cycled condensate storage tanks to various systems throughout the plant.

The intended functions of the Condensate System within the scope of license renewal include 

the following:

• Provide primary containment boundary. The clean condensate supply lines that 

penetrate the primary containment are equipped with manually operated primary 

containment isolation valves (10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The Condensate System contains nonsafety-related fluid-filled 

lines in the Primary Containment, Auxiliary Building, Reactor Building, Diesel Generator 

Building, Offgas Building, and Turbine Building that provide structural support or have 

potential spatial interactions with safety-related SSCs (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48). The 

cycled condensate storage tanks are credited for fire safe shutdown as a suction source 

for the RCIC System (10 CFR 54.4(a)(3)).

LRA Table 2.3.4-1 identifies the Condensate System component types within the scope of 

license renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.4.1; UFSAR Sections 5.4.6.3, 6.2.4.2.2, 9.2.7, 10.4.6, 

and 10.4.7; and the license renewal boundary drawings using the evaluation methodology 

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its 

review, the staff did not identify the need for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

has appropriately identified the Condensate System mechanical components within the scope of 

license renewal as required by 10 CFR 54.4(a). The staff also concludes that the applicant has 

adequately identified the system components subject to an AMR in accordance with the 

requirements in 10 CFR 54.21(a)(1).

2.3.4.2 Condenser and Air Removal System

Summary of Technical Information in the Application

The Condenser and Air Removal System consists of the main condenser and main condenser 

evacuation plant systems.
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LRA Section 2.3.4.2 states that the purposes of the Condenser and Air Removal System are to 

provide a heat sink for exhaust steam from the main turbine and reactor feed pump turbines 

during normal operation and to remove noncondensible gases from the condenser and exhaust 

them to the gaseous radwaste system. The Condenser and Air Removal System is in scope for 

license renewal. However, portions of the Condenser and Air Removal System are not required 

to perform intended functions and are not in scope. The Condenser and Air Removal System is 

a normally operating system.

The purposes of the Condenser and Air Removal System plant systems are as follows:

• The purpose of the main condenser is to provide a heat sink for turbine exhaust steam, 

turbine bypass steam, and other turbine cycle flows and to receive and collect flows for 

return to the reactor by passing circulating water through the condenser tubes to 

condense the steam from turbine exhausts and other sources, by removing 

noncondensible gases during normal operation and plant startup, and by providing a 

volume for collection and storage of condensate to be returned to the reactor.

• The purpose of the main condenser evacuation system is to maintain a vacuum in the 

condenser for the three low pressure turbine exhausts by removing the noncondensible 

gases from the condenser, including air in-leakage and dissociation products originating 

in the reactor, and by discharging them to the gaseous radwaste system. The system 

also functions to minimize the release of radioactivity to the environment following a 

control rod drop accident by manual isolation of the main condenser off-gas outlet 

isolation valves and manual trip of the mechanical vacuum pump when high radiation is 

detected in the main steam lines.

The intended functions of the Condenser and Air Removal System for license renewal include

the following:

• Sense process conditions and generate signals for reactor trip or engineered safety 

features actuation. Main condenser low vacuum instrumentation initiates MSIV closure 

and main steam line drain isolation (10 CFR 54.4(a)(1)).

• Provide post-accident containment holdup and plateout of MSIV bypass leakage. The 

main condenser is credited for holdup and plateout of MSIV leakage following a LOCA 

(10 CFR 54.4(a)(2)).

• Minimize the release of radioactive material to the environment. Manual isolation of the 

main condenser off-gas outlet valves and manual tripping of the mechanical vacuum 

pump is credited following a control rod drop accident to minimize radioactive releases 

(10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49). The Condenser 

and Air Removal System includes environmentally qualified pressure switches to sense 

loss of condenser vacuum (10 CFR 54.4(a)(3)).

LRA Table 2.3.4-2 identifies the Condenser and Air Removal System components within the 

scope of license renewal and subject to an AMR.
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Staff Evaluation

The staff reviewed LRA Section 2.3.4.2; UFSAR Sections 6.8, 7.3.2.2.3.12, 10.4.1, 10.4.2, 

15.4.9, and 15.6.5; and the license renewal boundary drawings using the evaluation 

methodology discussed in SER Section 2.3 and the guidance in SRP-LR Section 2.3. On the 

basis of its review, the staff did not identify the need for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Condenser and Air Removal System components within the scope of 

license renewal as required by 10 CFR 54.4(a). The staff also concludes that the applicant 

adequately identified the system components subject to an AMR in accordance with the 

requirements in 10 CFR 54.21(a)(1).

2.3.4.3 Feedwater System

Summary of Technical Information in the Application

The Feedwater System consists of the feedwater, feedwater heaters and drains, feedwater 

miscellaneous drains, feedwater control, zinc injection, hydrogen, and hydrogen water chemistry 

systems.

LRA Section 2.3.4.3 states that the purpose of the Feedwater System is to provide a 

dependable supply of high quality feedwater to the reactor vessel. The Feedwater System is in 

scope for license renewal. However, portions of the Feedwater System are not required to 

perform intended functions and are not in scope. The Feedwater System is a normally 

operating system.

The purposes of the Feedwater System plant systems are as follows:

• The purpose of the feedwater system is to provide feedwater at the required flow, 

pressure, and temperature to the reactor vessel by taking high-quality, preheated 

feedwater from the feedwater heaters and injecting the feedwater into the reactor vessel 

using motor or turbine driven reactor feed pumps.

• The purpose of the feedwater heaters and drains/feedwater miscellaneous drains is to 

recover thermal energy for preheating feedwater to increase the thermal efficiency of the 

plant by using cascading drains and extraction steam to heat reactor feedwater through 

the use of feedwater heaters.

• The purpose of the feedwater control system is to automatically control the flow of 

feedwater into the reactor vessel to maintain the water level in the vessel within 

predetermined levels over the entire power range of the reactor.

• The purpose of the zinc injection system is to reduce dose rates in the reactor 

recirculation piping by reducing the level of cobalt that is incorporated into the iron oxide 

layers on the recirculation piping by injecting a solution of depleted zinc oxide into the 

suction header of the reactor feed pumps.
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• The purpose of the hydrogen system is to provide a source of hydrogen for hydrogen 

water chemistry by providing regulated hydrogen from a cryogenic hydrogen storage 

facility to the hydrogen water chemistry injection system.

• The purpose of the hydrogen water chemistry system is to reduce rates of intergranular 

stress corrosion cracking in recirculation piping and reactor vessel internals by injecting 

hydrogen into the condensate booster pump suction header to suppress the formation of 

radiolytic oxygen in the reactor coolant.

The intended functions of the Feedwater System for license renewal include the following:

• Provide primary containment boundary. The system includes safety-related 

motor-operated primary containment isolation valves in the feedwater inlet lines to the 

reactor (10 CFR 54.4(a)(1)).

• Provide reactor coolant pressure boundary. The system includes safety-related 

motor-operated valves in the feedwater inlet lines to the reactor to provide long-term 

leakage control in the event of a piping failure in the Feedwater System 

(10 CFR 54.4(a)(1)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The Feedwater System contains nonsafety-related fluid-filled 

lines in the Reactor Building, Auxiliary Building, and Turbine Building that provide 

structural support or that have potential spatial interactions with safety-related SSCs 

(10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49). The Feedwater 

System motor-operated primary containment isolation valves include components that 

are environmentally qualified (10 CFR 54.4(a)(3)).

LRA Table 2.3.4-3 identifies the Feedwater System components within the scope of license 

renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.4.3; UFSAR Sections 5.4.15, 6.2, 7.7.4, and 10.4.7; and the 

license renewal boundary drawings using the evaluation methodology discussed in SER

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Feedwater System components within the scope of license renewal 

as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the system components subject to an AMR in accordance with the requirements in 

10 CFR 54.21(a)(1).
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2.3.4.4 Main Steam System

Summary of Technical Information in the Application

The Main Steam System consists of the plant main steam system and MSIV leakage control 

system. The station MSIV leakage control system is abandoned in place for Unit 1 and deleted 

for Unit 2.

LRA Section 2.3.4.4 states the purposes of the Main Steam System are as follows:

• Provide the high-pressure steam produced by the reactor to the main turbine during 

normal plant operation through the four main steam lines between the outboard primary 

containment isolation valves, the main turbine stop valves, and the main turbine bypass 

valves.

• Provide the capability to bypass steam around the main turbine by operation of main 

turbine bypass valves that discharge to the main condenser.

• Provide steam to users, such as the reactor feed pump turbines, steam jet air ejectors, 

off-gas preheaters, second stage reheaters, and steam seal evaporator, by providing 

high-pressure steam from upstream of the main turbine stop valves to flow or pressure 

control valves at each of the steam users.

• Route the main steam relief valve (MSRV) discharge to the suppression pool to 

minimize the thermal effects of opening the relief valves by routing the steam from the 

MSRV into the suppression pool, below the normal water level, to a quencher to 

facilitate condensation of the steam.

• Contain MSIV leakage following a LOCA by providing a volume within the large diameter 

main steam piping for plateout and holdup and a flow path through main steam drain 

lines to the main condenser for additional plateout and holdup in the condenser.

The intended functions of the Main Steam System for license renewal include the following:

• Sense process conditions and generate signals for reactor trip or engineered safety 

features actuation. The Main Steam System contains reactor protection system 

instrumentation that initiates reactor scram or turbine trip (10 CFR 54.4(a)(1)).

• Provide emergency heat removal from primary containment and provide containment 

pressure control. The Main Steam System includes the MSRV discharge piping, which 

prevents bypass leakage between the drywell and suppression pool and routes MSRV 

discharge to the suppression pool (10 CFR 54.4(a)(1)).

• Provide post-accident containment holdup and plateout of MSIV bypass leakage. The 

Main Steam System contains leakage from MSIVs and routes the leakage to the main 

condenser for holdup and plateout before release following a LOCA (10 CFR 54.4(a)(2)).

• Resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The Main Steam System includes nonsafety-related SSCs with 

the potential for spatial and structural interaction with safety-related SSCs in the Reactor 

Building (10 CFR 54.4(a)(2)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48). The 
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Main Steam System includes the MSRV discharge piping, which is used to reduce and 

control reactor pressure to support fire safe shutdown (10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for EQ (10 CFR 50.49). The Main Steam 

System contains reactor protection instrumentation that is subject to the requirements of 

10 CFR 50.49 (10 CFR 54.4(a)(3)).

• Relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the Commission’s regulations for SBO (10 CFR 50.63). The Main 

Steam System includes the MSRV discharge lines, which are used during an SBO to 

reduce and control reactor pressure (10 CFR 54.4(a)(3)).

LRA Table 2.3.4-4 identifies the Main Steam System component types within the scope of 

license renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.4.4; UFSAR Sections 3.2, 6.7, 6.8, 10.3, and 15.6; and the 

license renewal boundary drawings using the evaluation methodology discussed in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Main Steam System components within the scope of license renewal 

as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the system components subject to an AMR in accordance with the requirements in 

10 CFR 54.21(a)(1).

2.3.4.5 Main Turbine and Auxiliaries System

Summary of Technical Information in the Application

The Main Turbine and Auxiliaries System consists of the turbine generator system, gland seal 

steam system, turbine lube oil system, electro-hydraulic control (EHC) system, turbine test 

system, and portions of the main steam system.

LRA Section 2.3.4.5 states that the purpose of the Main Turbine and Auxiliaries System is to 

convert the thermal energy in the steam supplied from the reactor into rotational mechanical 

energy. The Main Turbine and Auxiliaries System is in scope for license renewal; however, 

portions of the system are not required to perform intended functions and are not in scope. The 

Main Turbine and Auxiliaries System is a normally operating system.

The purposes of the Main Turbine and Auxiliaries System plant systems are as follows:

• The purpose of the main turbine is to convert the thermal energy in the steam produced 

by the reactor into rotational mechanical energy for use by the main generator in 

producing electricity and to provide a passive holdup volume in conjunction with the 

main condenser following an accident for any leakage through the MSIV using the 
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exhaust hoods of the low pressure turbines, which are mounted on the top of the main 

condenser to form the boundary for holdup of MSIV leakage.

• The purpose of the gland seal steam system is to provide a source of clean steam to the 

shaft seals for the main high and low pressure turbine rotors; shaft seals for the reactor 

feed pump turbine rotors; and large main steam valves, including the main turbine stop 

valves, main turbine control valves, main turbine bypass valves, combined intermediate 

valves, and reactor feed pump turbine stop and control valves, by heating condensate 

during power operation in the steam seal evaporator.

• The purpose of the lube oil system is to provide clean pressurized oil to the main turbine 

thrust bearing, main turbine journal bearings, lift pump suction, hydrogen seal oil, and 

reactor feed pump turbine control system and bearings. It accomplishes this by purifying 

the lube oil and providing the pressurized oil to the selected users and returning it to the 

purification equipment.

• The purpose of the electro-hydraulic control system is to provide hydraulic fluid for 

control of main steam header pressure, turbine speed, and steam flow during normal 

operating and transient conditions by positioning the main steam stop valves, control 

valves, combined intermediate valves, and bypass valves.

• The purpose of turbine test system is to provide various system connection points so

that thermal performance testing can be performed on the turbine assembly by installed 

instrumentation connection points to monitor process variables in the Main Turbine and 

Auxiliaries System. This turbine test system is only installed on Unit 2.

The intended function of the Main Turbine and Auxiliaries System for license renewal includes:

• Provide post-accident containment holdup and plateout of MSIV bypass leakage. Credit 

is taken for holdup and plateout in the main condenser for MSIV leakage. The low 

pressure turbine exhaust hoods form part of this holdup boundary with the main 

condenser (10 CFR 54.4(a)(2)).

LRA Table 2.3.4-5 identifies the Main Turbine and Auxiliaries System component types within 

the scope of license renewal and subject to an AMR.

Staff Evaluation

The staff reviewed LRA Section 2.3.4.5, UFSAR Section 10.2, and the license renewal 

boundary drawings using the evaluation methodology discussed in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. On the basis of its review, the staff did not identify the need 

for additional information.

Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.3 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Main Turbine and Auxiliaries System components within the scope of 

license renewal as required by 10 CFR 54.4(a). The staff also concludes that the applicant 

adequately identified the system components subject to an AMR in accordance with the 

requirements in 10 CFR 54.21(a)(1).
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2.4 Scoping and Screening Results: Structures and Component Supports

This section documents the staff’s review of the applicant’s scoping and screening results for 

Structures and Component Supports. Specifically, this section discusses systems and 

structures within the following LRA sections:

• LRA Section 2.4.1, “Auxiliary Building”

• LRA Section 2.4.2, “Component Supports Commodity Group”

• LRA Section 2.4.3, “Cooling Lake”

• LRA Section 2.4.4, “Diesel Generator Building”

• LRA Section 2.4.5, “Lake Screen House”

• LRA Section 2.4.6, “Offgas Building”

• LRA Section 2.4.7, “Primary Containment”

• LRA Section 2.4.8, “Radwaste Building”

• LRA Section 2.4.9, “Reactor Building”

• LRA Section 2.4.10, “Structural Commodity Group”

• LRA Section 2.4.11, “Switchyard Structures”

• LRA Section 2.4.12, “Tank Foundations and Dikes”

• LRA Section 2.4.13, “Turbine Building”

• LRA Section 2.4.14, “Yard Structures”

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the 

applicant properly implemented its methodology, the staff’s review focused on the 

implementation results. This focus allowed the staff to confirm that there were no omissions of 

SCs that meet the scoping criteria and are subject to an AMR.

The staff’s evaluation of the information in the LRA was the same for all structures. The 

objective was to determine whether the applicant has identified, in accordance with 

10 CFR 54.4, “Scope,” components and supporting structures for structures that appear to meet 

the license renewal scoping criteria. Similarly, the staff evaluated the applicant’s screening 

results to verify that all passive, long-lived SCs were subject to an AMR in accordance with 

10 CFR 54.21(a)(1).

In its scoping evaluation, the staff reviewed the applicable LRA sections, focusing on 

components that have not been identified as within the scope of license renewal. The staff 

reviewed relevant licensing basis documents, including the UFSAR, for each structure to 

determine whether the applicant has omitted from the scope of license renewal components 

with intended functions delineated under 10 CFR 54.4(a). The staff also reviewed the licensing 

basis documents to determine whether the LRA specified all intended functions delineated 

under 10 CFR 54.4(a). The staff requested additional information to resolve any omissions or 

discrepancies identified.

After its review of the scoping results, the staff evaluated the applicant’s screening results. 

For those SCs with intended functions. The staff sought to determine whether (1) the functions 

are performed with moving parts or a change in configuration or properties or (2) the SCs are 

subject to replacement after a qualified life or specified time period, as described in 

10 CFR 54.21(a)(1). For those meeting neither of these criteria, the staff sought to confirm that 

these SCs were subject to an AMR as required by 10 CFR 54.21(a)(1). The staff requested 

additional information to resolve any omissions or discrepancies identified.
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2.4.1 Auxiliary Building

2.4.1.1 Summary of Technical Information in the Application

LRA Section 2.4.1 states that the purpose of the Auxiliary Building is to provide structural 

support, shelter, and protection to SSCs along with personnel housed within the building during 

normal plant operations and during and following postulated DBAs and extreme environmental 

conditions. The Auxiliary Building is a seismic Category I safety-related multiple-story structure 

comprised of a reinforced concrete shear wall structure supported on a reinforced concrete mat 

foundation on soil. The building meets the regulation at 10 CFR 54.4(a)(1) because it is relied

on to remain functional during and following DBEs and regulation at 10 CFR 54.4(a)(2) because 

failure of nonsafety-related portions of the structure could prevent satisfactory accomplishment 

of a function(s) identified for 10 CFR 54.4(a)(1). The building also provides protection for SSCs 

that are within the scope of license renewal to support regulated events pursuant to 

10 CFR 54.4(a)(3).

The Auxiliary Building is designed to maintain its structural integrity during and following 

postulated DBAs and extreme environmental conditions. According to Table 3.2-1 (note 34) of 

the UFSAR, shear walls are considered Category I for the Reactor Building, Auxiliary Building, 

Turbine Building, Radwaste Building, Diesel Generator Buildings, and Off-gas Filter Building 

because they are all interconnected and act together to resist lateral loads applied to these 

structures.

The LRA states that fire barriers, component supports, and structural commodities are 

evaluated separately in other relevant systems and commodity groups and are not included 

within the evaluation boundary of the Auxiliary Building. In addition, mechanical and electrical 

systems and components housed in or located within the Auxiliary Building are evaluated with 

their respective mechanical and electrical license renewal system or commodity group. 

Included within the boundary of the Auxiliary Building and determined not to be within the scope 

of license renewal are certain architectural elements in the miscellaneous operational support 

areas, such as the computer room and labs that include drywall partitions and soffits and 

suspended ceilings.

The intended functions of the Auxiliary Building within the scope of license renewal include the 

following:

• Provide physical support, shelter, and protection for safety-related SSCs, provide a 

centralized area for control and monitoring of safety-related equipment, provide for the 

discharge of treated gaseous waste, and control the potential release of fission products 

to the external environment so that offsite consequences of DBEs are within acceptable 

limits (10 CFR 54.4(a)(1)).

• Provide physical support, shelter, and protection for nonsafety-related SSCs whose 

failure could prevent satisfactory accomplishment of function(s) identified for 

10 CFR 54.4(a)(1) (10 CFR 54.4(a)(2)).

• Provide structural support or restraint to SSCs not in scope of license renewal to prevent 

interaction with safety-related SSCs (10 CFR 54.4(a)(2)).
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• Provide physical support, shelter, and protection for systems, structures, and 

components relied on in safety analyses or plant evaluations to perform a function that 

demonstrates compliance with the Commission’s regulations for fire protection 

(10 CFR 50.48), EQ (10 CFR 50.49), ATWS (10 CFR 50.62), and SBO (10 CFR 50.63)

(10 CFR 54.4(a)(3)).

LRA Table 2.4-1 identifies the Auxiliary Building component types within the scope of license 

renewal and subject to an AMR. The AMR results for these components are provided in LRA 

Table 3.5.2-1.

2.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.1; UFSAR Sections 3.5, 6.4, 9.5, and 12.3; UFSAR 

Table 3.2-1; and the license renewal boundary drawings using the evaluation methodology 

described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. The staff also reviewed 

Section 3.8.4 of the UFSAR to identify seismic Category I structures.

During its review, the staff evaluated the structure and component functions described in the 

LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal 

any SCs with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those SCs that the applicant has identified as being within the scope of license renewal to verify 

that it has not omitted any passive and long-lived SCs subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

2.4.1.3 Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.4 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant

appropriately identified the Auxiliary Building SCs within the scope of license renewal as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the components subject to an AMR in accordance with the requirements in 10 CFR 54.21(a)(1).

2.4.2 Component Supports Commodity Group

2.4.2.1 Summary of Technical Information in the Application

In LRA Section 2.4.2, the applicant described the Component Supports Commodity Group

consisting of structural elements and specialty components designed to transfer the load 

applied from an SSC to the building structural element or directly to the building foundation. 

Supports include seismic anchors or restraints, support frames, constant and variable spring 

hangers, rod hangers, guides, stops, straps, and clamps. Snubbers are also included in the 

boundary of this commodity group but are considered active components and are not subject to 

an AMR except for the end connections, which perform a passive function for structural support. 

The commodity group includes supports for ASME Code Class 1, 2, and 3 and metal 

components piping and components, including reactor vessel anchorage, cable trays, HVAC 

ducts; emergency diesel generators; platforms; spray shields; miscellaneous structures; racks; 

panels; and cabinets and enclosures for electrical equipment and instrumentation. The 

Component Supports Commodity Group includes supports for mechanical, electrical, and 

instrumentation SSCs that are within the scope of license renewal and supports for SSCs that 

are not within the scope of license renewal but are required to restrain or prevent physical 

interaction with safety-related SSCs (e.g., seismic Category II over I).
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The intended functions of the Component Supports Commodity Group within the scope of 

license renewal include the following:

• Provide structural support or restraint to safety-related SSCs in scope of license renewal

(10 CFR 54.4(a)(1)).

• Provide structural support or restraint to SSCs not in scope of license renewal to prevent 

interaction with safety-related SSCs (10 CFR 54.4(a)(2)).

• Perform a function that demonstrates compliance with the Commission’s regulations for 

fire protection (10 CFR 50.48), EQ (10 CFR 50.49), ATWS (10 CFR 50.62), and SBO 

(10 CFR 50.63) (10 CFR 54.4(a)(3)).

The applicant evaluates concrete equipment foundations, concrete anchors, and embedments 

that are not included in the boundary of the Component Supports Commodity Group separately 

with the license renewal structure that contains them.

LRA Table 2.4-2 identifies the component types and intended functions of component supports 

that are subject to an AMR. The AMR results for these components are provided in LRA 

Table 3.5.2-2.

2.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2; UFSAR Sections 3.6, 3.7, 3.9, 3.10 and 8.3; UFSAR 

Table 3.2-1; and the license renewal boundary drawings using the evaluation methodology 

described in LRA Section 2.1 and the guidance in SRP-LR Section 2.4. The staff also reviewed

UFSAR Section 3.8.4 to identify seismic Category I structures.

During its review, the staff evaluated the structure and component functions described in the 

LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal 

any SCs with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those SCs that the applicant has identified as being within the scope of license renewal to verify 

that it has not omitted any passive and long-lived SCs subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

2.4.2.3 Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.4 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Component Supports Commodity Group SCs within the scope of 

license renewal as required by 10 CFR 54.4(a). The staff also concludes that the applicant 

adequately identified the components subject to an AMR in accordance with the requirements in 

10 CFR 54.21(a)(1).

2.4.3 Cooling Lake

2.4.3.1 Summary of Technical Information in the Application

LRA Section 2.4.3 states that the purpose of the safety-related Cooling Lake is to provide a 

source of cooling water for the Nonessential Cooling Water System, which includes the 

circulating water and service water systems. The upper portion of the Cooling Lake, including 

the embankment and discharge structure and discharge flume, are not safety-related and do not 
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perform an intended function for license renewal. The submerged core standby cooling system 

(CSCS) pond and intake flume, as well as the CSCS outfall structure, which are located within 

the Cooling Lake, are classified as safety-related. The purpose of the CSCS pond and intake 

flume is to provide the UHS by providing water for the ECW System and also for the Fire 

Protection System. The CSCS pond and intake flume are in scope for license renewal because 

they are classified as seismic Category I safety-related structures required to maintain structural 

integrity and an adequate volume of cooling water for safety-related systems during DBEs.

The CSCS outfall structure is a safety-related concrete structure that directs return water into 

the CSCS pond and is in scope for license renewal. However, the makeup pipeline outfall 

structure and makeup and blowdown valve house, service spillway, and auxiliary spillway do not 

perform an intended function for license renewal and, therefore, are not in scope. The 

evaluation boundary includes the cooling lake embankment (including discharge structure and 

flume), submerged CSCS pond and intake flume, the UHS, CSCS pipeline outfall structure, 

makeup pipeline outfall structure, and makeup and blowdown valve house, service spillway 

(blowdown intake structure), and the auxiliary spillway.

Not included in the boundary of the Cooling Lake are the Lake Screen House and the retaining 

walls on the north and south sides of the Lake Screen House, which are evaluated separately 

with the Lake Screen House. The shad net (cable, polymer, and steel components) are 

included within the ECW System; however, the anchors are within the scope of the Cooling 

Lake.

The intended functions of the Cooling Lake within the scope of license renewal include the 

following:

• Provide physical support, shelter, and protection for safety-related SSCs, provide UHS 

during DBEs, and provide a source of cooling water for plant safe shutdown

(10 CFR 54.4(a)(1)).

• Provide physical support, shelter, and protection for nonsafety-related systems, 

structures, and components whose failure could prevent satisfactory accomplishment of 

functions(s) identified for 10 CFR 54.4(a)(1) (10 CFR 54.4(a)(2)).

• Perform a function that demonstrates compliance with the Commission’s regulations for 

fire protection (10 CFR 50.48) and SBO (10 CFR50.63) (10 CFR 54.4(a)(3)).

LRA Table 2.4-3 identifies the Cooling Lake component types within the scope of license 

renewal and subject to an AMR. The AMR results for these components are provided in LRA 

Table 3.5.2-3.

2.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3; UFSAR Sections 2.4, 2.5, 9.2, 10.4, and 11.2; UFSAR 

Table 3.2-1; and the license renewal boundary drawings using the evaluation methodology 

described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. The staff also reviewed 

UFSAR Section 3.8.4 to identify seismic Category I structures.

During its review, the staff evaluated the structure and component functions described in the 

LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal 

any SCs with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those SCs that the applicant has identified as being within the scope of license renewal to verify 
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that it has not omitted any passive and long-lived SCs subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

2.4.3.3 Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.4 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Cooling Lake SCs within the scope of license renewal as required by 

10 CFR 54.4(a). The staff also concludes that the applicant adequately identified the 

components subject to an AMR in accordance with the requirements in 10 CFR 54.21(a)(1).

2.4.4 Diesel Generator Building

2.4.4.1 Summary of Technical Information in the Application

LRA Section 2.4.4 states that the purpose of the Diesel Generator Building is to provide 

structural support, shelter, access control, and protection to safety-related SSCs housed within 

it during operation, shutdown, and postulated DBAs. Each Diesel Generator Building is a 

multiple-level seismic Category I structure that is part of the power generation complex. The 

shear walls for the Reactor Building, Auxiliary Building, Turbine Building, Radwaste Building, 

Diesel Generator Buildings, and Off-gas Filter Building are seismic Category I and 

interconnected to act together to resist lateral loads applied to these buildings. Major 

components contained within the building include the emergency diesel generators, fuel oil 

storage and day tanks, electrical switchgear, HVAC diesel compartment cooling and ventilation 

equipment, and miscellaneous equipment required to support the operation and maintenance of 

the emergency diesel generators. The buildings are comprised of a multiple-level reinforced 

concrete substructure supported on a reinforced concrete mat foundation on soil with a steel 

frame above the grade floor and are designed to withstand tornadoes, missiles, and flooding.

The intended functions of the Diesel Generator Building within the scope of license renewal 

include the following:

• Provide physical support, shelter, and protection for safety-related SSCs 

(10 CFR 54.4(a)(1)).

• Provide physical support, shelter, and protection for safety-related SSCs relied on in 

safety analyses or plant evaluations to perform a function that demonstrates compliance 

with the Commission’s regulations for fire protection (10 CFR 50.48) and SBO 

(10 CFR 50.63) (10 CFR 54.4(a)(3)).

LRA Table 2.4-4 identifies the Diesel Generator Building component types within the scope of 

license renewal and subject to an AMR. The AMR results for these components are provided in 

LRA Table 3.5.2-4.

2.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4; UFSAR Sections 1.2, 3.5, 3.7, and 9.5; UFSAR

Table 3.2-1; UFSAR Appendix H – “Fire Hazards Analysis”; and the license renewal boundary 

drawings using the evaluation methodology described in SER Section 2.4 and the guidance in 

SRP-LR Section 2.4. The staff also reviewed UFSAR Section 3.8.4 to identify seismic 

Category I structures.
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During its review, the staff evaluated the structure and component functions described in the 

LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal 

any SCs with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those SCs that the applicant has identified as being within the scope of license renewal to verify 

that it has not omitted any passive and long-lived components subject to an AMR in accordance 

with the requirements of 10 CFR 54.21(a)(1).

2.4.4.3 Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.4 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Diesel Generator Building SCs within the scope of license renewal 

as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the components subject to an AMR in accordance with the requirements in 10 CFR 54.21(a)(1).

2.4.5 Lake Screen House

2.4.5.1 Summary of Technical Information in the Application

LRA Section 2.4.5 states that the purpose of the Lake Screen House is to provide structural 

support, shelter, protection, and access to submerged CSCS pond water (UHS) for seismic 

Category I safety-related concrete structural components and mechanical components under 

postulated environmental and DBA loading conditions. The Lake Screen House, which is in 

scope for license renewal, also provides a water-retaining boundary for the Cooling Lake and 

protection and access to Cooling Lake water for non-seismic Category I plant equipment and 

components, including fire protection pumps and associated piping, valves, and related 

equipment.

The non-seismic Category I Lake Screen House is a multiple-story building consisting of a 

reinforced concrete box-type structure, structural steel frame, and a precast concrete roof and is 

supported on a 4-ft-thick reinforced concrete mat foundation on soil. The Lake Screen House 

includes the seismic Category I service water tunnel, the two flume retaining walls, and the 

contiguous chemical feed building and is designed to provide protection for the service water 

tunnel and the associated safety-related piping and valve components. The building also 

provides a water-retaining boundary and access to the submerged portion of the CSCS.

The intended functions of the Lake Screen House within the scope of license renewal include 

the following:

• Provide physical support, shelter, and protection for safety-related SSCs 

(10 CFR 54.4(a)(1)).

• Provide a source of cooling water for plant safe shutdown (10 CFR 54.4(a)(1)).

• Provide protection for nonsafety-related SSCs whose failure could prevent satisfactory

accomplishment of safety-related functions (10 CFR 54.4(a)(2)).

• Perform a function that demonstrates compliance with the Commission’s regulations for 

fire protection (10 CFR 50.48) and SBO (10 CFR 50.63) (10 CFR 54.4(a)(3)).

LRA Table 2.4-5 identifies the components subject to an AMR and intended functions. 

The AMR results for these components are provided in LRA Table 3.5.2-5.
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2.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.4.5; UFSAR Sections 1.2, 2.5, 3.3, 3.4, and 9.2; UFSAR 

Table 3.2-1; and the license renewal boundary drawings using the evaluation methodology 

described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. The staff also 

reviewed UFSAR Section 3.8.4 to identify structures classified as seismic Category I.

During its review, the staff evaluated the structure and component functions described in the 

LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal 

any SCs with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those SCs that the applicant has identified as being within the scope of license renewal to verify 

that it has not omitted any passive and long-lived components subject to an AMR in accordance 

with the requirements of 10 CFR 54.21(a)(1).

2.4.5.3 Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.4 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Lake Screen House SCs within the scope of license renewal as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the components subject to an AMR in accordance with the requirements in 10 CFR 54.21(a)(1).

2.4.6 Offgas Building

2.4.6.1 Summary of Technical Information in the Application

LRA Section 2.4.6 states that the purpose of the Offgas Building is to provide structural support, 

shelter, and protection for nonsafety-related SSCs during normal plant operation. Except for the 

seismic Category I shear walls, the Offgas Building is classified as a nonsafety-related seismic 

Category II structure that is in scope for license renewal. Also known as the Off-gas Filter 

Building, the Offgas Building is part of the power generation complex, which includes several 

contiguous buildings. The building consists of a reinforced concrete structural steel and metal 

siding with interior reinforced concrete and concrete block walls supported by a reinforced 

concrete mat foundation on soil. The building contains the off-gas filters and associated 

equipment components and the support systems and components necessary to support fire 

protection. The building is also designed to resist exterior flooding.

The intended functions of the Offgas Building within the scope of license renewal include the 

following:

• Provide structural support or restraint to SSCs in the scope of license renewal

(10 CFR 54.4(a)(2)).

• Provide physical support, shelter, and protection for nonsafety-related SSCs whose 

failure could prevent satisfactory accomplishment of safety-related functions

(10 CFR 54.4(a)(2)).

• Perform a function that demonstrates compliance with the Commission’s regulations for 

fire protection (10 CFR 50.48) (10 CFR 54.4(a)(3)).

LRA Table 2.4-6 identifies the components subject to an AMR and intended functions. 

The AMR results for these components are provided in LRA Table 3.5.2-6.
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2.4.6.2 Staff Evaluation

The staff reviewed LRA Section 2.4.6; UFSAR Sections 1.1, 1.2, 3.4, and 9.5; UFSAR 

Table 3.2-1; and the license renewal boundary drawings using the evaluation methodology 

described in SER Section 2.1 and the guidance in SRP-LR Section 2.4. The staff also reviewed 

UFSAR Section 3.8.4 to identify structures classified as seismic Category I.

During its review, the staff evaluated the structure and component functions described in the 

LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal 

any SCs with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those SCs that the applicant has identified as being within the scope of license renewal to verify 

that it has not omitted any passive and long-lived components subject to an AMR in accordance 

with the requirements of 10 CFR 54.21(a)(1).

2.4.6.3 Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.4 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Offgas Building SCs within the scope of license renewal as required 

by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified the 

components subject to an AMR in accordance with the requirements in 10 CFR 54.21(a)(1).

2.4.7 Primary Containment

2.4.7.1 Summary of Technical Information in the Application

LRA Section 2.4.7 states that the purpose of the Primary Containment is to provide a high 

integrity barrier to contain the effects of the postulated design basis line break and direct the 

steam released to the suppression chamber pool. The Primary Containment and internal 

structures provide structural support to safety- and nonsafety-related SSCs housed within. 

The steel-lined concrete drywell and suppression chamber walls provide a structural pressure 

barrier; water-retaining boundary; radiation shielding; and structural support for floors in the 

Reactor Building, including the refueling floor and pools. The Primary Containment is entirely in 

scope for license renewal.

The Primary Containment includes both Units 1 and 2 Primary Containment structures and the 

containment internal structures. Each Primary Containment is entirely enclosed and contained 

within the reinforced concrete Reactor Building, which provides secondary containment, shelter, 

and protection for the Primary Containment and the components housed within. The Primary 

Containment is a steel-lined, post-tensioned, reinforced concrete, Mark II type, safety-related 

seismic Category I structure consisting of a steel dome head and post-tensioned concrete wall 

standing on a base mat of conventionally reinforced concrete. Major systems and components 

in the Primary Containment include the reactor vessel and associated auxiliary systems, vent 

pipe system, containment cooling system, and the main steam safety relief valve discharge 

piping with associated quencher components. The Primary Containment consists of the 

following major structural components: Primary Containment wall, base foundation slab, liner 

plate and anchorages, penetrations and access hatches, drywell head, and internal structures.
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The intended functions of the Primary Containment within the scope of license renewal include

the following:

• Provide primary containment boundary, and provide physical support, shelter, and 

protection for safety-related SSCs (10 CFR 54.4(a)(1)).

• Provide sufficient air and water volumes to absorb the energy released to the 

containment in the event of DBEs so that the pressure is within acceptable limits and 

provides a source of water for ECCS (10 CFR 54.4(a)(1)).

• Control the potential release of fission products to the external environment so that 

offsite consequences of DBEs are within acceptable limits (10 CFR 54.4(a)(1)).

• Control the release of fission products to the secondary containment in the event of a 

design basis LOCA so that offsite consequences are within acceptable limits

(10 CFR 54.4(a)(1)).

• Provide physical support, shelter, and protection for nonsafety-related SSCs whose 

failure could prevent satisfactory accomplishment of functions identified for 

10 CFR 54.4(a)(1) (10 CFR 54.4(a)(2)).

• Provide physical support, shelter, and protection for SSCs relied on in safety analyses or 

plant evaluations to perform a function that demonstrates compliance with the 

Commission’s regulations for fire protection (10 CFR 50.48), EQ (10 CFR50.49), ATWS

(10 CFR 50.62), and SBO (10 CFR 50.63) (10 CFR 54.4(a)(3)).

LRA Table 2.4-7 identifies the Primary Containment components within the scope of license 

renewal and subject to an AMR. The AMR results for these components are provided in LRA 

Table 3.5.2-7.

2.4.7.2 Staff Evaluation

The staff reviewed LRA Section 2.4.7; UFSAR Sections 5.3 and 6.2; UFSAR Table 3.6-6, 

Table 6.1-1, and Table 6.2-1; and the license renewal boundary drawings (including LR-M-3 and 

LR-LAS-M-92 and 138) using the evaluation methodology described in SER Section 2.4 and the 

guidance in SRP-LR Section 2.4. The staff also reviewed UFSAR Section 3.8.4 to identify 

structures classified as seismic Category I.

During its review, the staff evaluated the structure and component functions described in the 

LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal 

any SCs with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those SCs that the applicant has identified as being within the scope of license renewal to verify 

that it has not omitted any passive and long-lived components subject to an AMR in accordance 

with the requirements of 10 CFR 54.21(a)(1).

UFSAR Section 9.4.10.2 states that debris screens are provided for all purge penetrations. 

However, LRA Section 2.4.7, “Primary Containment,” and LRA Section 2.4.9, “Reactor 

Building,” do not discuss or include such components in their respective tables for components 

subject to an AMR. In a letter dated May 14, 2015, the staff asked the licensee to clarify 

whether such a component is relied on to perform an intended function; identify where it is 

covered in the LRA; and, if not, provide a justification for its exclusion from the scope of license 

renewal.
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In its response letter dated June 8, 2015, the licensee stated that the debris screens for the 

primary containment purge system are not scoped with either the Primary Containment or the 

Reactor Building. Instead, they are part of the containment vent and purge portion of the CGC 

system (LRA Section 2.3.3.2). They are in the scope of license renewal but were inadvertently 

omitted from the LRA. They perform an intended function to filter the air that passes through 

the containment vent and purge penetrations and are shown on drawings LR-LAS-M-92-1 and 

LR-LAS-M-138-1. LRA Tables 2.3.3-2 and 3.3.2-2 have been revised to include these 

components. The response also stated that an extent of condition review was performed to 

confirm other debris screens in similar configurations have been included in the LRA, and LRA 

Table 2.3.3-2 and Table 3.3.2-2 were revised to add new items. The staff finds the licensee’s 

response acceptable.

2.4.7.3 Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.4 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Primary Containment SCs within the scope of license renewal as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the components subject to an AMR in accordance with the requirements in 10 CFR 54.21(a)(1).

2.4.8 Radwaste Building

2.4.8.1 Summary of Technical Information in the Application

LRA Section 2.4.8 states that the purpose of the Radwaste Building is to provide structural 

support, shelter, and protection for nonsafety-related SSCs that collect, monitor, process, 

package, and provide temporary storage facilities for radioactive wastes during plant operation. 

The Radwaste Building also provides physical support, shelter, and protection to portions of the 

Fire Protection System.

The Radwaste Building is classified as a nonsafety-related seismic Category II structure with 

shear walls designed to act together with the other power generation complex shear walls 

classified as seismic Category I. The building, which does not contain any safety-related 

equipment, is a multiple-story structure with above- and below-grade areas designed to 

preclude accidental release of radioactive materials to the environment. The building shell is 

reinforced concrete with interior concrete and block walls supported on a reinforced concrete 

mat foundation on soil. The Radwaste Building is, therefore, in scope for license renewal.

The intended functions of the Radwaste Building within the scope of license renewal include the 

following:

• Provide physical support, shelter, and protection for nonsafety-related SSCs and 

components whose failure could prevent satisfactory accomplishment of safety-related 

functions (10 CFR 54.4(a)(2)).

• Provide physical support, shelter, and protection for SSCs relied on in safety analyses or 

plant evaluations to perform a function that demonstrates compliance with the 

Commission’s regulations for fire protection (10 CFR 50.48) (10 CFR 54.4(a)(3)).

LRA Table 2.4-8 identifies the Radwaste Building components within the scope of license 

renewal and subject to an AMR. The AMR results for these components are provided in LRA 

Table 3.5.2-8.
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2.4.8.2 Staff Evaluation

The staff reviewed LRA Section 2.4.8; UFSAR Sections 1.1, 1.2, 3.1, 3.4, 3.11, 7.7, 9.1, 9.4, 

11.2, 11.4, 12.3, and 15.7 and Appendix E; UFSAR Table 3.2-1; and the license renewal 

boundary drawings using the evaluation methodology described in SER Section 2.4 and the 

guidance in SRP-LR Section 2.4. The staff also reviewed UFSAR Section 3.8.4 to identify 

seismic Category I structures.

During its review, the staff evaluated the structure and component functions described in the 

LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal 

any SCs with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those SCs that the applicant has identified as being within the scope of license renewal to verify 

that it has not omitted any passive and long-lived components subject to an AMR in accordance 

with the requirements of 10 CFR 54.21(a)(1).

2.4.8.3 Conclusion

Based on the results of the staff’s evaluation discussed in LRA Section 2.4 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Radwaste Building SCs within the scope of license renewal as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the components subject to an AMR in accordance with the requirements in 10 CFR 54.21(a)(1).

2.4.9 Reactor Building

2.4.9.1 Summary of Technical Information in the Application

LRA Section 2.4.9 states that the purpose of the Reactor Building is to provide secondary 

containment when the primary containment is in service and to provide primary containment 

during reactor refueling and maintenance operations when the primary containment is open. 

The building, which includes the seismic Category I equipment access building, provides 

structural support and protection to SSCs housed within during normal plant operation and 

during and following postulated DBAs and extreme environmental conditions.

The structure is a safety-related seismic Category I reinforced concrete structure, which also 

houses refueling and reactor servicing equipment, new and spent fuel storage facilities, and 

other reactor safety and auxiliary systems. The structure consists of poured-in-place, reinforced 

concrete exterior walls up to the refueling floor and supported on a reinforced concrete mat 

foundation on soil that is continuous under the Primary Containment, Auxiliary Building, Diesel 

Generator Buildings, and Turbine Buildings. The exterior walls of the building are designed to 

carry a negative pressure of 0.25 psig and will serve as the containment during shutdown when 

the primary containment vessel is open for refueling or maintenance. The building also includes 

a reinforced concrete main steam chase that connects the primary containment to the main 

steam tunnel protecting the main steam line piping from external missiles and that protects the 

other seismic Category I components in the building from the effect of steam in the unlikely 

event of a pipe rupture inside the chase.
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The intended functions of the Reactor Building within the scope of license renewal include the 

following:

• Provide physical support, shelter, and protection for safety-related SSCs

(10 CFR 54.4(a)(1)).

• Provide protection for safe storage of new and spent fuel (10 CFR 54.4(a)(1)).

• Control the potential release of fission products to the external environment so that 

offsite consequences of DBEs are within acceptable limits (10 CFR 54.4(a)(1)).

• Provide physical support, shelter, and protection for nonsafety-related SSCs whose 

failure could prevent satisfactory accomplishment of safety-related functions

(10 CFR 54.4(a)(2)).

• Provide physical support, shelter, and protection for SSCs relied on in safety analyses or 

plant evaluations to perform a function that demonstrates compliance with the 

Commission’s regulations for fire protection (10 CFR 50.48), EQ (10 CFR 50.49), ATWS

(10 CFR 50.62), and SBO (10 CFR 50.63) (10 CFR 54.4(a)(3)).

LRA Table 2.4-9 identifies the Reactor Building components within the scope of license renewal 

and subject to an AMR. The AMR results for these components are provided in LRA 

Table 3.5.2-9.

2.4.9.2 Staff Evaluation

The staff reviewed LRA Section 2.4.9; UFSAR Sections 1.1, 1.2, 3.1, 3.3, 3.4, 3.5, 

3.11, 6.2, 9.1, and 9.5; UFSAR Table 3.2-1 (specifically notes 22 and 34); and the license 

renewal boundary drawings using the evaluation methodology described in SER Section 2.4

and the guidance in SRP-LR Section 2.4. The staff also reviewed UFSAR Section 3.8.4 to 

identify seismic Category I structures.

During its review, the staff evaluated the structure and component functions described in the 

LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal 

any SCs with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those SCs that the applicant has identified as being within the scope of license renewal to verify 

that it has not omitted any passive and long-lived components subject to an AMR in accordance 

with the requirements of 10 CFR 54.21(a)(1).

2.4.9.3 Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.4 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Reactor Building SCs within the scope of license renewal as required 

by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified the 

components subject to an AMR in accordance with the requirements in 10 CFR 54.21(a)(1).

2.4.10 Structural Commodity Group

2.4.10.1 Summary of Technical Information in the Application

LRA Section 2.4.10 states that the Structural Commodity Group shares material and 

environment properties allowing common programs across all in-scope structures to manage 
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their aging effects. Structural Commodities include bird screens, cable trays, compressible 

joints and seals, conduit, doors, insulation and insulation jacketing, louvers, spray shields, 

miscellaneous steel, panels, racks, cabinets and other enclosures, penetration seals and 

sleeves, roofing, seals, gaskets, moisture barriers, tube track, structural bolting, and concrete 

anchors associated with these commodities. Structural Commodities are located in the 

structures that are within the scope of license renewal.

The intended functions of the Structural Commodity Group within the scope of license renewal 

include the following:

• Provide physical support, shelter, and protection for safety-related SSCs

(10 CFR 54.4(a)(1)).

• Provide physical support, shelter, and protection for nonsafety-related SSCs whose 

failure could prevent satisfactory accomplishment of safety-related functions

(10 CFR 54.4(a)(2)).

• Provide physical support, shelter, and protection for SSCs relied on in safety analyses or 

plant evaluations to perform a function that demonstrates compliance with the 

Commission’s regulations for fire protection (10 CFR 50.48), ATWS (10 CFR 50.62), and 

SBO (10 CFR 50.63) (10 CFR 54.4(a)(3)).

LRA Table 2.4-10 identifies the Structural Commodity Group components within the scope of 

license renewal and subject to an AMR. The AMR results for these components are provided in 

LRA Table 3.5.2-10.

2.4.10.2 Staff Evaluation

The staff reviewed LRA Section 2.4.10; UFSAR Sections 3.4, 3.5, 5.2, 5.3, 6.1, 8.3, 9.4, 

and 9.5; UFSAR Table 3.2-1; and the license renewal boundary drawings using the evaluation 

methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. The staff 

also reviewed UFSAR Section 3.8.4 to identify structures classified as seismic Category I.

During its review, the staff evaluated the structure and component functions described in the 

LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal 

any SCs with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those SCs that the applicant has identified as being within the scope of license renewal to verify 

that it has not omitted any passive and long-lived components subject to an AMR in accordance 

with the requirements of 10 CFR 54.21(a)(1).

UFSAR Section 3.4.1.4, “Flood Protection Measures,” states, in part, that additional protection is 

provided by means of waterproofing and waterstops, all exterior walls to grade level are sealed 

with a waterproof membrane, and all exterior construction joints are sealed with waterstops to 

grade level. Seismic Category I structures that house safety-related equipment are the Reactor 

Building, Auxiliary Building, Diesel Generator Building, and Lake Screen House. The UFSAR 

includes components related to additional flood protection measures that are not included in the 

LRA tables for the relevant structures. In a letter dated May 14, 2015, the staff asked the 

applicant if the LRA addresses the waterstops and, if not, to provide a justification for their 

exclusion from the scope of license renewal.

In its response letter dated June 8, 2015, the applicant stated that the Structural Commodity 

Group scoping evaluation did not specifically identify waterstops because SRP-LR Table 2.4-1 
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states that waterstops do not need to be called out explicitly in the scoping or screening results 

if they are included as parts of structural components subject to an AMR. The response also 

stated that waterstops are included as integral parts of the reinforced concrete exterior 

below-grade structural components that are subject to an AMR and, therefore, are not called out 

explicitly in the scoping and screening or AMR results (also in accordance with SRP-LR 

Table 2.4-1). The waterproofing (waterproof membrane) applied to exterior below-grade walls 

does not provide an intended function for license renewal. The above- and below-grade exterior 

reinforced concrete (walls) and foundations provide the flood protection intended function as 

identified in LRA Tables 3.5.2-1, 3.5.2-4, 3.5.2-5, and 3.5.2-9 for the Auxiliary Building, Diesel 

Generator Building, Lake Screen House, and the Reactor Building. UFSAR Section 3.4.1.3 

describes structures in the context of flood protection and lists buildings that resist exterior 

floods both above and below grade. The waterproof membrane is identified in UFSAR 

Section 3.4.1.4 as an additional protection feature provided only on exterior below-grade walls. 

The above- and below-grade exterior reinforced concrete (walls) and foundations provide the 

flood protection intended function as identified in the screening and AMR review results for the 

structures. The staff finds the licensee’s response acceptable.

2.4.10.3 Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.4 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Structural Commodity Group SCs within the scope of license 

renewal as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately 

identified the components subject to an AMR in accordance with the requirements in 

10 CFR 54.21(a)(1).

2.4.11 Switchyard Structures

2.4.11.1 Summary of Technical Information in the Application

LRA Section 2.4.11 states that the purpose of the Switchyard Structures is to provide physical 

support, shelter, and protection for Offsite Power System components and to serve as the 

electrical transmission terminals for each unit. The Offsite Power System is relied on to provide 

offsite power during plant shutdown and in the event of a site emergency. The Switchyard 

Structures include the 345-kV switchyard, the switchyard relay house, and the switchyard 

maintenance building. The Switchyard Structures support connection between the offsite 

transmission network and the onsite distribution, including unit generators. The foundations 

within the 345-kV switchyard consist of reinforced concrete bearing on soil.

The switchyard relay house is a single-story above-grade masonry wall structure with reinforced 

concrete walls below grade supported on a reinforced concrete foundation slab on soil. The 

foundations and supports for four breakers located in the Switchyard Structures are relied on to 

provide physical support and the switchyard relay house provides physical support, shelter, and 

protection for components relied on to provide offsite power during SBO and fire safe shutdown, 

and are, therefore, in scope for license renewal. The remainder of the Switchyard Structures, 

including the switchyard maintenance building, are not in scope for license renewal.
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The intended function of the Switchyard Structures within the scope of license renewal includes 

the following:

• Provide physical support, shelter, and protection for SSCs relied on in safety analyses or 

plant evaluations to perform a function that demonstrates compliance with the 

Commission’s regulations for fire protection (10 CFR 50.48) and SBO (10 CFR 50.63)

(10 CFR 54.4(a)(3)).

LRA Table 2.4-11 identifies the Switchyard Structures components within the scope of license 

renewal and subject to an AMR. The AMR results for these components are provided in LRA 

Table 3.5.2-11.

2.4.11.2 Staff Evaluation

The staff reviewed LRA Section 2.4.11; UFSAR Sections 1.2, 8.1, 8.2, and 8.3; UFSAR 

Figures 8.1-1, 8.1-2, 8.1-3, and 8.1-4; UFSAR Appendix H; and the license renewal boundary 

drawings using the evaluation methodology described in SER Section 2.4 and the guidance in 

SRP-LR Section 2.4. The staff also reviewed UFSAR Section 3.8.4 to identify seismic 

Category I structures.

During its review, the staff evaluated the structure and component functions described in the 

LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal 

any SCs with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those SCs that the applicant has identified as being within the scope of license renewal to verify 

that it has not omitted any passive and long-lived components subject to an AMR in accordance 

with the requirements of 10 CFR 54.21(a)(1).

2.4.11.3 Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.4 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Switchyard Structures SCs within the scope of license renewal as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the components subject to an AMR in accordance with the requirements in 10 CFR 54.21(a)(1).

2.4.12 Tank Foundations and Dikes

2.4.12.1 Summary of Technical Information in the Application

LRA Section 2.4.12 states that the purpose of Tank Foundations and Dikes is to provide 

structural support, shelter, and protection for safety-related and nonsafety-related structure 

components and commodities, including systems and components that support fire safe 

shutdown. The purpose of the dikes around the cycled condensate storage tanks is for spill 

mitigation. Tank Foundations and Dikes consists of the cycled condensate storage tank 

foundations and dikes, clean condensate tank foundation, demineralized water tank foundation, 

well water storage tank foundation, and demineralized regenerative solution tank foundation. 

The cycled condensate storage tanks are supported by a circular reinforced concrete ring 

foundation pad with the tank bottom supported by a layer of clean sand on top of compacted 

structural backfill. The dike does not perform an intended function and is, therefore, not in 

scope for license renewal.
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The intended function of Tank Foundations and Dikes within the scope of license renewal 

includes the following:

• Provide physical support, shelter, and protection for SSCs relied on in safety analyses or 

plant evaluations to perform a function that demonstrates compliance with the 

Commission’s regulations for fire protection (10 CFR 50.48) (10 CFR 54.4(a)(3)).

LRA Table 2.4-12 identifies Tank Foundations and Dikes components within the scope of 

license renewal and subject to an AMR. The AMR results for these components are provided in 

LRA Table 3.5.2-12.

2.4.12.2 Staff Evaluation

The staff reviewed LRA Section 2.4.12; UFSAR Sections 1.2, 3.1, 4.6, 5.4, 6.1, and 9.2; UFSAR 

Table 3.2-1; and the license renewal boundary drawings using the evaluation methodology 

described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. The staff also 

reviewed UFSAR Section 3.8.4 to identify seismic Category I structures.

During its review, the staff evaluated the structure and component functions described in the 

LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal 

any SCs with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those SCs that the applicant has identified as being within the scope of license renewal to verify 

that it has not omitted any passive and long-lived components subject to an AMR in accordance 

with the requirements of 10 CFR 54.21(a)(1).

2.4.12.3 Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.4 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Tank Foundations and Dikes SCs within the scope of license 

renewal as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately 

identified the components subject to an AMR in accordance with the requirements in 

10 CFR 54.21(a)(1).

2.4.13 Turbine Building

2.4.13.1 Summary of Technical Information in the Application

LRA Section 2.4.13 states that the purpose of the Turbine Building is to provide structural 

support, shelter, and protection for nonsafety-related SSCs during normal plant operation and 

certain safety-related system components during both normal operations and during and 

following the safe shutdown earthquake seismic event. The Turbine Building is a multiple-story 

structure comprised of a reinforced concrete substructure supported on a reinforced concrete 

mat foundation on soil with a steel frame above the grade floor. The two 210-ton overhead 

cranes, one for each unit, service the turbine generators. The Turbine Building contains steam 

and power conversion system components and the support systems and components 

necessary to support fire protection and SBO. The Turbine Building superstructure is designed 

to withstand tornado loads on the exposed structural frame to prevent collapse. The building is 

classified as a nonsafety-related seismic Category II structure. With some architectural 

exceptions, the Turbine Building is in scope for license renewal in its entirety.
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The intended functions of the Turbine Building within the scope of license renewal include the 

following:

• Provide structural support or restraint to SSCs in the scope of license renewal

(10 CFR 54.4(a)(2)).

• Provide physical support, shelter, and protection for nonsafety-related SSCs whose 

failure could prevent satisfactory accomplishment of safety-related functions

(10 CFR 54.4(a)(2)).

• Provide physical support, shelter, and protection for SSCs relied on in safety analyses or 

plant evaluations to perform a function that demonstrates compliance with the 

Commission’s regulations for fire protection (10 CFR 50.48), EQ (10 CFR 50.49), and 

SBO (10 CFR 50.63) (10 CFR 54.4(a)(3)).

LRA Table 2.4-13 identifies the Turbine Building components within the scope of license 

renewal and subject to an AMR. The AMR results for these components are provided in LRA 

Table 3.5.2-13.

2.4.13.2 Staff Evaluation

The staff reviewed LRA Section 2.4.13; UFSAR Sections 1.1, 1.2, 2.4, 3.1, 3.3, 3.4, 7.7, 9.4, 

11.2, and 12.3; UFSAR Appendix J; UFSAR Table 3.2-1; UFSAR Figure 2.5-51; and the license 

renewal boundary drawings using the evaluation methodology described in SER Section 2.4

and the guidance in SRP-LR Section 2.4. The staff also reviewed UFSAR Section 3.8.4 to 

identify seismic Category I structures.

During its review, the staff evaluated the structure and component functions described in the 

LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal 

any SCs with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those SCs that the applicant has identified as being within the scope of license renewal to verify 

that it has not omitted any passive and long-lived components subject to an AMR in accordance 

with the requirements of 10 CFR 54.21(a)(1).

2.4.13.3 Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.4 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Turbine Building SCs within the scope of license renewal as required 

by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified the 

components subject to an AMR in accordance with the requirements in 10 CFR 54.21(a)(1).

2.4.14 Yard Structures

2.4.14.1 Summary of Technical Information in the Application

LRA Section 2.4.14 states that the purpose of Yard Structures is to provide structural support; 

shelter; and protection for nonsafety-related components and commodities, including 

components that supply power to safety-related equipment during emergency plant operating 

conditions and power to equipment relied on for post-fire safe shutdown or recovery from an 

SBO. Yard Structures include transformer foundations, trenches, light poles, transmission 
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towers, fire hose storage foundations, manholes, valve pits, duct banks, yard drainage, 

miscellaneous yard structures, and the meteorological tower.

The intended function of the Yard Structures within the scope of license renewal includes the 

following:

• Provide physical support, shelter, and protection for SSCs relied on in safety analyses or 

plant evaluations to perform a function that demonstrates compliance with the 

Commission’s regulations for fire protection (10 CFR 50.48) and SBO (10 CFR 50.63)

(10 CFR 54.4(a)(3)).

LRA Table 2.4-14 identifies Yard Structures components within the scope of license renewal 

and subject to an AMR. The AMR results for these components are provided in LRA 

Table 3.5.2-14.

2.4.14.2 Staff Evaluation

The staff reviewed LRA Section 2.4.14; UFSAR Sections 1.2, 2.4, 3.1, 8.2, 9.1, and 9.5; UFSAR 

Table 3.2-1 and Table 8.3-5; and the license renewal boundary drawings using the evaluation 

methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. The staff 

also reviewed UFSAR Section 3.8.4 to identify seismic Category I structures.

During its review, the staff evaluated the structure and component functions described in the 

LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal 

any SCs with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those SCs that the applicant has identified as being within the scope of license renewal to verify 

that it has not omitted any passive and long-lived components subject to an AMR in accordance 

with the requirements of 10 CFR 54.21(a)(1).

2.4.14.3 Conclusion

Based on the results of the staff’s evaluation discussed in SER Section 2.4 and on a review of 

the LRA, UFSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the Yard Structures SCs within the scope of license renewal as required 

by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified the 

components subject to an AMR in accordance with the requirements in 10 CFR 54.21(a)(1).

2.5 Scoping and Screening Results: Electrical

This section documents the staff’s review of the applicant’s scoping and screening results for 

electrical systems. Specifically, this section discusses electrical components and commodity 

groups.

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the 

applicant properly implemented its methodology, the staff’s review focused on the 

implementation results. This focus allowed the staff to confirm that there were no omissions of 

electrical and I&C system components that meet the scoping criteria and that are subject to an 

AMR.
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The staff’s evaluation of the information in the LRA was the same for all electrical and I&C 

systems. The objective was to determine whether the applicant has identified, in accordance 

with 10 CFR 54.4, “Scope,” components and supporting structures for electrical and I&C 

systems that meet the license renewal scoping criteria. Similarly, the staff evaluated the 

applicant’s screening results to verify that all passive, long-lived components were subject to an 

AMR in accordance with 10 CFR 54.21(a)(1).

In its scoping evaluation, the staff reviewed the applicable LRA sections, focusing on 

components that have not been identified as within the scope of license renewal. The staff 

reviewed the UFSAR for each electrical and I&C system to determine whether the applicant has 

omitted from the scope of license renewal components with intended functions delineated under 

10 CFR 54.4(a).

After its review of the scoping results, the staff evaluated the applicant’s screening results. 

For those SCs with intended functions, the staff sought to determine whether (1) the intended 

functions are performed with moving parts or a change in configuration or properties or (2) the 

SCs are subject to replacement after a qualified life or specified time period as described in 

10 CFR 54.21(a)(1). For those SCs meeting neither of these criteria, the staff sought to confirm 

that these SCs were subject to an AMR as required by 10 CFR 54.21(a)(1). The staff requested 

additional information to resolve any omissions or discrepancies identified.

2.5.1 Electrical Systems

2.5.1.1 Summary of Technical Information in the Application

LRA Section 2.5 describes the scoping and screening results for electrical systems. LSCS 

electrical systems were scoped per criteria in 10 CFR 54.4(a)(1), (a)(2), and (a)(3). A bounding 

scoping approach was used for electrical equipment. All electrical components within in-scope 

systems were included within the scope of license renewal. The results of the electrical 

systems scoping review are provided in LRA Table 2.2-1, “Plant Level Scoping Results.” In 

addition, electrical components, including certain switchyard components, credited to restore 

offsite power following an SBO are included within the scope of license renewal.

A bounding screening approach, as described in NEI 95-10 was used to assign electrical 

components in scope of license renewal to commodity groups. The commodities subject to an 

AMR were identified by applying the regulations at 10 CFR 54.21(a)(1)(i) and (ii). Electrical 

components in the SBO offsite power recovery path were identified based on their intended 

functions. A list of electrical components and commodities identified at LSCS is provided in 

LRA Section 2.5.2.1, “Identification of Electrical Commodities.” The list includes electrical 

components and commodities identified in NEI 95-10 Appendix B in addition to components and 

commodities added per NUREG-1800 Table 2.1-5.

The criterion of 10 CFR 54.21(a)(1)(i) was then applied to identify components and commodities 

that perform license renewal functions, as described in 10 CFR 54.4, “Scope,” without moving 

parts or without a change in configuration or properties (i.e., passive components). In the 

screening process, the following electrical commodities were determined not to have a license 

renewal intended function: cable tie wraps, fuse holders (not part of active equipment): metallic 

clamps, and uninsulated ground conductors. The fuse holder commodity includes both the 

insulation portion and the metallic clamp portion of the fuse holder. The insulation portion of the 

fuse holders was scoped as part of the “insulation material for electrical cables and connections”
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commodity. The metallic clamp portion of the fuse holders was scoped as a “fuse holder 

(not part of active equipment): metallic clamps” commodity.

The criterion of 10 CFR 54.21(a)(1)(ii) was applied to the electrical commodities that remained 

following application of the 10 CFR 50.21(a)(1)(i) criterion to exclude those commodities that are 

subject to replacement based on a qualified life or specified time period. The only electrical 

commodities identified for exclusion are electrical components and commodities included in the 

EQ Program. The remaining commodities (i.e., long-lived components), which are not in the EQ 

Program and which are not part of larger active components, require an AMR and are identified 

in LRA Table 2.5.2-1, “Electrical Commodities Subject to Aging Management Review,” along 

with their associated license renewal intended functions as follows:

• Cable Connections (Metallic Parts) – electrical continuity

• High Voltage Insulators – insulate (electrical)

• Insulation Material for Electrical Cables and Connections – insulate (electrical)

• Metal Enclosed Bus – electrical continuity, insulate (electrical), and shelter, protection

• Switchyard Bus and Connections – electrical continuity

• Transmission Conductors – electrical continuity

• Transmission Connectors – electrical continuity

Components supporting or interfacing with electrical components are assessed in the 

appropriate mechanical or structures sections. Components, such as cable trays, conduits, 

instrument racks, panels and enclosures, structures associated with switchyard circuit breakers, 

and the switchyard relay house, are assessed in LRA Section 2.4, “Scoping and Screening 

Results: Structures and Component Supports.” The shelter, protection, and pressure boundary 

intended functions of electrical penetrations are also addressed in LRA Section 2.4. Electrical 

components that have pressure boundary functions, such as elements, resistance temperature 

detectors, sensors, thermocouples, transducers, and electric heaters (housing), are addressed 

in the LRA Section 2.3, “Scoping and Screening Results: Mechanical.”

2.5.1.2 Staff Evaluation

The staff reviewed LRA Section 2.5; LRA Section 2.1.3.4, “Scoping for Regulated Events”

(SBO); and LSCS UFSAR Chapter 8 using the evaluation methodology described in SRP-LR

Section 2.5, “Scoping and Screening Results: Electrical and Instrumentation and Control 

Systems.”

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has not omitted from the scope of license renewal any electrical 

components with intended functions delineated under 10 CFR 54.4(a).

The regulation at 10 CFR 54.4(a)(3) requires that, all SSCs relied on in safety analyses or plant 

evaluation to perform a function that demonstrates compliance with NRC regulations for SBO 

(10 CFR 50.63), be included within the scope of license renewal. SRP-LR Section 2.5.2.1.1, 

“Components within the Scope of SBO (10 CFR 50.63),” provides the guidance to identify 

electrical systems components that are relied on to meet the requirements of the SBO rule for 

license renewal. This includes (1) the onsite power system meeting the requirements in

10 CFR 54.4 (a)(1) (safety-related systems), (2) equipment that is required to cope with an SBO 

(e.g., alternate AC power sources) meeting the requirements in 10 CFR 54.4(a)(3), and (3) the 

plant system portion of the offsite power system, including the electrical distribution equipment 

out to the first circuit breaker with the offsite distribution system (i.e., equipment in the 
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switchyard), that is used to connect the plant to the offsite power source meeting the 

requirements in 10 CFR 54.4(a)(3).

In addition, General Design Criterion 17, “Electric Power Systems,” of Appendix A, “General 

Design Criteria for Nuclear Power Plants,” to 10 CFR Part 50, “Domestic Licensing of 

Production and Utilization Facilities,” requires that electric power from the transmission network 

to the onsite electric distribution system is supplied by two physically independent circuits to 

minimize the likelihood of their simultaneous failure.

The SSCs that are relied on to meet the requirements of the SBO rule in both circuits are to be 

included within the scope of licensee renewal. In LRA Section 2.1.3.4, the applicant provided 

the LSCS SBO recovery boundary in Figure 2.1-2, “LaSalle SBO Recovery Boundary,” and 

components that are within the scope of license renewal on the plant side of the 

SBO boundaries.

LSCS satisfies the requirements of 10 CFR 50.63, “Loss of All Alternating Current Power,” as an 

AC-independent 4-hour coping plant. As stated in UFSAR Section 15.9.3.2, the 125 volts direct 

current (VDC) (Divisions 1 and 2) and 250-VDC Class 1E batteries are sized to provide SBO 

loads for 4 hours. The Class 1E batteries and associated safety-related equipment are included 

within the scope of license renewal as required by 10 CFR 54.4(a)(1).

An SBO power recovery is defined as the repowering of the plant AC distribution system from 

offsite sources or onsite emergency AC sources. For LSCS, two physically independent circuits 

are provided for each unit, one through the unit’s assigned system auxiliary transformer (SAT), 

and the other from the SAT of the other unit. The applicant included, within the scope of license 

renewal, the circuits between the Units 1 and 2 4,160-V engineered safety features buses up to 

and including the 345-kV circuit breakers supplying the SATs.

For Unit 1, as shown on LRA Figure 2.1-2, the circuits supplying power to the Divisions 1 and 2 

engineered safety features buses 141Y (142Y) consist of (1) the normal circuit from the 345-kV 

switchyard circuit breakers 11-13 and 1-13 through the SAT 142 and circuit breakers 1412 

(1422) and (2) the alternate circuit from the 345-kV switchyard circuit breakers 1-6 and 4-6 

through the SAT 242 and circuit breakers 2412 (2422) through unit tie breakers 2414 and 1414 

(2424 and 1424), respectively.

For Unit 2, as shown on LRA Figure 2.1-2, the circuits supplying power to the Divisions 1 and 2

engineered safety features buses 241Y (242Y) consist of (1) the normal circuit from the 345-kV 

switchyard circuit breakers 1-6 and 4-6 through the SAT 242 and circuit breakers 2412 (2422) 

and (2) the alternate circuit from the 345-kV switchyard circuit breakers 11-13 and 1-13 through 

the SAT 142 and circuit breaker 1412 (1422) through unit tie breakers 1414 and 2414 (1424 and 

2424), respectively.

The switchyard bus and connections, control circuits and structures associated with the 

switchyard circuit breakers, the switchyard relay house, transmission conductors and 

connections, high-voltage insulators, and metal enclosed bus, within the SBO recovery 

boundaries are also included within the scope of license renewal. Components that are subject 

to an AMR are included in LRA Table 2.5.2-1. Based on the review of the SBO scoping 

information, the staff concludes that the scoping is consistent with the guidance in 

SRP-LR Section 2.5.2.1.1.
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The staff then reviewed those electrical and I&C components and commodities that the 

applicant identified as being within the scope of license renewal to verify that the applicant has 

not omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

The applicant did not include cable tie-wraps in the electrical commodity groups subject to an 

AMR because cable tie-wraps do not have a license renewal intended function at LSCS. 

The applicant stated that LSCS has no current license basis requirements that cable tie-wraps 

must remain functional during and following DBEs and that cable tie-wraps are not credited in 

the LSCS design basis in terms of any 10 CFR 54.4, “Scope,” intended function. The applicant 

clarified that cable tie-wraps are used to bundle wires and cables together to keep the wire and 

cable runs neat and to restrain cables and wires to facilitate cable installation and maintenance 

at LSCS. Based on the review of this information and the LSCS UFSAR, the staff finds that the 

exclusion of cable tie-wraps from the electrical commodity groups subject to an AMR is 

acceptable.

The applicant did not include Fuse Holders (Not Part of Active Equipment): Metallic Clamps in 

the electrical commodities subject to an AMR because, based on a systematic review performed 

using plant documents, controlled drawings, and the plant equipment database, the metallic 

clamps portion of LSCS fuse holders were either installed in active equipment or did not perform 

a license renewal intended function. Based on the review of this information, the staff finds that 

the exclusion of Fuse Holders (Not Part of Active Equipment): Metallic Clamps from the 

electrical commodities subject to an AMR is acceptable.

The applicant did not include uninsulated ground conductors in the electrical commodity groups 

subject to an AMR because uninsulated ground conductors do not perform a license renewal 

intended function at LSCS. The applicant clarified that uninsulated ground conductors are 

provided for equipment and personnel protection. The staff reviewed the UFSAR and found that 

uninsulated ground conductors are not credited in the LSCS design basis. Therefore, the staff 

concludes that the exclusion of uninsulated ground conductors from the electrical commodity 

groups subject to an AMR is acceptable.

2.5.1.3 Conclusion

The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify any 

SSCs within the scope of license renewal. In addition, the staff’s review determined whether the 

applicant failed to identify any components subject to an AMR. The staff finds no such 

omissions. On the basis of its review, the staff concludes that there is reasonable assurance 

that the applicant has adequately identified the electrical and I&C systems components within 

the scope of license renewal as required by 10 CFR 54.4(a) and those subject to an AMR as 

required by 10 CFR 54.21(a)(1).

2.6 Conclusion for Scoping and Screening

The staff reviewed the information in LRA Section 2, “Scoping and Screening Methodology for 

Identifying Structures and Components Subject to Aging Management Review and 

Implementation Results,” and determines that (1) the applicant’s scoping and screening 
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methodology was consistent with 10 CFR 54.21(a)(1) and the staff’s positions on the treatment 

of safety-related and nonsafety-related SSCs within the scope of license renewal and (2) the 

applicant’s determination of SCs subject to an AMR is consistent with the requirements of 

10 CFR 54.4 and 10 CFR 54.21(a)(1).

On the basis of its review, the staff concludes that the applicant has adequately identified those 

systems and components within the scope of license renewal as required by 10 CFR 54.4(a) 

and those subject to an AMR as required by 10 CFR 54.21(a)(1).

3-1

AGING MANAGEMENT REVIEW RESULTS

This section of the safety evaluation report (SER) evaluates aging management programs 

(AMPs) and aging management reviews (AMRs) for LaSalle County Station, Units 1 and 2 

(LSCS), by the staff of the United States (U.S.) Nuclear Regulatory Commission (NRC) (the 

staff).

In Appendix B to its license renewal application (LRA), as amended during the review, Exelon 

Generation Company, LLC (Exelon or the applicant), described the 46 AMPs that it relies on to 

manage or monitor the aging of passive, long-lived structures and components (SCs).

In LRA Section 3, the applicant provided the results of the AMRs for those SCs identified in LRA 

Section 2 as within the scope of license renewal and subject to an AMR.

3.0 Applicant’s Use of the Generic Aging Lessons Learned Report

In preparing its LRA, the applicant credited NUREG-1801, Revision 2, “Generic Aging Lessons 

Learned (GALL) Report,” dated December 2010. The GALL Report contains the staff’s generic 

evaluation of the existing plant programs and documents the technical basis for determining 

where existing programs are adequate without modification and where existing programs should 

be augmented for the period of extended operation. The evaluation results documented in the 

GALL Report indicate that many of the existing programs are adequate to manage the aging 

effects for particular license renewal SCs. The GALL Report also contains recommendations on 

specific areas for which existing programs should be augmented for license renewal. An 

applicant may reference the GALL Report in its LRA to demonstrate that its programs 

correspond to those reviewed and approved in the report.

The purpose of the GALL Report is to provide a summary of staff-approved AMPs to manage or 

monitor the aging of SCs subject to an AMR. If an applicant commits to implementing these 

staff-approved AMPs, the time, effort, and resources for LRA review will be greatly reduced, 

improving the efficiency and effectiveness of the license renewal review process. The 

GALL Report also serves as a quick reference for applicants and staff reviewers to AMPs and 

activities that the staff has determined will adequately manage or monitor aging during the 

period of extended operation.

The GALL Report identifies (1) systems, structures, and components (SSCs), (2) SC materials, 

(3) environments to which the SCs are exposed, (4) the aging effects of the materials and 

environments, (5) the AMPs credited with managing or monitoring the aging effects, and 

(6) recommendations for further applicant evaluations of aging management for certain 

component types.

The staff’s review was in accordance with Title 10 of the Code of Federal Regulations, Part 54, 

“Requirements for Renewal of Operating Licenses for Nuclear Power Plants” (10 CFR Part 54); 

the guidance in NUREG-1800, Revision 2, “Standard Review Plan for Review of License 

Renewal Applications for Nuclear Power Plants” (SRP-LR), dated December 2010; and the 

GALL Report.
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In addition to its review of the LRA, the staff conducted an onsite audit of selected AMPs during 

the weeks of March 30, 2015, and April 13, 2015. The onsite audits are designed for maximum 

efficiency of the staff’s LRA review. The applicant can respond to questions, the staff can 

readily evaluate the applicant’s responses, the need for formal correspondence between the 

staff and the applicant is reduced, and the result is an improvement in review efficiency.

3.0.1 Format of the License Renewal Application

The applicant submitted an application that is structured in accordance with Regulatory Guide 

(RG) 1.188, “Standard Format and Content for Applications to Renew Nuclear Power Plant 

Operating Licenses,” Revision 1, dated September 2005, and Nuclear Energy Institute (NEI) 

95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54 – The License 

Renewal Rule,” Revision 6, dated June 2005. The organization of LRA Section 3 parallels that 

of SRP-LR Chapter 3. LRA Section 3 presents AMR results information in the following two 

table types:

(1) Table 1’s: Table 3.x.1, where “3” indicates the LRA section number, “x” indicates the 

subsection number from the GALL Report, and “1” indicates that this table type is the 

first in LRA Section 3.

(2) Table 2’s: Table 3.x.2-y, where “3” indicates the LRA section number, “x” indicates the 

subsection number from the GALL Report, “2” indicates that this table type is the second 

in LRA Section 3, and “y” indicates the system table number.

In its Table 1’s, the applicant summarized the portions of the application that it considered to be 

consistent with the GALL Report. In its Table 2’s, the applicant identified the linkage between 

the scoping and screening results in LRA Section 2 and the AMRs in LRA Section 3.

3.0.1.1 Overview of Table 1’s

Each Table 3.x.1 (Table 1) provides a summary comparison of how the facility aligns with the 

corresponding tables in the GALL Report. The tables are essentially the same as summary 

Tables 3.1-1 through 3.6-1 in the SRP-LR, except that the “ID” column is named “Item Number,” 

the “Type” column has been deleted because it is not necessary, and the “Rev2 Item” and 

“Rev1 Item” columns have been replaced by a “Discussion” column. The “Item Number” column 

is a means for the staff reviewer to cross-reference Table 2’s with Table 1’s. In the “Discussion” 

column, the applicant provided clarifying information. The following are examples of information 

that might be contained within this column:

• further evaluation recommended (information or reference to where that information is 

located)

• the name of a plant-specific program

• exceptions to the GALL Report assumptions

• discussion of how the item is consistent with the corresponding item in the GALL Report

when the consistency may not be obvious

• discussion of how the item is different from the corresponding item in the GALL Report

(e.g., when an exception is taken to a GALL Report AMP)

The format of each Table 1 allows the staff to align a specific row in the table with the 

corresponding SRP-LR table row so that consistency can be checked easily.
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3.0.1.2 Overview of Table 2’s

Each Table 2 provides the detailed results of the AMRs for components identified in LRA 

Section 2 as subject to an AMR. The LRA has a Table 2 for each of the systems or structures 

within a specific system grouping (e.g., Reactor Vessel, Internals, and Reactor Coolant System; 

Engineered Safety Features; Auxiliary Systems). For example, the Reactor Vessel, Internals 

and Reactor Coolant System group has tables specific to the Reactor Coolant Pressure 

Boundary System (Table 3.1.2–1), the Reactor Vessel (Table 3.1.2–2), and the Reactor Vessel 

Internals System (Table 3.1.2–3). Each Table 2 consists of nine columns:

(1) Component Type – The first column lists LRA Section 2 component types subject to an 

AMR in alphabetical order.

(2) Intended Function – The second column identifies the license renewal intended 

functions, including abbreviations, where applicable, for the listed component types. 

Definitions and abbreviations of intended functions are in LRA Table 2.1-1.

(3) Material – The third column lists the particular construction material(s) for the component 

type.

(4) Environment – The fourth column lists the environments to which the component types 

are exposed. Internal and external service environments are indicated with a list of 

these environments in LRA Table 3.0-1.

(5) Aging Effect Requiring Management – The fifth column lists aging effects requiring 

management (AERMs). As part of the AMR process, the applicant determined any 

AERMs for each combination of material and environment.

(6) Aging Management Programs – The sixth column lists the AMPs that the applicant uses 

to manage the identified aging effects.

(7) NUREG–1801 Item – The seventh column lists the GALL Report item(s) identified in the 

LRA as similar to the AMR results. The applicant compared each combination of 

component type, material, environment, AERM, and AMP in LRA Table 2 with the 

GALL Report items. If there are no corresponding items in the GALL Report, the 

applicant leaves the column blank.

(8) Table 1 Item – The eighth column lists the corresponding summary item number from

the LRA Table 1’s. If the applicant identifies in each LRA Table 2 AMR results 

consistent with the GALL Report, the Table 1 item summary number should be listed in 

LRA Table 2. If there is no corresponding item in the GALL Report, column eight is left 

blank. In this manner, the information from the two tables can be correlated.

(9) Notes – The ninth column lists the corresponding notes used to identify how the 

information in each Table 2 aligns with the information in the GALL Report. The notes, 

identified by letters, were developed by an NEI working group and will be used in future 

LRAs. Any plant-specific notes identified by numbers provide additional information 

about the consistency of the item with the GALL Report.

3.0.2 Staff’s Review Process

The staff conducted three types of evaluations of the AMRs and AMPs:

(1) For items that the applicant stated are consistent with the GALL Report, the staff 

conducted either an audit or a technical review to determine consistency.
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(2) For items that the applicant stated are consistent with the GALL Report with exceptions, 

enhancements, or both, the staff conducted either an audit or a technical review of the 

item to determine consistency. In addition, the staff conducted a technical review of the 

applicant’s technical justifications for the exceptions or the adequacy of the 

enhancements.

The SRP-LR states that an applicant may take one or more exceptions to specific 

GALL Report AMP elements; however, any exception to the GALL Report AMP should 

be described and justified. Therefore, the staff considers exceptions as being portions of 

the GALL Report AMP that the applicant does not intend to implement.

In some cases, an applicant may choose an existing plant program that does not meet 

all the program elements defined in the GALL Report AMP. However, the applicant may 

make a commitment to augment the existing program to satisfy the GALL Report AMP

before the period of extended operation. Therefore, the staff considers these 

augmentations or additions to be enhancements. Enhancements include, but are not 

limited to, activities needed to ensure consistency with the GALL Report

recommendations. Enhancements may expand but not reduce the scope of an AMP.

(3) For other items, the staff conducted a technical review to verify conformance with 

10 CFR 54.21(a)(3) requirements.

The staff’s audits and technical reviews of the applicant’s AMPs and AMRs determine whether 

the aging effects on SCs can be adequately managed to maintain their intended function(s) 

consistent with the plant’s current licensing basis (CLB) for the period of extended operation, as 

required by 10 CFR Part 54, “Requirements for Renewal of Operating Licenses for Nuclear 

Power Plants.”

3.0.2.1 Review of Aging Management Programs

For AMPs for which the applicant claimed consistency with the GALL Report AMPs, the staff 

conducted either an audit or a technical review to verify the claim. For each AMP with one or 

more exceptions, the staff evaluated each exception to determine whether the exception was 

acceptable and whether the modified AMP would adequately manage the aging effect(s) for 

which it was credited. For AMPs that were not evaluated in the GALL Report, the staff 

performed a full review to determine their adequacy. The staff evaluated the AMPs against the 

following 10 program elements defined in SRP-LR Appendix A:

(1) Scope of Program – Scope of the program should include the specific SCs subject to an 

AMR for license renewal.

(2) Preventive Actions – Preventive actions should prevent or mitigate aging degradation.

(3) Parameters Monitored or Inspected – Parameters monitored or inspected should be 

linked to the degradation of the particular structure or component intended function(s).

(4) Detection of Aging Effects – Detection of aging effects should occur before there is a 

loss of structure or component intended function(s). This includes aspects such as 

method or technique (i.e., visual, volumetric, surface inspection), frequency, sample 

size, data collection, and timing of new/one-time inspections to ensure timely detection 

of aging effects.

(5) Monitoring and Trending – Monitoring and trending should provide predictability of the 

extent of degradation, as well as timely corrective or mitigative actions.
3-5

(6) Acceptance Criteria – Acceptance criteria, against which the need for corrective action 

will be evaluated, should ensure that the structure or component intended function(s) are 

maintained under all CLB design conditions during the period of extended operation.

(7) Corrective Actions – Corrective actions, including root cause determination and 

prevention of recurrence, should be timely.

(8) Confirmation Process – Confirmation process should ensure that preventive actions are 

adequate and that appropriate corrective actions have been completed and are effective.

(9) Administrative Controls – Administrative controls should provide for a formal review and 

approval process.

(10) Operating Experience – Operating experience of the AMP, including past corrective

actions resulting in program enhancements or additional programs, should provide 

objective evidence to support the conclusion that the effects of aging will be adequately 

managed so that the SC intended function(s) will be maintained during the period of 

extended operation.

Details of the staff’s audit evaluation of program elements 1 through 6 and 10 are documented 

in SER Section 3.0.3.

The staff reviewed the applicant’s quality assurance (QA) program and documented its 

evaluations in SER Section 3.0.4. The staff’s evaluation of the QA program included 

assessment of the “corrective actions,” “confirmation process,” and “administrative controls” 

program elements.

The staff reviewed the information on the “operating experience” program element and 

documented its evaluation in SER Sections 3.0.3 and 3.0.5.

3.0.2.2 Review of AMR Results

Each LRA Table 2 contains information concerning whether the AMRs identified by the 

applicant align with the GALL Report AMRs. For a given AMR in a Table 2, the staff reviewed 

the intended function, material, environment, AERM, and AMP combination for a particular 

system component type. Item numbers in column seven of the LRA, “NUREG–1801 Vol. 2 

Item,” correlate to an AMR combination as identified in the GALL Report. A blank in column 

seven indicates that the applicant was unable to identify an appropriate correlation in the 

GALL Report. The staff also conducted a technical review of combinations not consistent with 

the GALL Report. The next column, “Table 1 Item,” refers to a number indicating the correlating 

row in Table 1.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which it does not recommend further evaluation, the staff’s review 

determined whether the plant-specific components of these GALL Report component groups 

were bounded by the GALL Report evaluation.

The applicant noted for each AMR item how the information in the tables aligns with the 

information in the GALL Report. The staff audited those AMRs with notes A through E 

indicating how the AMR is consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 
3-6

The staff audited these items to verify consistency with the GALL Report and validity of the AMR 

for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the GALL Report 

AMP. The staff audited these items to verify consistency with the GALL Report and verified that 

the identified exceptions to the GALL Report AMPs have been reviewed and accepted. The 

staff also determined whether the applicant’s AMP was consistent with the GALL Report 

AMP and whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR item, although different from that in the 

GALL Report, is consistent with that in the GALL Report for material, environment, and aging 

effect. In addition, the AMP is consistent with the GALL Report AMP. This note indicates that 

the applicant was unable to find a listing of some system components in the GALL Report; 

however, the applicant identified in the GALL Report a different component with the same 

material, environment, aging effect, and AMP as the component under review. The staff audited 

these items to verify consistency with the GALL Report. The staff also determined whether the 

AMR item of the different component was applicable to the component under review and 

whether the AMR was valid for the site-specific conditions.

Note D indicates that the component for the AMR item, although different from that in the 

GALL Report, is consistent with that in the GALL Report for material, environment, and aging 

effect. In addition, the AMP takes some exceptions to the GALL Report AMP. The staff audited 

these items to verify consistency with the GALL Report. The staff verified whether the AMR 

item of the different component was applicable to the component under review and whether the 

identified exceptions to the GALL Report AMPs have been reviewed and accepted. The staff 

also determined whether the applicant’s AMP was consistent with the GALL Report AMP and 

whether the AMR was valid for the site-specific conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect but credits a different AMP. The staff audited these items to 

verify consistency with the GALL Report. The staff also determined whether the credited AMP 

would manage the aging effect consistently with the GALL Report AMP and whether the AMR 

was valid for the site-specific conditions.

3.0.2.3 UFSAR Supplement

Consistent with the SRP-LR for the AMRs and AMPs that it reviewed, the staff also reviewed 

the updated final safety analysis report (UFSAR) supplement, which summarizes the applicant’s 

programs and activities for managing aging effects for the period of extended operation, as 

required by 10 CFR 54.21(d).

3.0.2.4 Documentation and Documents Reviewed

In its review, the staff used the LRA, LRA supplements, SRP-LR, and the GALL Report. During 

the onsite audit, the staff also examined the applicant’s justifications to verify that the applicant’s 

activities and programs will adequately manage the effects of aging on SCs. The staff also 

conducted detailed discussions and interviews with the applicant’s license renewal project 

personnel and others with technical expertise relevant to aging management.
3-7

3.0.3 Aging Management Programs

SER Table 3.0-1 presents the AMPs credited by the applicant and described in LRA 

Appendix B. The table also indicates the GALL Report AMP with which the applicant claimed 

consistency and shows the section of this SER in which the staff’s evaluation of the program is 

documented.

LSCS Aging Management Programs

Applicant AMP LRA 

Sections

New or 

Existing 

Program

LRA Initial 

Comparison to 

the GALL 

Report

GALL Report AMPs

SER Section

(Disposition)

ASME Section XI 

Inservice Inspection, 

Subsections IWB, IWC, 

and IWD

A.2.1.1

B.2.1.1

Existing Consistent XI.M1, “ASME Section XI 

Inservice Inspection, 

Subsections IWB, IWC, and 

IWD”

3.0.3.1.1

(Consistent)

Water Chemistry A.2.1.2

B.2.1.2

Existing Consistent with 

Exception

XI.M2, “Water Chemistry” 3.0.3.2.1

(Consistent with 

Exception)

Reactor Head Closure 

Stud Bolting

A.2.1.3

B.2.1.3

Existing Consistent with 

Exceptions

XI.M3, “Reactor Head 

Closure Stud Bolting”

3.0.3.2.2

(Consistent with 

Exceptions)

BWR Vessel ID 

Attachment Welds

A.2.1.4

B.2.1.4

Existing Consistent XI.M4, “BWR Vessel ID 

Attachment Welds”

3.0.3.1.2

(Consistent)

BWR Feedwater 

Nozzle

A.2.1.5

B.2.1.5

Existing Consistent XI.M5, “BWR Feedwater 

Nozzle”

3.0.3.1.3

(Consistent)

BWR Control Rod Drive 

Return Line Nozzle

A.2.1.6

B.2.1.6

Existing Consistent XI.M6, “BWR Control Rod 

Drive Return Line Nozzle”

3.0.3.1.4

(Consistent)

BWR Stress Corrosion 

Cracking

A.2.1.7

B.2.1.7

Existing Consistent XI.M7, “BWR Stress 

Corrosion Cracking”

3.0.3.1.5

(Consistent)

BWR Penetrations A.2.1.8

B.2.1.8

Existing Consistent XI.M8, “BWR Penetrations” 3.0.3.1.6

(Consistent)

BWR Vessel Internals A.2.1.9

B.2.1.9

Existing Consistent with 

Enhancements

XI.M9, “BWR Vessel 

Internals”

3.0.3.2.3

(Consistent with 

Enhancements)

Flow-Accelerated 

Corrosion

A.2.1.10

B.2.1.10

Existing Consistent XI.M17, “Flow-Accelerated 

Corrosion”

3.0.3.1.7

(Consistent with 

Exception)

Bolting Integrity A.2.1.11

B.2.1.11

Existing Consistent with 

Enhancements

XI.M18, “Bolting Integrity” 3.0.3.2.4

(Consistent with 

Enhancements)

Open-Cycle Cooling 

Water System

A.2.1.12

B.2.1.12

Existing Consistent with 

Enhancements

XI.M20, “Open-Cycle 

Cooling Water System”

3.0.3.2.5

(Consistent with 

Enhancements)

Closed Treated Water 

Systems

A.2.1.13

B.2.1.13

Existing Consistent with 

Enhancement

XI.M21A, “Closed Treated 

Water Systems”

3.0.3.2.6

(Consistent with 

Enhancements)

Inspection of Overhead 

Heavy Load and Light 

Load (Related to 

Refueling) Handling 

Systems

A.2.1.14

B.2.1.14

Existing Consistent with 

Enhancement

XI.M23, “Inspection of 

Overhead Heavy Load and 

Light Load (Related to 

Refueling) Handling 

Systems”

3.0.3.2.7

(Consistent with 

Enhancement)
3-8

Applicant AMP LRA 

Sections

New or 

Existing 

Program

LRA Initial 

Comparison to 

the GALL 

Report

GALL Report AMPs

SER Section

(Disposition)

Compressed Air 

Monitoring

A.2.1.15

B.2.1.15

Existing Consistent with 

Exception and 

Enhancements

XI.M24, “Compressed Air 

Monitoring”

3.0.3.2.8

(Consistent with 

Exception and 

Enhancements)

Fire Protection A.2.1.16

B.2.1.16

Existing Consistent with 

Enhancements

XI.M26, “Fire Protection” 3.0.3.2.9

(Consistent with 

Enhancements)

Fire Water System A.2.1.17

B.2.1.17

Existing Consistent with 

Exceptions and 

Enhancements

XI.M27, “Fire Water 

System”

3.0.3.2.10

(Consistent with 

Exceptions and 

Enhancements)

Aboveground Metallic 

Tanks

A.2.1.18

B.2.1.18

Existing Consistent with 

Enhancements

XI.M29, “Aboveground 

Metallic Tanks”

3.0.3.2.11

(Consistent with 

Enhancements)

Fuel Oil Chemistry A.2.1.19

B.2.1.19

Existing Consistent with 

Enhancements

XI.M30, “Fuel Oil Chemistry” 3.0.3.2.12

(Consistent with 

Enhancements)

Reactor Vessel 

Surveillance

A.2.1.20

B.2.1.20

Existing Consistent XI.M31, “Reactor Vessel 

Surveillance”

3.0.3.1.8

(Consistent with 

Exception and 

Enhancements)

One-Time Inspection A.2.1.21

B.2.1.21

New Consistent XI.M32, “One-Time 

Inspection”

3.0.3.1.9

(Consistent)

Selective Leaching A.2.1.22

B.2.1.22

New Consistent XI.M33, “Selective 

Leaching”

3.0.3.1.10

(Consistent)

Unit 1 One-time 

Inspection of ASME 

Code Class 1 

Small-Bore Piping

A.2.1.23

B.2.1.23

New Consistent XI.M35, “One-time 

Inspection of ASME Code 

Class 1 Small Bore-Piping”

3.0.3.1.11

(Consistent)

External Surfaces 

Monitoring of 

Mechanical 

Components

A.2.1.24

B.2.1.24

New Consistent XI.M36, “External Surfaces 

Monitoring of Mechanical 

Components”

3.0.3.1.12

(Consistent)

Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components

A.2.1.25

B.2.1.25

New Consistent XI.M38, “Inspection of 

Internal Surfaces in 

Miscellaneous Piping and 

Ducting Components”

3.0.3.1.13

(Consistent)

Lubricating Oil Analysis A.2.1.26

B.2.1.26

Existing Consistent XI.M39, “Lubricating Oil 

Analysis”

3.0.3.1.14

(Consistent)

Monitoring of 

Neutron-Absorbing 

Materials Other Than 

Boraflex

A.2.1.27

B.2.1.27

Existing Consistent with 

Enhancement

XI.M40, “Monitoring of 

Neutron-Absorbing 

Materials Other than 

Boraflex”

3.0.3.2.13

(Consistent with 

Enhancement)

Buried and 

Underground Piping

A.2.1.28

B.2.1.28

Existing Consistent with 

Enhancements

XI.M41, “Buried and 

Underground Piping and 

Tanks”

3.0.3.2.14

(Consistent with 

Enhancements)

ASME Section XI, 

Subsection IWE

A.2.1.29

B.2.1.29

Existing Consistent with 

Enhancements

XI.S1, “ASME Section XI, 

Subsection IWE”

3.0.3.2.15

(Consistent with 

Enhancements)
3-9

Applicant AMP LRA 

Sections

New or 

Existing 

Program

LRA Initial 

Comparison to 

the GALL 

Report

GALL Report AMPs

SER Section

(Disposition)

ASME Section XI, 

Subsection IWL

A.2.1.30

B.2.1.30

Existing Consistent with 

Enhancements

XI.S2, “ASME Section XI, 

Subsection IWL”

3.0.3.2.16

(Consistent with 

Enhancements)

ASME Section XI, 

Subsection IWF

A.2.1.31

B.2.1.31

Existing Consistent with 

Enhancements

XI.S3, “ASME Section XI, 

Subsection IWF”

3.0.3.2.17

(Consistent with 

Enhancements)

10 CFR Part 50, 

Appendix J

A.2.1.32

B.2.1.32

Existing Consistent XI.S4, “10 CFR Part 50, 

Appendix J”

3.0.3.1.15

(Consistent)

Masonry Walls A.2.1.33

B.2.1.33

Existing Consistent with 

Enhancements

XI.S5, “Masonry Walls” 3.0.3.2.18

(Consistent with 

Enhancements)

Structures Monitoring A.2.1.34

B.2.1.34

Existing Consistent with 

Enhancements

XI.S6, “Structures 

Monitoring”

3.0.3.2.19

(Consistent with 

Enhancements)

RG 1.127, Inspection of 

Water-Control 

Structures Associated 

with Nuclear Power 

Plants

A.2.1.35

B.2.1.35

Existing Consistent with 

Enhancements

XI.S7, “RG 1.127, 

Inspection of Water-Control 

Structures Associated with 

Nuclear Power Plants”

3.0.3.2.20

(Consistent with 

Enhancements)

Protective Coating 

Monitoring and 

Maintenance Program

A.2.1.36

B.2.1.36

Existing Consistent XI.S8, “Protective Coating 

Monitoring and Maintenance 

Program”

3.0.3.1.16

(Consistent)

Insulation Material for 

Electrical Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

A.2.1.37

B.2.1.37

New Consistent XI.E1, “Insulation Material 

for Electrical Cables and 

Connections Not Subject to 

10 CFR 50.49 

Environmental Qualification 

Requirements”

3.0.3.1.17

(Consistent)

Insulation Material for 

Electrical Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements Used in 

Instrumentation Circuits

A.2.1.38

B.2.1.38

New Consistent XI.E2, “Insulation Material 

for Electrical Cables and 

Connections Not Subject to 

10 CFR 50.49 

Environmental Qualification 

Requirements Used in 

Instrumentation Circuits”

3.0.3.1.18

(Consistent)

Inaccessible Power 

Cables Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

A.2.1.39

B.2.1.39

New Consistent XI.E3, “Inaccessible Power 

Cables Not Subject to 

10 CFR 50.49 

Environmental Qualification 

Requirements”

3.0.3.1.19

(Consistent)

Metal Enclosed Bus A.2.1.40

B.2.1.40

Existing Consistent with 

Enhancements

XI.E4, “Metal-Enclosed Bus” 3.0.3.2.21

(Consistent with 

Enhancements)
3-10

Applicant AMP LRA 

Sections

New or 

Existing 

Program

LRA Initial 

Comparison to 

the GALL 

Report

GALL Report AMPs

SER Section

(Disposition)

Electrical Cable 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

A.2.1.41

B.2.1.41

New Consistent XI.E6, “Electrical Cable 

Connections Not Subject to 

10 CFR 50.49 

Environmental Qualification 

Requirements”

3.0.3.1.20

(Consistent)

Service Level III and 

Service Level III 

Augmented Coatings 

Monitoring and 

Maintenance Program

A.2.2.1

B.2.2.1

New Plant-Specific XI.M42, “Internal 

Coatings/Linings for InScope Piping, Piping 

Components, Heat 

Exchangers, and Tanks”

3.0.3.3.1

Plant Specific

Unit 2 Inspection of 

ASME Code Class 1 

Small-Bore Piping 

Program

A.2.2.2

B.2.2.2

New Plant-Specific N/A 3.0.3.3.2

Plant Specific

Fatigue Monitoring A.3.1.1

B.3.1.1

Existing Consistent with 

Enhancements

X.M1, “Fatigue Monitoring” 3.0.3.2.22

(Consistent with 

Enhancements)

Concrete Containment 

Tendon Prestress

A.3.1.2

B.3.1.2

Existing Consistent with 

Enhancement

X.S1, “Concrete 

Containment Tendon 

Prestress”

3.0.3.2.23

(Consistent with 

Enhancement)

Environmental 

Qualification (EQ) of 

Electric Components

A.3.1.3

B.3.1.3

Existing Consistent X.E1, “Environmental 

Qualification (EQ) of 

Electrical

Components”

3.0.3.1.21

(Consistent)

3.0.3.1 AMPs Consistent with the GALL Report

In LRA Appendix B, the applicant identified the following AMPs as consistent with the 

GALL Report:

• ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

• BWR Vessel ID Attachment Welds

• BWR Feedwater Nozzle

• BWR Control Rod Drive Return Line Nozzle

• BWR Stress Corrosion Cracking

• BWR Penetrations

• Flow-Accelerated Corrosion

• Reactor Vessel Surveillance

• One-Time Inspection

• Selective Leaching

• Unit 1 One-time Inspection of ASME Code Class 1 Small-Bore Piping

• External Surfaces Monitoring of Mechanical Components
3-11

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

• Lubricating Oil Analysis

• 10 CFR Part 50, Appendix J

• Protective Coating Monitoring and Maintenance Program

• Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements

• Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Used in Instrumentation Circuits

• Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements

• Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements

• Environmental Qualification (EQ) of Electric Components

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

Summary of Technical Information in the Application. LRA Section B.2.1.1 describes the 

applicant’s existing ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

program, as consistent with GALL Report AMP XI.M1, “ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD.” The LRA states that the program manages cracking and 

loss of fracture toughness for American Society of Mechanical Engineers (ASME) Code 

Class 1, 2, and 3 piping and components exposed to reactor coolant environment. The LRA 

also states that the program includes periodic visual, surface, and volumetric examinations of 

ASME Code Class 1, 2, and 3 piping and components. The LRA further states that the program 

performs these examinations in accordance with ASME Code Section XI ISI, Subsections IWB, 

IWC, and IWD.

In addition, the LRA states that currently the program is in its third 10-year inspection interval, 

using the 2001 Edition through 2003 Addenda of the ASME Code and Risk-Informed Inservice 

Inspection (RI-ISI) alternatives for examination categories B-F, B-J, C-F-1, and C-F-2 for ASME 

Code Class 1 and 2 piping welds (as approved by relief request). The LRA further states that 

the program is updated every 10-year inspection interval to the latest ASME Code Edition and 

Addenda approved by the NRC in 10 CFR 50.55a, 12 months before the start of the interval. 

The LRA states that the program is consistent with the program described in the GALL Report, 

Section XI.M1, “ASME Section XI, Inservice Inspection, Subsections IWB, IWC, and IWD.”

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M1. Based on its audit, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M1.

Operating Experience. LRA Section B.2.1.1 summarizes operating experience related to the 

applicant’s ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program. 

LRA states that in 2004, Unit 1 core spray piping welds internal to the reactor vessel were 

inspected using ultrasonic test (UT) examinations. The applicant stated that, as a result of 
3-12

these examinations, three welds were determined to have five indications. The applicant also 

stated that these indications were evaluated as acceptable for one operating cycle; 

re-examinations in 2006 did not reveal any changes. The applicant further stated that 

subsequent examinations in 2008 determined that the indications in two of the welds were 

geometric reflections. The applicant stated that the remaining weld was examined again in 

2012 with no notable changes to the indication and was determined to be acceptable for two 

additional operating cycles by evaluation. The applicant stated that the core spray piping welds 

for Unit 2 have also been inspected by volumetric examination with no recorded indications.

The applicant stated that, in 2005, surface examinations performed on Unit 2 using magnetic 

particle examinations revealed several indications, which did not meet the acceptance criteria of 

ASME Code Section XI, Subsections IWC-3500 and IWB-3500. The applicant also stated that

the indications, which were in pipe base metal (near a lug weld), were completely removed as 

part of its corrective actions. The applicant further stated that subsequent to flaw removal, 

volumetric examination was performed to verify acceptable pipe wall thickness.

The applicant stated that the program is informed by plant-specific and industry operating 

experience and that it is enhanced as needed. The applicant also stated that there is 

confidence that the program will continue to be effectively implemented and that it will continue 

to identify degradation before failure and loss of intended function during the period of extended 

operation.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M1 was evaluated.

UFSAR Supplement. LRA Section A.2.1.1 provides the UFSAR supplement for the ASME 

Section XI ISI, Subsections IWB, IWC, and IWD program. The staff reviewed this UFSAR 

supplement description of the program and noted that it is consistent with the recommended 

description in SRP-LR Table 3.0-1. The staff also noted that the applicant committed to ongoing 

implementation of the existing ASME Section XI ISI, Subsections IWB, IWC, and IWD program 

for managing the effects of aging for applicable components during the period of extended 

operation. The staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s ASME Section XI ISI, 

Subsections IWB, IWC, and IWD program, the staff concludes that those program elements for 

which the applicant claimed consistency with the GALL Report are consistent. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 
3-13

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

BWR Vessel ID Attachment Welds

Summary of Technical Information in the Application. LRA Section B.2.1.4 describes the 

applicant’s existing BWR Vessel ID Attachment Welds program as a condition monitoring 

program consistent with GALL Report AMP XI.M4, “BWR Vessel ID Attachment Welds.” The 

LRA states that the program performs condition monitoring by in-vessel examinations through 

the station’s augmented inservice inspections. The inspections are performed in accordance 

with the guidelines of Boiling Water Reactor Vessel and Internals Project (BWRVIP)-48-A, 

“Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines.” Any detected 

indications are evaluated in accordance with ASME Code Section XI, Subsections IWB-3500 

and IWB-3600, and with the additional guidance provided by BWRVIP-48-A. The program 

includes the vessel attachment welds for the following internal components: steam dryer 

support and hold down bracket, guide rod bracket, feedwater sparger bracket, jet pump riser 

brace, core spray piping bracket, and surveillance sample holder bracket. In conjunction with 

this program, the Water Chemistry program is also used to mitigate the aging effect of cracking 

of reactor vessel internal attachment welds exposed to reactor coolant by maintaining high 

reactor coolant purity.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M4. Based on its audit, the staff 

found that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M4. However, as a result of the NRC’s license renewal inspection at LSCS, completed 

on October 16, 2015, the staff identified a potential issue related to the effective coverage 

obtained in the performance of qualified enhanced visual examinations (EVT-1s) for LSCS’s 

vessel internals.

The staff noted that Exelon Procedure ER-AB-331, Revision 14, “BWR Internals Program 

Management,” addresses changes to the EVT-1 requirements in BWRVIP-03, “Reactor 

Pressure Vessel and Internals Examination Requirements.” Attachment 1 to ER-AB-331, 

“Exelon Position on EVT-1 Implementation,” states that changes related to the reduction of the 

allowable viewing angle have reduced the effective coverage of some weld examinations to 

zero percent in some cases. It further states that “EVT-1 inspections of required welds and 

components that yield an effective coverage of zero percent meet the BWRVIP inspection 

requirements.” The staff noted that ER-AB-331 is an implementation document for the BWR 

Vessel ID Attachment Welds and the BWR Vessel Internals AMPs.

Although not addressed in BWRVIP guidelines, the staff’s expectation is that the examination 

coverage of inspections performed for AMPs based on BWRVIP guidance would be in 

accordance with the ASME Code. Since BWRVIP-03 and BWRVIP-48-A do not address 

minimum required effective examination coverage, it is unclear to the staff whether limited 

examination coverage meets the BWRVIP’s expected level of implementation. The staff had 

identified this issue as open item OI 3.0.3.1.2-1.
3-14

By letter dated February 16, 2016, the staff issued RAI B.2.1.4-1, requesting the applicant to: 

(1) provide a summary of the locations where EVT-1 examinations are performed, whether 

Alloy 182 welds are included, and the percent coverage for these examinations; (2) provide the 

technical basis regarding the limited inspection coverage, and its adequacy to detect aging 

degradation prior to loss of intended function(s) where examination coverage is expected to be 

less than 90 percent; (3) provide a summary of the operating experience related to detected 

flaws, and the results of any flaw analyses; (4) describe how inspection results with minimal 

coverage will be documented and justified during the period of extended operation; and (5) state 

whether deviation reports will be submitted for inspection results for vessel attachment welds 

that credit examinations with limited coverage and if not, justify how the BWRVIP will provide 

adequate oversight of the effectiveness of the BWR Vessel ID Attachment Welds.

By letter dated February 25, 2016, the applicant provided its response to RAI B.2.1.4-1. For 

Part 1 of the RAI, the applicant provided a summary of the EVT-1 examinations performed on 

vessel ID attachment welds for LSCS, from 2004 through 2015. Based on a review of available 

records, the applicant concluded that most of the attachment welds subject to EVT-1 

examinations are at least partially fabricated with Alloy 182 material, which is susceptible to 

intergranular stress corrosion cracking (IGSCC). The applicant explained that at the time of the 

inspections, examinations were performed according to the latest revision of BWRVIP-03. The 

applicant stated that BWRVIP-03, Revision 10, required that the angle of inspection not exceed 

30 degrees from perpendicular to the examination surface to meet the qualification 

requirements of EVT-1. The applicant also stated that prior to this revision, the inspection angle 

could be as much as 60 degrees, similar to what is required for VT-1 examinations performed 

for ASME Code, Section XI. The applicant further stated that this revision to the EVT-1 

examination was implemented at LSCS, Unit 2, during the refueling outage in 2009 and for 

Unit 1 during the 2010 outage. The applicant stated that the average EVT-1 examination 

coverage for the attachment welds prior to this revision was 91 percent for Unit 1, and 

87 percent for Unit 2, and the average EVT-1 examination coverage for the attachment welds 

after the revision is 72 percent for Unit 1, and 66 percent for Unit 2.

The applicant explained that it performs an examination on the entire accessible surface of the 

vessel ID attachment weld, and the reported coverage is calculated using the total accessible 

weld examined that meets the EVT-1 requirements and the entire weld (i.e., accessible plus 

inaccessible). The applicant stated that the portions that cannot be examined to the EVT-1 

requirements are visually examined by a qualified nondestructive examination specialist.

In response to Part 2 of the RAI, the applicant stated that if the qualification requirements 

remain the same during the period of extended operation, it expects examination coverage 

would be consistent with what is currently achieved, as reported in its response to Part 1 of the 

RAI. The applicant stated that while BWRVIP-48-A does not address required examination 

coverage for attachment welds, the examination methods that are applicable (BWRVIP-03, 

Revision 18) direct that all accessible surfaces of the component be examined. For welds this is 

further defined to include the adjacent base metal.

The applicant stated that the ASME Code Section XI, requires examinations of accessible 

attachment welds using either VT-1 or VT-3 methods, whereas the examination method used 

for certain vessel attachment welds (EVT-1) is more effective in the detection of cracks 

characteristic of IGSCC. The applicant also stated that while some of the reported vessel ID 

attachment welds have limited EVT-1 coverage (i.e., less than 90 percent of the entire weld 

surface), it is adequate to detect aging degradation prior to loss of intended function. The 

applicant further stated that the EVT-1 method is the nuclear industry standard for visual 
3-15

examination, and is more effective than the ASME Code Section XI requirement for vessel ID 

attachment welds.

In response to Part 3 of the RAI, the applicant stated that it has not detected indications of 

cracking on the vessel ID attachment welds for LSCS; therefore, it has not performed any 

evaluations or flaw analyses to determine the maximum flaw size that can be tolerated. The 

applicant also stated that there have not been any reported instances of IGSCC in vessel 

attachment welds for the domestic BWR fleet. The applicant stated that if a flaw was detected 

and it did not meet the standards for ASME Section XI, IWB-3520, the flaw would be analytically 

evaluated in accordance with ASME Section XI, IWB-3600, for acceptability, and these 

evaluations include determination of the maximum allowable flaw size.

In its response to Part 4 of the RAI, the applicant stated that based on its operating experience it 

does not expect EVT-1 examinations of vessel attachment welds with essentially zero-percent 

coverage would occur during the period of extended operation. The applicant stated that it has 

revised its procedure referenced in ER-AB-331, which discussed the possibility of accepting 

zero-percent EVT-1 examination coverage. The applicant also stated that the revised 

procedure requires that when the EVT-1 or VT-1 method is specified, the entire accessible 

surface of the weld or component is to be visually examined to the maximum extent practical 

with the specific qualification requirements. The applicant further stated that the procedure has 

been revised to clarify that in cases in which an EVT-1 examination of a reactor internal 

component results in zero-percent examination coverage, this condition is to be entered into the 

corrective action program and evaluated for whether a BWRVIP deviation report is required. 

The applicant reiterated that, based on historical data, it does not expect that essentially 

zero-percent EVT-1 examination coverage would occur for the vessel ID attachment welds 

during the period of extended operation.

In its response to Part 5 of the RAI, the applicant stated that Exelon implementing procedures 

require that it submit a deviation report to the BWRVIP when a mandatory or needed element is 

not being implemented consistent with the intent of the BWRVIP guidance. The applicant also 

stated that the BWRVIP provides for oversight of the effectiveness of the BWR Vessel ID 

Attachment Welds AMP through the use of reviews by the Institute of Nuclear Power Operations 

(INPO), which include comprehensive periodic onsite assessments of program implementation, 

monitoring, and review and analysis of operating experience. The applicant further stated that 

the results of these examinations are provided to the BWRVIP following each refueling outage.

The staff reviewed the applicant’s response and finds it acceptable because the applicant’s 

summary of past EVT-1 examinations, performed in accordance with BWRVIP-48-A and 

BWRVIP-03 for LSCS, confirmed that the EVT-1 examinations performed for the vessel ID 

attachment welds provide a level of examination equivalent to or superior to those that would 

have been expected if the examinations had been performed to the requirements of ASME 

Code Section XI, Subsection IWB, Examination Category B-N-2. Additionally, the applicant 

confirmed that there have not been any instances of crediting zero-percent examination 

coverage, and going forward its procedures will be revised to require that, in the unlikely event 

that zero-percent coverage is obtained, this condition would be entered into the corrective action 

program and evaluated for whether a BWRVIP deviation report is required. The staff’s concerns 

described in RAI B.2.1.4-1 are resolved, and the associated open item, OI 3.0.3.1.2-1, is closed.

Based on its audit and review of the applicant’s response to RAI B.2.1.4-1, the staff finds that 

program elements 1 through 6 for which the applicant claimed consistency with the GALL 

Report are consistent with the corresponding program elements of GALL Report AMP XI.M4.
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Operating Experience. LRA Section B.2.1.4 summarizes operating experience related to the 

applicant’s BWR Vessel ID Attachment Welds program. The applicant stated that vessel ID 

attachment welds for Unit 1 were examined using a visual examination technique (i.e., EVT-1) 

during refueling outages (RFOs) in 2004, 2006, 2008, 2010, and 2012. The applicant also 

stated that the examinations included the attachment welds for the following vessel internal 

components: the jet pump riser brace support pads, feedwater sparger, steam dryer support 

bracket, and core spray piping bracket. The applicant further stated that these examinations did 

not identify any indications of cracking. In addition, the applicant indicated that similar 

examinations were performed for Unit 2 during the RFOs in 2005, 2007, 2011, and 2013. The 

applicant stated that these examinations did not identify any indications of cracking.

The applicant stated that the cited inspections provide a good example of how the program uses 

condition monitoring to manage the effects of cracking for the vessel internal attachment welds. 

The applicant further stated that the lack of cracking indications on its vessel attachment welds 

can be attributed to the effectiveness of the water chemistry management, design, and good 

installation practices. The applicant stated that, based on the program’s effectiveness, there is 

reasonable assurance that the continued implementation of the BWR Vessel ID Attachment 

Welds program will identify degradation of vessel attachment welds before failure or loss of 

intended function during the period of extended operation.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which the GALL Report AMP XI.M4 was evaluated.

UFSAR Supplement. LRA Section A.2.1.4 provides the UFSAR supplement for the BWR 

Vessel ID Attachment Welds program. The staff reviewed this UFSAR supplement description 

of the program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff also noted that the applicant committed to ongoing implementation of the 

existing BWR Vessel ID Attachment Welds program for managing the effects of aging for 

applicable components during the period of extended operation. The staff finds that the 

information in the UFSAR supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and its review of the applicant’s BWR Vessel ID 

Attachment Welds program, the staff concludes that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 
3-17

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

BWR Feedwater Nozzle

Summary of Technical Information in the Application. LRA Section B.2.1.5 describes the 

existing BWR Feedwater Nozzle program as consistent with GALL Report AMP XI.M5, “BWR 

Feedwater Nozzle.” The LRA states that the program is a condition monitoring program 

intended to manage the aging effect of cracking in the feedwater nozzles of the reactor vessel. 

The program manages these aging effects in accordance with ASME Code Section XI, 

Subsection IWB, Table IWB–2500–1, and with recommendations in BWR Owners Group 

Licensing Topical Report GE-NE-523-A71-0594-A, Revision 1, “Alternate BWR Feedwater 

Nozzle Inspection Requirements,” dated May 2000. According to the LRA, the applicant 

implements this program through the plant’s ISI program and specifies a UT examination of 

critical regions of the feedwater nozzles. The LRA states that the applicant made changes to 

the nozzle design in response to NUREG-0619, “BWR Feedwater Nozzle and Control Rod Drive 

Return Line Nozzle Cracking,” dated November 1980, to mitigate thermally induced fatigue 

cracking; that the design does not include cladding on the nozzle inner surface; and that the 

nozzle uses a triple sleeve design. A low-flow feedwater control valve is used, and the reactor 

water cleanup system returns flow to both feedwater loops to minimize the frequency and 

magnitude of temperature fluctuations and resulting thermal fatigue of the feedwater nozzles. 

The LRA also states that both units do not have a thermal sleeve bypass leakage detection 

system and that the inspection interval has not been modified based on leakage data. 

ASME Code Section XI criteria are used to evaluate flaws and inspection results that do not 

satisfy the acceptance standards are documented in accordance with the corrective action 

program.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M5. Based on its audit, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M5.

Operating Experience. LRA Section B.2.1.5 summarizes operating experience related to the 

BWR Feedwater Nozzle program. The LRA states that the applicant inspected each feedwater 

nozzle at least twice in accordance with the guidance in GE-NE-523-A71-0594-A, Revision 1, as 

part of the existing augmented ISI program. During the inspection of Units 1 and 2 feedwater 

nozzles in 2012 and 2011, respectively, the applicant discovered minor recordable indications 

evaluated as acceptable, consistent with ASME Code Section XI Article IWB-3000 criteria. 

Additionally, ISI reactor coolant boundary leakage testing performed during each RFO has not

identified any leakage from the feedwater nozzles to date.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.
3-18

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M5 was evaluated.

UFSAR Supplement. LRA Section A.2.1.5 provides the UFSAR supplement for the BWR 

Feedwater Nozzle program. The staff reviewed this UFSAR supplement description of the 

program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff also noted that the applicant committed to ongoing implementation of the 

existing BWR Feedwater Nozzle program for managing the effects of aging for applicable 

components during the period of extended operation. The staff finds that the information in the

UFSAR supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s BWR Feedwater Nozzle 

program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

BWR Control Rod Drive Return Line Nozzle

Summary of Technical Information in the Application. LRA Section B.2.1.6 describes the 

existing BWR Control Rod Drive Return Line Nozzle program as consistent with GALL Report 

AMP XI.M6, “BWR Control Rod Drive Return Line Nozzle.” The LRA states that the AMP is a 

condition monitoring program that addresses the control rod drive return line (CRDRL) nozzle, 

which is exposed to a reactor coolant environment, to manage the effect of cracking. The LRA 

also states that the AMP proposes to manage this aging effect through periodic ISI 

examinations that are implemented in accordance with ASME Code Section XI, 

Table IWB-2500-1. The LRA further states that requirements of NUREG-0619 were 

implemented by capping the CRDRL nozzle and removing the return line. There are no ongoing 

maintenance or testing activities from NUREG-0619 that apply to LSCS, Units 1 and 2.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M6. Based on its audit, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M6.

Operating Experience. LRA Section B.2.1.6 summarizes operating experience related to the 

BWR Control Rod Drive Return Line Nozzle program. The LRA states that the most recent UT 

examinations of the CRDRL nozzle blend radius, nozzle-to-vessel weld, and nozzle-to-cap weld 

performed on LSCS, Units 1 and 2, did not identify indications of cracking. Additionally, visual 

inspections (VT-2) of the CRDRL nozzle, cap, and associated welds have not discovered 

leakage. The VT-2 visual inspections are performed, as part of the ISI program, at each RFO 

during reactor pressure testing. The LRA also states that the Mechanical Stress Improvement 

Process (MSIP) was performed on the CRDRL nozzle-to-cap weld on LSCS, Units 1 and 2, to 
3-19

provide improved IGSCC resistance at the welds. Indications of cracks have not been 

discovered in these welds.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M6 was evaluated.

UFSAR Supplement. LRA Section A.2.1.6 provides the UFSAR supplement for the BWR 

Control Rod Drive Return Line Nozzle program. The staff reviewed this UFSAR supplement 

description of the program and noted that it is consistent with the recommended description in 

SRP-LR Table 3.0-1. The staff also noted that the applicant committed (Commitment No. 6) to 

ongoing implementation of the existing BWR Control Rod Drive Return Line Nozzle program for 

managing the effects of aging for applicable components during the period of extended 

operation. The staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s BWR Control Rod Drive 

Return Line Nozzle program, the staff concludes that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

BWR Stress Corrosion Cracking

Summary of Technical Information in the Application. LRA Section B.2.1.7 describes the 

existing BWR Stress Corrosion Cracking program as consistent with GALL Report AMP XI.M7, 

“BWR Stress Corrosion Cracking.” The program is a condition monitoring and mitigative 

program that has been implemented in accordance with NUREG-0313, Revision 2, “Technical 

Report on Material Selection and Processing Guidelines for BWR Coolant Pressure Boundary 

Piping,” dated January 1988, and NRC Generic Letter (GL) 88-01, “NRC Position on 

Intergranular Stress Corrosion Cracking (IGSCC) in BWR Austenitic Stainless Steel Piping,” 

dated January 25, 1988, and its Supplement 1, dated February 4, 1992. The program manages 

IGSCC in relevant piping and piping welds made of stainless steel and nickel-based alloy in 

reactor coolant and treated water environments. The program includes an induction heating 

stress improvement or mechanical stress improvement process to mitigate cracking on the 

welds susceptible to IGSCC. Reactor coolant water chemistry is controlled and monitored in 

accordance with Electric Power Research Institute (EPRI) guidelines to maintain high water 
3-20

purity and reduce susceptibility to SCC as described in LRA Section B.2.1.2, Water Chemistry 

program.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M7. For the “detection of aging 

effects” program element, the staff determined the need for additional information, which 

resulted in the issuance of the RAIs discussed below.

GALL Report AMP XI.M7 states that the program to manage IGSCC in reactor coolant pressure 

boundary piping is delineated in NUREG-0313, Revision 2, and GL 88-01 with its Supplement 1. 

The “detection of aging effects” program element of GALL Report AMP XI.M7 also states that 

modifications of the extent and schedule of inspection in GL 88-01 are allowed in accordance 

with the inspection guidance in staff-approved BWRVIP-75-A, “Technical Basis for Revisions to 

Generic Letter 88-01 Inspection Schedules.”

LRA Section B.2.1.7 states that the BWR Stress Corrosion Cracking program is consistent with 

GALL Report AMP XI.M7. The LRA also states that hydrogen water chemistry and noble 

metals chemical addition have been implemented to further reduce the susceptibility of reactor 

coolant piping systems to IGSCC. The LRA further states that welds classified as Category A 

(IGSCC-resistant material) are subsumed into the Risk-Informed Inservice Inspection (RI-ISI) 

program in accordance with staff-approved EPRI Topical Report (TR)-112657, Revision B-A, 

“Revised Risk-Informed Inservice Inspection Evaluation Procedure,” dated December 1999.

During the audit, the staff noted that LSCS implemented RI-ISI for the current (third) ISI interval 

through the relief request process as approved by the NRC in its letter dated April 29, 2008. 

The staff also noted that the inspection extent for Category A welds, which are subsumed in the 

RI-ISI program, may not be consistent with the guidance in GALL Report AMP XI.M7 because 

the RI-ISI adopts a risk-based selection process. Therefore, the staff needed additional 

information to confirm whether the program will adequately manage cracking due to IGSCC for 

Category A welds during the period of extended operation.

By letter dated May 29, 2015, the staff issued RAI B.2.1.7-1 requesting that the applicant clarify 

whether the inspection extent for Category A welds, subsumed in the RI-ISI, is consistent with 

the guidance in GL 88-01 and BWRVIP-75-A. The staff also requested if the inspection extent 

for Category A welds is different from the guidance in GL 88-01 and BWRVIP-75-A, that the 

applicant clarify why the inspection extent for Category A welds is not identified as a program 

exception and provide the bases, with plant-specific operating experience, to show that the 

program adequately manages IGSCC for Category A welds.

In its response dated June 25, 2015, the applicant stated that the RI-ISI methodology approved 

and implemented for the third ISI interval (October 2007 – September 2017) is consistent with 

the guidance in staff-approved EPRI TR-112657, Revision B-A. The applicant also confirmed 

that, if such approval allowing implementation of risk-informed inspection per EPRI TR-112657, 

Revision B-A is not granted for the period of extended operation, LSCS will inspect Category A 

welds in accordance with the extent and frequency of inspection specified by BWRVIP-75-A, 

Table 3-1. The staff noted that BWRVIP-75-A, Table 3-1, specifies that the inspection extent for 

Category A welds be 25 percent under normal water chemistry or 10 percent under hydrogen 

water chemistry.
3-21

In addition, the applicant stated that all of the Category A welds are assigned medium-risk

Category 4 except for two Unit 2 welds that are high-risk Category 2 welds. The applicant 

stated that its risk-informed inspection requires inspections of 25 percent of the high-risk 

Category 2 welds and 10 percent of the medium-risk Category 4 welds during each 10-year 

inspection interval in accordance with EPRI TR-112657, Revision B-A. As an example, the 

applicant stated that during the 10-year period of 2003 through 2012 there were five Category A 

welds (12 percent) inspected at Unit 1 and five Category A welds (9 percent) inspected at 

Unit 2. The applicant also indicated that, because the populations of Category 2 and 

Category 4 welds include many welds that are not included in the scope of the BWR Stress 

Corrosion Cracking program, the percentage of Category A welds selected for the risk-informed 

inspection may be more than, less than, or equal to the inspection extent specified in 

BWRVIP-75-A.

In its response regarding the program exception, the applicant indicated that the inspection 

extent for Category A welds is not identified as a program exception because the inspection 

extent for Category A welds will be consistent with BWRVIP-75-A and GALL Report AMP XI.M7 

without obtaining NRC approval for continued use of RI-ISI during the period of extended 

operation.

The applicant also stated that EPRI TR-112657, Revision B-A, provides a staff-approved 

method for meeting GL 88-01 commitments for establishing the inspection extent for Category A 

welds. The applicant further stated that the introduction section of the NRC safety evaluation 

(SE) (October 28, 1999) for EPRI TR-112657, Revision B-A, states that RI-ISI programs 

enhance overall safety by (1) focusing inspections of piping at highly risk-significant locations 

and at locations where failure mechanisms are likely to be present and (2) improving the 

effectiveness of inspection of components because examination methods are based on the 

postulated failure mode and configuration of the piping structural element.

In its response regarding operating experience, the applicant stated that there has never been a 

leak or an indication identified from an inspection that was indicative of IGSCC for any welds 

within the scope of the program at LSCS, Units 1 and 2, and this demonstrates that the Water 

Chemistry program, materials selection, and implementation of processes and programs 

providing resistance to IGSCC have been effectively implemented at LSCS. The applicant also 

stated that continuing to subsume the Category A welds into the RI-ISI program in accordance 

with EPRI TR-112657, Revision B-A, results in an adequate methodology to manage the aging 

effect of IGSCC for Category A welds.

In its review, the staff found the applicant’s response acceptable because (1) the applicant 

clarified that its currently approved and implemented RI-ISI program for the third 10-year interval 

is consistent with the staff-approved guidance for inspections of Category A welds described in 

EPRI TR-112657, Revision B-A, (2) the applicant confirmed that it will inspect Category A welds 

in accordance with the guidance in BWRVIP-75-A for the period of extended operation if RI-ISI 

is not granted, and (3) the applicant confirmed that there was no leak or inspection result that 

indicates occurrence of IGSCC in any welds within the scope of the program. The staff’s 

concern described in RAI B.2.1.7-1 is resolved.

As defined in GL 88-01, Category B and C welds are made of materials that are nonresistant to 

IGSCC where a stress improvement process was applied within or after the first 2 years of 

operation. During its audit, the staff reviewed LAS03.G05, “ISI Selection Document – Third 

Ten-Year Inspection Interval, LaSalle County Station, Units 1 & 2,” Revision 1, dated 

March 31, 2011, which included inspection schedules and selections for Category B and C 
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welds. The staff noted that the inspection selections for Unit 2 Category B and C welds were 25 

and 1, respectively; however, the number specified by BWRVIP-75A was 34 and 2, respectively. 

Therefore, additional information was necessary to confirm the consistency of the program with 

GALL Report AMP XI.M7. By letter dated May 29, 2015, the staff issued RAI B.2.1.7-2 

requesting that the applicant provide justification as to why the number of Category B and C 

welds selected for inspection at LSCS, Unit 2, is less than the number specified by 

BWRVIP-75-A.

In its response dated June 25, 2015, the applicant stated that the table in the referenced ISI 

selection document is not used for selecting and scheduling inspection of Category B through G 

welds. The applicant clarified that the 10-year inspection period for BWRVIP-75-A does not 

correspond with the 10-year ISI interval. The applicant stated that the current 10-year 

inspection period for BWRVIP-75-A is January 1, 2013, through December 31, 2022, whereas 

the current 10-year ISI interval is October 1, 2007, through September 30, 2017. The applicant 

also stated that the program will continue to implement the same frequency and scope for 

inspections of Category B and C welds through the period of extended operation. The applicant 

also stated that its program is consistent with the guidance in Table 3-1 of BWRVIP-75-A for 

inspection frequency and scope of Category B through G welds for normal water chemistry 

conditions without crediting for implementation of hydrogen water chemistry.

The applicant clarified that 25 percent of the Category B and C welds are inspected during each 

10-year period and confirmed that during the first 10-year period (2003 through 2012) 

inspections were performed on 34 Category B welds and 2 Category C welds on Unit 2, 

consistent with the guidance in BWRVIP-75-A. The applicant also discussed the inspection 

status and schedule of Unit 2 welds during the current 10-year period (2013 through 2022) by 

noting that 14 Category B welds and no Category C welds have been inspected so far. 

Consequently, at least 20 additional Category B welds and 2 Category C welds will need to be 

inspected by December 31, 2022, in order to meet the guidance in BWRVIP-75-A.

The staff found the applicant’s response acceptable because (1) the number of inspections for 

Unit 2 Category B and C welds in the cited inspection selection document do not correlate with 

the number of inspections required by BWRVIP-75-A because the 10-year ISI interval does not 

correspond to the same 10-year inspection period for BWRVIP-75-A, (2) the inspection 

schedule for Unit 2 Category B and C welds for the current 10-year inspection period are 

consistent with GALL Report AMP XI.M7, and (3) the inspection frequency and scope for 

Category B through G welds in the program are consistent with BWRVIP-75-A and 

GALL Report AMP XI.M7. The staff’s concern described in RAI B.2.1.7-2 is resolved.

The staff noted that GL 88-01 indicates that examinations should comply with the applicable 

Edition and Addenda of the ASME Code, Section XI, as specified in paragraph (g), “Inservice 

Inspection Requirements,” of 10 CFR 50.55a or as otherwise approved by the NRC. In addition, 

Information Notice (IN) 98-42, “Implementation of 10 CFR 50.55a(g) Inservice Inspection 

Requirements,” dated December 1, 1998, indicates that “essentially 100 percent” of the required 

examination volume for inservice inspections is defined as more than 90 percent of the specified 

examination volume. However, during the audit, the staff noted that Table B in the LSCS,

Unit 2, Post-Outage 90-Day ISI Summary Report, dated May 31, 2013, indicates that the 

examination coverage of the BWRVIP-75-A inspections on several Category B welds was only 

50 percent. The staff notes that, because these welds are classified as augmented inservice 

inspection, the applicant does not submit relief requests as would be necessary if they were 

ASME-required inspections. To determine whether the limited examination coverage will 

adequately manage IGSCC during the period of extended operation, by letter dated 
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May 29, 2015, the staff issued RAI B.2.1.7-3 requesting that the applicant explain why the 

examination coverage is limited and justify why the program is adequate to manage cracking 

due to IGSCC without additional inspections to compensate for the limited examination 

coverage of each weld category during an inspection period.

In its response dated June 25, 2015, the applicant provided the average examination coverage 

of each weld category for welds examined between February 2008 and March 2015 at each 

unit. The applicant clarified that all volumetric weld examinations performed under the scope of 

the GL 88-01 were, to the maximum examination volume coverage practical, using currently 

approved performance demonstration initiative (PDI) methods. The applicant stated that where 

50-percent examination coverage is reported, the welds are between piping and a cast valve 

body or other component where the weld configuration is such that the PDI method can only 

provide qualified and reliable results for the side of the weld adjacent to the piping. The 

applicant also stated that the issue of less than 90-percent examination coverage for welds has 

been entered into the Exelon corrective action program for resolution in connection to recently 

completed weld examinations.

The staff noted that the applicant’s response did not provide information regarding the 

examination coverage of Unit 1 Category A welds and Unit 2 Category C welds. It was also 

unclear to the staff whether the cast valve body associated with the Unit 2 Category D welds is 

made of cast material resistant to IGSCC. By letter dated August 18, 2015, the staff issued 

RAI B.2.1.7-3a requesting that the applicant provide the examination coverage for the two 

categories not previously provided and provide justification if limited examination coverage is 

identified. In addition, for the two Category D welds, the staff requested that the applicant 

provide information to clarify whether the cast materials are resistant to IGSCC and, if available, 

any internal visual or surface examination results of the valve body per ASME Code Section XI 

requirements.

In its response dated September 15, 2015, for examination coverages, the applicant included 

the period from February 2006 through March 2015, and stated that five Unit 1 Category A 

welds were examined with 100-percent overall examination coverage and that two Unit 2 

Category C welds were examined with an overall coverage of 50 percent. The applicant 

justified the limited coverage by stating that the PDI methods result in a best-effort approach 

using the best available approved volumetric examination techniques and that Exelon will 

continue to use the latest commercially available examination techniques that provide coverage 

to the maximum extent practical. In addition, during the 31-year Unit 2 operating history, there 

have been no indications of IGSCC for the welds within the program scope.

In its response regarding the valve material associated with the two Unit 2 Category D welds, 

the applicant clarified that the valve body is fabricated of cast stainless steel SA-351, 

Grade CF8M with a carbon content of 0.04 percent and a ferrite content of 19.3 percent. The 

applicant indicated that although the carbon content for the valve body is slightly above the 

maximum value (0.035 percent) specified in GL 88-01 to be resistant to IGSCC, the ferrite 

content is significantly above the minimum ferrite content (7.5 percent). The applicant 

determined that the cast valve body has relatively good resistance to IGSCC based on the 

evaluation of the carbon and ferrite content. In addition, there have been no maintenance 

activities that provided an opportunity to internally examine the valve. The applicant also 

clarified that piping welded to the valve is not resistant to IGSCC and that, if IGSCC were to 

initiate in these welds, it would likely occur on the piping side rather than the valve side of the 

weld. The applicant further confirmed that the piping side of these welds is subject to qualified 
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and reliable examination using the PDI method every 6 years in accordance with the 

examination schedule of BWRVIP-75-A and that no indications of cracking have been identified.

In its review of the valve material associated with the Unit 2 Category D welds, the staff finds the 

applicant’s response acceptable because (1) the cast stainless steel valve body retains 

resistance to IGSCC based on the ferrite content of the material (19.3 percent), consistent with 

the criterion specified in GL 88-01 for IGSCC-resistant materials, and (2) the applicant clarified 

that the program inspects the piping side of the Category D welds, which are susceptible to 

IGSCC, by using qualified and reliable methods at the inspection frequency specified in 

GL 88-01 and indicated that these inspections have not identified any indications of cracking. 

The staff’s concern related to the valve material portion of RAI B.2.1.7-3a is resolved.

However, in its review of the examination coverage aspect, the staff received additional 

information from the Regional Inspectors conducting the IP-71002 inspection at LSCS. The 

staff became aware that Exelon appears to credit any percentage coverage as meeting the 

BWR Stress Corrosion Cracking program because BWRVIP-75-A does not specify a 

percentage for examination coverage. To evaluate the adequacy of the applicant’s program, 

the staff issued RAI B.2.1.7-3b in a letter dated February 16, 2016, to confirm the percentage of 

examination coverage that Exelon considers meeting BWRVIP-75-A, and to provide the 

technical bases for crediting examinations when the coverage obtained is less than 90 percent. 

The staff had identified this as OI 3.0.3.1.5-1.

In its response dated February 25, 2016, the applicant stated that the minimum percentage of 

weld volume examination coverage for a single weld to be considered “inspected,” under the 

current GL 88-01 program and the BWR Stress Corrosion Cracking program during the period 

of extended operation, is greater than 90 percent. The applicant also stated that Exelon’s 

implementing procedure currently requires generation of a corrective action issue report for weld 

examinations that have comparably limited coverage. The applicant also stated that the 

implementing procedure will be revised to improve clarity for the required extent of evaluation 

for weld examinations that are only credited under the BWR Stress Corrosion Cracking

program, when examination coverage is less than or equal to 90 percent. The revised guidance 

will require an engineering technical evaluation that provides documented bases comparable to 

that which would be included in a relief request, had the inspection been an ASME Code 

examination. Such welds would then be considered “inspected” if they were examined to the 

maximum coverage attainable using the “performance demonstration initiative” methods. The 

staff finds the applicant’s response acceptable because the program will now ensure that for all 

limited weld examinations performed by the BWR Stress Corrosion Cracking program, there will 

be a documented technical basis comparable to that required for an ASME Code relief request. 

The staff’s concern described in RAI B.2.1.7-3b is resolved, and the associated open item, 

OI 3.0.3.1.5-1, is closed.

Based on its audit and review of the applicant’s responses to RAIs B.2.1.7-1, B.2.1.7-2, 

B.2.1.7-3, B.2.1.7-3a, and B.2.1.7-3b, the staff finds that program elements 1 through 6 for 

which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.M7.

Operating Experience. LRA Section B.2.1.7 summarizes the operating experience related to 

the BWR Stress Corrosion Cracking program. The applicant indicated that induction heating or 

a mechanical stress improvement process was performed on all Unit 1 welds and all except two 

Unit 2 welds that are within the scope of the program. The applicant also stated that the stress 

improvements were applied to most of the welds before 2 years of operation, illustrating that 
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industry operating experience and staff guidance were applied effectively to mitigate and 

prevent IGSCC in the welds within the scope of the program. In addition, the applicant 

confirmed that no indications of cracking were identified during the volumetric examinations 

performed on the 9 welds in the 2012 Unit 1 RFO or on the 13 welds in the 2013 Unit 2 RFO.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M7 was evaluated.

UFSAR Supplement. LRA Section A.2.1.7 provides the UFSAR supplement for the BWR Stress 

Corrosion Cracking program. The staff reviewed this UFSAR supplement description of the 

program and notes that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s BWR Stress Corrosion 

Cracking program, the staff determines that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

BWR Penetrations

Summary of Technical Information in the Application. LRA Section B.2.1.8 describes the 

existing BWR Penetrations program as consistent with GALL Report AMP XI.M8, “BWR 

Penetrations.” The LRA states that the program is a condition monitoring program intended to 

manage the effects of aging of reactor vessel penetrations exposed to reactor coolant including 

instrument, control rod drive housing, standby liquid control (SLC)/core plate differential 

pressure, and incore-monitoring housing penetrations. The LRA also states that the program 

manages cracking due to stress corrosion cracking (SCC) and IGSCC using management of 

water chemistry and condition monitoring of reactor vessel penetration welds. The inspection 

and evaluation activities follow the recommendations in BWRVIP-49-A, “BWR Vessel and 

Internals Project, Instrument Penetration Inspection and Flaw Evaluation Guidelines,” dated 

March 2002; BWRVIP-47-A, “BWR Vessel and Internals Project, BWR Lower Plenum 

Inspection and Flaw Evaluation Guidelines,” dated June 2004; BWRVIP-27-A, “BWR Vessel 

and Internals Project, BWR Standby Liquid Control System/Core Plate Delta-P Inspection and 

Flaw Evaluation Guidelines,” dated August 2003; the requirements of ASME Code Section XI, 
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Subsection IWB; and the recommendations for reactor water chemistry as described in the 

Water Chemistry (LRA Section B.2.1.2) program.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M8. Based on its audit, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M8.

Operating Experience. LRA Section B.2.1.8 summarizes operating experience related to the 

BWR Penetrations program. The LRA states that, during RFOs in 1999 and 2002 for Unit 1 and 

outages in 2000 and 2003 for Unit 2, the applicant implemented the baseline inspections 

required by BWRVIP-47-A as part of the BWR Penetrations program, and these inspections 

identified no cracking or other material condition issues. The LRA also summarizes the results 

for inspections required by BWRVIP-27-A, conducted in 2008 for Unit 1 and 2007 for Unit 2, 

which found no recordable indications in the SLC/Core Plate differential pressure penetration to 

safe end extension welds. Additionally, the applicant conducted VT-2 visual inspections of the 

instrumentation, CRD housing, incore-monitoring housing, and the SLC/Core Plate differential 

pressure penetrations during the reactor coolant boundary system leakage test in 2012 and 

2013 for LSCS, Units 1 and 2, respectively, and found no leakage from these components.

The staff reviewed operating experience information in the application during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M8 was evaluated.

UFSAR Supplement. LRA Section A.2.1.8 provides the UFSAR supplement for the BWR 

Penetration program. The staff reviewed this UFSAR supplement description of the program 

and noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The 

staff also noted that the applicant committed to ongoing implementation of the existing BWR 

Penetrations program for managing the effects of aging for applicable components during the 

period of extended operation. The staff finds that the information in the UFSAR supplement is 

an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s BWR Penetration program, 

the staff concludes that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. The staff concludes that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). Based on its review, the staff concludes that the UFSAR supplement

provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
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Flow-Accelerated Corrosion

Summary of Technical Information in the Application. LRA Section B.2.1.10, as modified by 

letter dated August 6, 2015, describes the existing Flow-Accelerated Corrosion program as 

consistent with an exception with GALL Report AMP XI.M17, “Flow-Accelerated Corrosion,” as 

modified by License Renewal Interim Staff Guidance (LR-ISG)-2012-01, “Wall Thinning due to 

Erosion Mechanisms.” The LRA states that the program predicts, detects, and monitors wall 

thinning due to flow-accelerated corrosion and erosion in piping and components in reactor 

coolant, steam, and treated water environments. Specifically, the program includes analytic 

evaluations, baseline inspections, and followup inspections to confirm predictions and performs 

repairs and replacements as necessary.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M17. For the “scope of program,” 

“detection of aging effects,” “monitoring and trending,” and “acceptance criteria” program 

elements, the staff determined the need for additional information, which resulted in the 

issuance of a request for addition information (RAI), as discussed below.

The “scope of program,” “detection of aging effects,” and “acceptance criteria” program 

elements in GALL Report AMP XI.M17 discuss the implementation of Electrical Power 

Research Institute (EPRI) Nuclear Safety Analysis Center (NSAC)-202L-R2 or NSAC-202L-R3, 

“Recommendations for an Effective Flow-Accelerated Corrosion Program,” dated April 8, 1999 

(Revision 2), and August 10, 2007 (Revision 3), as part of the program. Initially, LRA 

Section B.2.1.10 stated that LSCS’s Flow-Accelerated Corrosion program was based on EPRI 

NSAC-202L-R3. However, during the AMP Audit, it was disclosed that, after the submission of 

the LRA, the program was being revised to incorporate the guidance in EPRI NSAC-202L-R4, 

“Recommendations for an Effective Flow-Accelerated Corrosion Program,” dated 

November 26, 2013. This new revision contains alternate recommendations, such as guidance 

for system evaluation exclusion using a reduced trace chromium content. By letter dated 

July 7, 2015, the staff issued RAI B.2.1.10-1 requesting that the applicant provide the necessary 

program element changes associated with the exception to GALL Report AMP XI.M17.

In its response dated August 6, 2015, the applicant identified the technical changes in EPRI 

NSAC-202L-R4, as they relate to the “scope of program,” “detection of aging effects,” 

“monitoring and trending,” and “acceptance criteria” program elements of GALL Report 

AMP XI.M17. In the “scope of program” program element, the applicant identified reduced 

chromium content down to 0.10 percent as the revised exclusion for components within the 

system. In the “detection of aging effects” program element, the applicant identified the change 

for selecting components to include “entrance effect” locations. In the “monitoring and trending” 

program element, the applicant identified new discussions related to “calibrated lines,” 

“establishing calibration,” and “maintaining calibration,” and the addition of three new methods 

for determining wear rates from wall thickness measurements. The applicant also discussed 

the removal of the hydrazine factor from CHECWORKSTM. In the “acceptance criteria” program 

element, the applicant identified a new discussion regarding consideration of higher safety 

factors in situations where the measured wall thickness is less than the predicted wall thickness 

until the cause of the difference is understood or mitigated. With regard to component exclusion 

for chromium levels down to 0.10 percent, the applicant provided several industry references 

that served as the bases for this change. In addition, the applicant noted that by letter dated 

November 5, 2014, NEI had previously provided to the staff the information relating to the three 

new methods for calculating component wear. As part of its response, the applicant revised 
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LRA Sections A.2.1.10 and B.2.1.10 to identify that the program now includes an exception by 

relying on the implementation of EPRI NSAC-202L-R4.

The staff finds the response acceptable because the applicant delineated the specific changes 

for each program element contained in EPRI NSAC-202L-R4. The staff notes that, as stated in 

EPRI NSAC-202L, the recommendations have been updated with experiences from the 

CHECWORKSTM Users Group members and from recent developments in detection, modeling, 

and mitigation technology that refine and enhance the previous versions. The staff also notes 

that, in addition to the references cited by the applicant, EPRI 1011837, “Residual Chromium 

Effects on Flow-Accelerated Corrosion of Carbon Steel,” dated March 27, 2006, also evaluated 

the effects of low chromium content. Based on the above discussion and its evaluation of the 

information provided by the applicant, the staff’s concerns described in RAI B.2.1.10-1 are 

resolved.

Exception 1. In its response dated August 6, 2015, the applicant identified an exception to the 

“scope of program,” “detection of aging effects,” “monitoring and trending,” and “corrective 

action” program elements as a result of using EPRI NSAC-202L-R4, instead of EPRI 

NSAC-202L-R2 or EPRI NSAC-202L-R3. The staff reviewed this exception against the 

corresponding program elements in GALL Report AMP XI.M17 and finds it acceptable because, 

as documented in the applicant’s response to RAI B.2.1.10-1 (discussed above), EPRI 

periodically updates NSAC-202L by refining and enhancing the recommendations from earlier 

versions with operating experience and recent developments in detection, modeling, and 

mitigation techniques.

Based on its audit and review of the applicant’s response to RAI B.2.1.10-1, the staff finds that 

program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M17.

Operating Experience. LRA Section B.2.1.10 summarizes operating experience related to the 

Flow-Accelerated Corrosion program. In April 2013 the applicant identified through-wall leaks 

downstream of the minimum flow line orifice for the LSCS, Unit 2, high pressure core spray 

system. The program was able to identify the aging effect of wall thinning due to erosion, and 

the applicant used the corrective action program to prevent recurrence on this component and 

similar components through extent of condition inspections. The applicant also described 

inspections performed during the spring 2013 outage, which included baseline and followup 

inspections. All 97 of the components inspected met acceptance criteria, demonstrating that the 

program identifies and monitors wall thinning due to flow-accelerated corrosion.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M17 was evaluated.
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UFSAR Supplement. LRA Section A.2.1.10, as modified by letter dated August 6, 2015, 

provides the UFSAR supplement for the Flow-Accelerated Corrosion program. The staff 

reviewed this UFSAR supplement description of the program and noted that it is consistent with 

the recommended description in SRP-LR Table 3.0-1, as modified by LR-ISG-2012-01. The 

staff finds that the information in the UFSAR supplement is an adequate summary description of 

the program.

Conclusion. On the basis of its audit and review of the applicant’s Flow-Accelerated Corrosion 

program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report AMP XI.M17 are consistent. In addition, the staff reviewed 

the exception and its justifications and determines that the AMP, with the exception, is adequate 

to manage the applicable aging effects. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Reactor Vessel Surveillance

Summary of Technical Information in the Application. LRA Section B.2.1.20, as modified by 

letters dated June 25, 2015, August 26, 2015, and October 29, 2015, describes the existing 

Reactor Vessel Surveillance program as consistent, with an exception and enhancements, with 

GALL Report AMP XI.M31, “Reactor Vessel Surveillance.” This program manages the loss of 

fracture toughness of the reactor vessel and nozzles in a reactor coolant and neutron flux 

environment. The program monitors changes in the fracture toughness properties of ferritic 

materials in the beltline region of the reactor vessel. BWRVIP-86, Revision 1-A, “Updated BWR 

Integrated Surveillance Program (ISP) Implementation Plan,” dated October 2012, describes the 

BWRVIP Integrated Surveillance Program (ISP) for the current license term and the extended 

period of operation. The applicant participates in the BWRVIP ISP in accordance with the 

requirements in Appendix H, “Reactor Vessel Material Surveillance Program Requirements,” to 

10 CFR Part 50, “Domestic Licensing of Production and Utilization Facilities.”

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M31. For the “detection of aging 

effect” program element, the staff determined the need for additional information, which resulted 

in the issuance of an RAI, as discussed below.

The “detection of aging effects” program element of GALL Report AMP XI.M31 states that the 

plant-specific or ISP shall have at least one capsule with a projected neutron fluence equal to or 

exceeding the 60-year peak reactor vessel wall neutron fluence before the end of the period of 

extended operation. The program element also states that the program withdraws one capsule 

at an outage in which the capsule receives a neutron fluence of between 1 and 2 times the peak 

reactor vessel wall neutron fluence at the end of the period of extended operation and tests the 

capsule in accordance with the requirements of American Society for Testing and Materials 

(ASTM) E185-82, “Standard Practice for Conducting Surveillance Tests for Light-Water Cooled 

Nuclear Power Reactor Vessels,” dated January 1, 1982.

LRA Section B.2.1.20 indicates that the applicant’s Reactor Vessel Surveillance program is an 

existing program that is consistent with GALL Report AMP XI.M31 with no exception or 
3-30

enhancement. LRA Table 4.2.1-4 indicates that the LSCS, Unit 2, peak reactor vessel wall 

neutron fluence at the end of the period of extended operation is 1.22x1018 n/cm2 (E > 1 MeV). 

The LRA also states that the applicant is participating in the BWRVIP ISP, which is described in 

BWRVIP-86, Revision 1-A, and proposes to continue its participation in the BWRVIP ISP for the 

period of extended operation.

The staff noted that the BWRVIP ISP surveillance capsules for the period of extended operation 

are called “ISP(E)” capsules and that the surveillance weld and plate materials for LSCS, Unit 2,

are irradiated in reactor vessels of other plants as planned in the BWRVIP ISP. The staff also 

noted that the neutron fluence values for LSCS, Unit 2, ISP(E) surveillance plate and weld 

materials, as planned in the BWRVIP ISP, are not consistent with the fluence range criterion 

described in the “detection of aging effects” program element of GALL Report AMP XI.M31. As 

described above, GALL Report AMP XI.M31 specifies withdrawal of one capsule at an outage in 

which the capsule receives a neutron fluence of between 1 and 2 times the peak reactor vessel 

wall neutron fluence at the end of the period of extended operation. Therefore, the staff needed 

additional information to determine the consistency of the applicant’s program with the 

GALL Report.

By letter dated May 29, 2015, the staff issued RAI B.2.1.20-2 requesting that the applicant

clarify whether the applicant’s program will test LSCS, Unit 2, surveillance weld and plate 

materials at neutron fluence levels that are consistent with the neutron fluence range that is 

specified in GALL Report AMP XI.M31. The staff also requested that, if the neutron fluence 

values for surveillance materials are not consistent with GALL Report AMP XI.M31, the 

applicant identify a program exception regarding the neutron fluence range and justify why the 

exception is acceptable to manage loss of fracture toughness due to neutron irradiation 

embrittlement for the reactor vessel.

In its response dated June 25, 2015, amended by letter dated August 26, 2015, the applicant 

stated that the LSCS, Unit 2, ISP(E) representative weld material is located in a Susquehanna 

Steam Electric Station, Unit 1, surveillance capsule that has a planned fluence exposure of 

8.67x1017 n/cm2

, which is less than the 60-year peak fluence value of 1.14x1018 n/cm2 that is 

projected for the limiting LSCS, Unit 2, beltline weld as shown in LRA Table 4.2.1-5. The 

applicant also indicated that the LSCS, Unit 2, ISP(E) representative plate material is located in 

a River Bend Nuclear Station reactor capsule that has a planned fluence exposure of 4.49x1018

n/cm2

, which exceeds 2 times the 60-year peak fluence value of 1.22x1018 n/cm2 that is 

projected for the limiting LSCS, Unit 2, plate as shown in LRA Table 4.2.1-4. The applicant 

further stated that, because the planned exposures for each of the LSCS, Unit 2, ISP(E) 

capsules fall outside the specified fluence exposure range, an exception is taken to the 

GALL Report AMP XI.M31 “detection of aging effects” program element. In addition, the 

applicant revised LRA Section B.2.1.20, Table 3.1.1, and Table 3.1.2-2, consistent with the 

identification of the program exception.

In its response, the applicant stated that the heat numbers for the representative weld and plate 

materials in the ISP(E) capsules do not match the heat numbers of the LSCS, Unit 2, limiting 

beltline weld and plate materials. The applicant also stated that, in these cases, it computes the 

adjusted reference temperature (ART) using the method specified in BWRVIP-135, Revision 3, 

Procedure Number 2, “Recommended Guidance for the Use of ISP Surveillance Data when 

Vessel Material and Surveillance Material Heat Numbers Do Not Match.” The applicant further 

stated that this method determines the chemistry factor using Tables 1 and 2 of RG 1.99, 

“Radiation Embrittlement of Reactor Vessel Materials,” Revision 2, dated May 1988, based on 

the copper and nickel content of the actual LSCS reactor vessel weld and plate materials.
3-31

In addition, the applicant indicated that, because of the chemistry factor calculation using 

Tables 1 and 2 of RG 1.99, Revision 2, the LSCS embrittlement calculations for the reactor 

vessel are not affected by the fact that the representative ISP(E) surveillance capsules 

applicable to LSCS, Unit 2, have planned fluence exposure values outside of the fluence range 

specified in GALL Report AMP XI.M31. The applicant also indicates that this conclusion is 

supported by Section 7.2 of the staff-approved BWRVIP-86, Revision 1-A, which states, “There 

are some cases in which capsule fluence will be less than 100 percent of the 1/4T EOLE (End 

of License–Extended) fluence. However, the practical consequence is not significant. In most 

of those cases, the representative material in the capsule is not the same heat as the target 

vessel material; thus, the target plants will utilize Regulatory Guide 1.99, Revision 2, chemistry 

factor tables to determine a chemistry factor for calculating predicted embrittlement shift.”

In its review, the staff finds the applicant’s response acceptable because (1) the applicant 

clarified that the heat numbers of the ISP(E) representative plate and weld materials for LSCS, 

Unit 2, do not match the heat numbers of the limiting LSCS, Unit 2, plate and weld materials, 

respectively, (2) the applicant confirmed that, for those limiting materials of LSCS, Unit 2, the 

chemistry factor tables of RG 1.99, Revision 2, will be used to calculate chemistry factors and 

ARTs consistent with the guidance in RG 1.99, Revision 2, and (3) the applicant adequately 

identified a program exception regarding the neutron fluence range of the surveillance materials 

for the LSCS, Unit 2, reactor vessel. The staff’s concern described in RAI B.2.1.20-2 is 

resolved.

The staff also reviewed the portions of the “detection of aging effects,” “monitoring and 

trending,” “acceptance criteria,” and “corrective actions” program element associated with the 

exception to determine whether the program will be adequate to manage the aging effects for 

which it is credited. The staff’s evaluation of the exception and enhancements follows.

Exception 1. As discussed above, the applicant revised LRA Section B.2.1.20 to identify a 

program exception in its response dated June 25, 2015, to RAI B.2.1.20-2. In this exception, 

the applicant indicated that GALL Report AMP XI.M31 states that the program withdraws one 

capsule at an outage in which the capsule receives a neutron fluence of between 1 and 2 times 

the peak reactor vessel wall neutron fluence at the end of the period of extended operation and 

tests the capsule in accordance with the requirements of ASTM E185-82. The applicant also 

indicated that, because the neutron fluence values for LSCS, Unit 2, ISP(E) surveillance plate 

and weld materials, as planned in the BWRVIP ISP, are not consistent with this fluence range 

criterion, a program exception is identified. The applicant further provided justification for the 

program exception in its response to RAI B.2.1.20-2.

As previously discussed, the staff reviewed this exception against the corresponding program 

element in GALL Report AMP XI.M31 and finds it acceptable because the applicant clarified that 

(1) the heat numbers of the ISP(E) representative plate and weld materials for LSCS, Unit 2, do 

not match the heat numbers of the limiting LSCS, Unit 2, plate and weld materials, respectively 

and (2) for those limiting materials of LSCS, Unit 2, the chemistry factor tables of RG 1.99, 

Revision 2, will be used to calculate chemistry factors and ARTs, consistent with the guidance in 

RG 1.99, Revision 2.

Enhancements 1 and 2. As described in its letter dated August 26, 2015, the applicant 

identified enhancements to the Reactor Vessel Surveillance Program. In the enhancements, 

the applicant stated that (1) prior to the period of extended operation, a monitoring limit for 

neutron fluence will be established at the limiting Unit 1 axial weld (currently 39.15 effective 

full-power years (EFPY)) that corresponds to the axial weld failure probability of 5.02x10-6 per 
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reactor year specified in the Supplement to the Final Safety Evaluation of the BWRVIP-05 

Report dated March 7, 2000; and (2) prior to 39.15 EFPY, a probabilistic axial weld failure 

analysis will be completed for Unit 1 that demonstrates the 60-year axial weld failure probability 

is no greater than 5.02x10-6 per reactor year.

By letter dated October 23, 2015, the staff issued RAI 4.2.5-1a requesting that the applicant

(1) clarify whether the program includes an enhancement that operating restrictions will be 

established to ensure that the Unit 1 reactor is operated within the neutron fluence range for 

which the analysis remains valid, and if not, justify why such enhancement is not identified; and 

(2) clarify whether it will submit an updated analysis on the Unit 1 reactor vessel axial weld 

failure probability for staff’s review and approval sufficiently in advance of the reactor vessel 

fluence level exceeding the fluence range for which the applicant’s analysis remains valid 

(e.g., submittal at least 3 years before the analysis is projected to become invalid). In addition, 

the staff requested that the applicant ensure that the applicant’s program enhancements are 

consistent with the applicant’s response.

In its response dated October 29, 2015, the applicant revised LRA Sections A.2.1.20 and 

B.2.1.20 to include enhancements to the “monitoring and trending,” “acceptance criteria,” and 

“corrective actions” program elements. In this enhancement, the applicant stated that, prior to 

the period of extended operation, a maximum fluence limit of 6.25x1017 n/cm2 will be established 

for monitoring the limiting Unit 1 axial welds to ensure that the axial weld failure probability does 

not exceed 5.02x10-6 per reactor year. The staff noted that the limitation established in this 

enhancement is consistent with the applicant’s revised basis for accepting the reactor vessel 

failure probability analysis for LSCS, Unit 1, in accordance with 10 CFR 54.21(c)(1)(iii). SER 

Section 4.2.5 provides that the staff’s evaluation of the basis for accepting this time-limited 

aging analysis (TLAA) in accordance with 10 CFR 54.21(c)(1)(iii) using the enhancement and 

commitment in Commitment No. 20 of UFSAR Supplement Table A.5. In Commitment No. 20, 

the applicant committed, in part, to submitting a revised probability of failure analysis for LSCS,

Unit 1, for NRC review and approval at least 3 years prior to the time when the limiting Unit 1 

axial welds will reach a limiting neutron fluence of 6.25x1017 n/cm2 (E > 1.0 MeV).

The staff reviewed this enhancement against the corresponding program elements in GALL

Report AMP XI.M31 and finds it acceptable because (1) the enhancement will monitor changes 

in the fracture toughness properties of ferritic materials in the reactor vessel beltline region 

resulting from exposure to neutron irradiation and the thermal environment, which is in 

accordance with Appendix H to 10 CFR Part 50, and (2) the applicant has established operating 

restrictions on the monitoring of the neutron fluence for LSCS, Unit 1, reactor vessel axial welds 

consistent with the enhancement in Commitment No. 20, as stated in UFSAR Supplement 

Table A.5.

Operating Experience. LRA Section B.2.1.20 summarizes operating experience related to the 

applicant’s Reactor Vessel Surveillance program. The staff reviewed operating experience 

information in the application and during the audit to determine whether the applicable aging 

effects and industry and plant-specific operating experience were reviewed by the applicant. As 

discussed in the Audit Report, the staff conducted an independent search of the plant operating 

experience information to determine whether the applicant had adequately evaluated and 

incorporated operating experience related to this program. During its review, the staff identified 

operating experience for which it determined the need for additional clarification, which resulted 

in the issuance of RAIs, as discussed below.
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LRA Section B.2.1.20 indicates that the 120-degree capsule of LSCS, Unit 1, was withdrawn 

from the Unit 1 reactor vessel in 2010 as planned in the BWRVIP ISP. The LRA also indicates 

that the weld and plate surveillance materials were tested and that the test results were 

published in BWRVIP-250NP and BWRVIP Letter 2012-036. The LRA further indicates that the 

credible data for weld heat 1P3571 obtained from the surveillance testing were used to update 

the LSCS, Unit 1, Pressure-Temperature (P-T) curves.

The staff noted that BWRVIP-250NP indicates that the testing and evaluation of the surveillance 

capsules was completed in 2011. The staff also noted that the BWRVIP ISP described in 

BWRVIP-86, Revision 1, indicates that recently (within the past several years) a capsule 

containing the ISP surveillance weld material for LSCS, Unit 2, should have been withdrawn 

from a host plant for surveillance testing. However, the staff noted that LRA Section B.2.1.20 

does not discuss whether evaluation of the surveillance data for LSCS, Unit 2, is included in the 

LRA.

The staff also noted that LRA Tables 4.2.3-2 and 4.2.3-4 address ART and related data under 

the heading of “Integrated Surveillance Program Chemistry Values from BWRVIP-135, 

Revision 2.” The staff further noted that BWRVIP-135, Revision 2, was published as an ISP 

data source book in October 2009, before the most recent surveillance capsule withdrawals for 

LSCS, Units 1 and 2, as indicated in the references section of the LSCS, Unit 1, P-T limits 

report, dated January 3, 2014. Therefore, the staff needed additional information to confirm 

whether the LRA describes the evaluation of the most recent surveillance capsule data for 

LSCS, Units 1 and 2.

By letter dated May 29, 2015, the staff issued RAI B.2.1.20-3 requesting that the applicant 

clarify whether the LRA describes the evaluation of the most recent surveillance capsule data 

for LSCS, Units 1 and 2 (including LRA Tables 4.2.3-2 and 4.2.3-4).

In its response dated June 25, 2015, the applicant clarified that the LSCS, Unit 1, surveillance 

material chemistry values provided in LRA Table 4.2.3-2 are from the LSCS, Unit 1, 120-degree 

capsule that was withdrawn in 2010 and tested in 2011. The applicant also clarified that the 

LSCS, Unit 2, surveillance material chemistry values provided in LRA Table 4.2.3-4 are from the 

Susquehanna Steam Electric Station, Unit 1, 120-degree surveillance capsule that was 

withdrawn in March 2012 and is applicable to LSCS, Unit 2. The applicant further clarified that 

the references to BWRVIP-135, Revision 2, in the table headings are not current and that these 

references are updated to BWRVIP-135, Revision 3 (December 2014). In addition, the 

applicant stated that references to BWRVIP-135, Revision 2, in the text of LRA Section 4.2.3, 

Table 4.2.3-2, Table 4.2.3-4, and Reference 4.8.5 have also been updated to refer to

BWRVIP-135, Revision 3.

In its review, the staff finds the applicant’s response acceptable because the applicant clarified 

that the LRA includes the evaluation of the most recent surveillance data. The staff’s concern 

described in B.2.1.20-3 is resolved.

The operating experience discussed in LRA Section B.2.1.20 indicates that, because a 

damaged spring was discovered on the LSCS, Unit 2, 120-degree capsule in 2007, it was 

removed from the reactor vessel and placed in the spent fuel pool where it will remain 

indefinitely. The LRA also indicates that, because LSCS, Unit 2, is not a host plant of the 

BWRVIP ISP, the capsule does not require surveillance testing as part of the ISP.
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In its review of the operating experience, the staff noted that the LRA does not provide sufficient 

information on the applicant’s assessment of the plant-specific operating experience to ensure 

prevention of similar events that can impact the availability of reactor vessel surveillance 

capsules.

By letter dated May 29, 2015, the staff issued RAI B.2.1.20-4 requesting that the applicant 

provide the following information to demonstrate adequate assessment of the operating 

experience regarding reactor vessel surveillance capsules: (1) the role of the damaged spring, 

(2) the nature of the damage (including the cause), (3) the assessment of the plant-specific 

operating experience as applied to the other surveillance capsules, and (4) the identification of 

activities, as needed, to prevent similar events from occurring to the other capsules.

By letter dated June 25, 2015, the applicant responded to RAI B.2.1.20-4 as follows. In its 

response regarding the role of the spring, the applicant stated that, inside each reactor vessel in 

the beltline region where the fuel is located, upper and lower brackets are welded to the inside 

surface of the vessel wall that hold each of three surveillance capsule holders to the reactor 

vessel wall. The applicant also stated that the upper bracket has a 90-degree upward bend and 

that the lower bracket has a 90-degree downward bend. The applicant further stated that these 

upper and lower brackets are used to support the surveillance capsule assembly and to locate it 

in the proper position within the reactor vessel.

The applicant further stated that the top of the surveillance capsule holder has a fixed bracket, 

whereas the bottom of the capsule holder has a spring-loaded rod with a ring on its end used for 

attaching the holder to the lower bracket. In addition, the applicant stated that, to install the 

capsule holder, the ring at the bottom of the spring-loaded rod is engaged with the lower support 

bracket and that the capsule holder is raised to seat the top of the holder over the upper 

bracket. The applicant indicated that, as the capsule holder is raised, the spring inside the 

capsule holder allows the rod to extend out from the bottom of the holder, allowing the assembly 

to elongate. The applicant also indicated that the spring maintains compression on both 

brackets once the capsule holder is in position.

In its response regarding the nature of the damage, the applicant indicated that, in 2005, the 

LSCS, Unit 2, 120-degree surveillance capsule holder lower ring was found out of its design 

orientation and not properly engaged with the lower bracket. The applicant also indicated that 

the lower ring of the capsule holder was marginally located under the 90-degree downward 

bend portion of the bracket. The applicant indicated that it appeared that water flow had pushed 

the capsule holder away from the reactor vessel wall toward the shroud. The applicant further 

stated that the external components of the surveillance capsule holder were visually examined 

and that no additional deviations or defects were noted.

In addition, the applicant stated that, because the spring is mounted on the lower bracket rod, 

inside the surveillance capsule holder, it is not visible for inspection. The applicant stated that 

the cause of the damage could not be determined. The applicant also indicated that the 

apparent cause of the loss of preload was determined to be a damaged spring because removal 

of the spring force would allow the capsule holder to relax, thus permitting the ring to disengage 

from the lower bracket.

In its response regarding assessment of operating experience and actions to prevent similar 

events, the applicant indicated that LSCS, Unit 2, is not a host plant in the BWRVIP ISP. The 

applicant also indicated that since the Unit 2 120-degree capsule was not scheduled for testing, 

the capsule was removed from the reactor vessel in 2007 and was placed in the fuel pool for 
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long-term storage where it is available for future repair and reinsertion if needed. The applicant 

further indicated that each of the LSCS reactors has one remaining surveillance capsule 

installed.

In addition, the applicant stated that, during each RFO, a VT-3 visual examination is performed 

to verify that the remaining surveillance capsule holder is in place, intact, and has not been 

damaged during operation or other in-vessel activities. The applicant stated that every 2 years, 

when a VT-3 visual examination is performed on the welds connecting the attachment lugs to 

the reactor pressure vessel (RPV), the orientation of the capsule holder is also confirmed. The 

applicant also stated that additionally, during examinations of other components in the area of 

the capsule holder, the orientation of the capsule holder is confirmed. The applicant further 

stated that the corrective action program would identify and address any misalignment of the 

surveillance capsule holder.

In its review, the staff finds the applicant’s response acceptable because the applicant clarified 

that (1) the spring inside the surveillance capsule holder is used to maintain compressive 

loading for installation of surveillance capsules, (2) in the 2015 operating experience, the lower 

support ring of the Unit 2 capsule holder was found out of its design orientation, and no other 

adverse indications were observed from the visual examination of the external components of 

the capsule holder, (3) the LSCS, Unit 2, 120-degree capsule was placed in the spent fuel pool 

for potential future use; (4) each of the LSCS reactors has only one remaining surveillance 

capsule installed, and (5) visual inspections are periodically performed on the surveillance 

capsule holders in the reactor vessels to ensure that the capsule holders remain intact. The 

staff’s concern described in RAI B.2.1.20-4 is resolved.

Based on its audit and review of the application and the applicant’s responses to 

RAIs B.2.1.20-3 and B.2.1.20-4, the staff finds that the applicant has appropriately evaluated 

plant-specific and industry operating experience and that implementation of the program has 

resulted in the applicant taking corrective actions. In addition, the staff finds that the conditions 

and operating experience at the plant are bounded by those for which GALL Report 

AMP XI.M31 was evaluated.

UFSAR Supplement. LRA Section A.2.1.20 provides the UFSAR supplement for the applicant’s 

Reactor Vessel Surveillance program. The staff reviewed this UFSAR supplement description 

of the program against the recommended description for this type of program as described in 

SRP-LR Table 3.0-1. The staff identified a concern that required the issuance of an RAI as 

described below.

LRA Section A.2.1.20 states that the schedule for removing surveillance capsules is in 

accordance with the timetable specified in BWRVIP-86-A for the current license term and for the 

period of extended operation. The staff noted that the abstract section of BWRVIP-86, 

Revision 1-A, “Updated BWR Integrated Surveillance Program (ISP) Implementation Plan,” 

dated October 2012, states the following:

This report identifies the test matrix of capsules containing the representative 

weld and plate materials and the planned schedule for withdrawal and testing. 

The content of BWRVIP-116 (ISP for the License Renewal Period) was merged 

with BWRVIP-86-A (ISP Implementation Plan) to provide a single, 

comprehensive implementation plan for the ISP during both the original and 

renewed license period. This report (BWRVIP-86, Revision 1-A) incorporates 

changes proposed by the BWRVIP in response to the NRC Request for 
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Additional Information, recommendations in the NRC Safety Evaluation and other 

necessary revisions identified since the previous publication of this report.

During the audit, the staff noted that the applicant’s implementation procedure 

(ER-ABB-331-103, Revision 3) for the Reactor Vessel Surveillance program includes references 

to both BWRVIP-86-A and BWRVIP-86, Revision 1-A. As discussed above, the staff also noted 

that BWRVIP-86-A (October 2002) describes the ISP implementation plan for the original 

license period developed before the issuance of BWRVIP-86, Revision 1, whereas BWRVIP-86, 

Revision 1-A, describes the staff-approved ISP implementation plan for both the original and 

extended license period. The staff further noted that the UFSAR supplement description for the 

Reactor Vessel Surveillance program includes a reference to BWRVIP-86-A (October 2002) 

rather than to BWRVIP-86, Revision 1-A (October 2012).

By letter dated May 29, 2015, the staff issued RAI B.2.1.20-1 requesting that the applicant 

justify why the UFSAR supplement does not include a reference to BWRVIP-86, Revision 1-A 

(October 2012). The staff also requested alternatively that the applicant revise the UFSAR 

supplement to include a reference to BWRVIP-86, Revision 1-A, as the ISP implementation 

plan.

In its response dated June 25, 2015, the applicant stated that the UFSAR supplement

presented in LRA Section A.2.1.20 and the program summary presented in LRA 

Section B.2.1.20 are revised to change the reference from BWRVIP-86-A to BWRVIP-86, 

Revision 1-A. The applicant also stated that LRA Section 3.1.2.2.3 is also revised to clarify that 

the schedule for removing surveillance capsules is in accordance with the timetable specified in 

BWRVIP-86, Revision 1-A, for the current license term and for the period of extended operation. 

The applicant further stated that Exelon procedure ER-AB-331-103 will also be revised to 

change the reference to BWRVIP-86, Revision 1-A.

In its review, the staff finds the applicant’s response acceptable because the applicant provided

an adequate revision to the LRA and implementing procedure, including LRA Sections A.2.1.20 

(UFSAR supplement) and B.2.1.20 (program description), that correctly refers to BWRVIP-86, 

Revision 1-A, instead of BWRVIP-86-A. Therefore, the UFSAR supplement for the Reactor 

Vessel Surveillance program is consistent with the corresponding program description in 

SRP-LR Table 3.0-1. The staff’s concern described in RAI B.2.1.20-1 is resolved. The staff 

finds that the information in the UFSAR supplement, as amended by letter dated June 25, 2015, 

is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Reactor Vessel Surveillance 

program, the staff determined that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the exception 

and its justification and determined that the AMP, with the exception, is adequate to manage the 

applicable aging effects. In addition, the staff reviewed the enhancements and confirmed that 

their implementation before the period of extended operation will make the AMP adequate to 

manage the applicable aging effects. The staff concludes that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).
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One-Time Inspection

Summary of Technical Information in the Application. LRA Section B.2.1.21 describes the new 

One-Time Inspection program as consistent with GALL Report AMP XI.M32, “One-Time 

Inspection.” The LRA states that the One-Time Inspection program manages loss of material, 

cracking, and reduction of heat transfer in piping, piping components, piping elements, heat 

exchangers, and other components within the scope of license renewal. The LRA also states 

that the One-Time Inspection program proposes to manage these aging effects with inspections 

that focus on locations that are isolated from flow streams (i.e., that are stagnant or that have 

low flow for extended periods and are susceptible to the gradual accumulation or concentration 

of agents that promote certain aging effects). Additionally, the One-Time Inspection program is 

used to verify the system-wide effectiveness of the Water Chemistry (LRA Section B.2.1.2), Fuel 

Oil Chemistry (LRA Section B.2.1.19), and Lubricating Oil Analysis (LRA Section B.2.1.26) 

programs, which are designed to prevent or minimize aging to the extent that it will not cause a 

loss of intended function.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M32. Based on its audit, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M32.

Operating Experience. LRA Section B.2.1.21 summarizes operating experience related to the 

One-Time Inspection program. In October 2012 the applicant performed a UT examination of a 

nonsafety-related service water system pipe and identified localized pitting where the wall 

thickness was below minimum wall thickness requirements. The pitting was entered into the 

corrective action program. An evaluation was performed, and the applicant determined that the 

piping in its current condition would continue to meet its function of maintaining pressure 

boundary and structural integrity, but it would need to be replaced during the February 2013 

RFO.

In March 2012, the applicant performed a UT examination of the safety-related 1A fuel pool 

emergency makeup pump suction piping and identified localized pitting where the wall thickness 

was below the ASME Code minimum wall thickness requirements. The pitting was entered into 

the corrective action program. In 2009, the applicant performed another UT at the same 

location of the pipe. An evaluation was completed and determined that the results were 

acceptable based on the rate of material loss, and through-wall degradation was predicted to 

occur in approximately 2015. Because the piping had already reached its minimum wall 

thickness and had active pitting, it was concluded that this piping could no longer perform its 

design function. As a result, the affected fuel pool emergency makeup pump suction piping and 

the 1A fuel pool emergency makeup pump were isolated from service and subsequently 

replaced.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.
3-38

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M32 was evaluated.

UFSAR Supplement. LRA Section A.2.1.21 provides the UFSAR supplement for the One-Time 

Inspection program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant committed to implement the new One-Time Inspection program

within 10 years before the period of extended operation for managing the effects of aging for 

applicable components. The staff finds that the information in the UFSAR supplement is an 

adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s One-Time Inspection

program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Selective Leaching

Summary of Technical Information in the Application. LRA Section B.2.1.22 describes the new 

Selective Leaching program as consistent with GALL Report XI.M33, “Selective Leaching,” as 

modified by LR-ISG-2011-03 and LR-ISG-2012-02. The LRA states that the program ensures 

the integrity of gray cast iron and copper alloy (with greater than 15-percent zinc) components

that are susceptible to loss of material due to selective leaching. The LRA also states that there 

are no in-scope aluminum bronze components with an aluminum content greater than 

8 percent. The program manages selective leaching in the service environments of raw water, 

closed cycle cooling water, treated water, wastewater, and soil. The program will manage this 

aging effect through a one-time visual inspection coupled with hardness measurement or other 

mechanical examination techniques. The LRA also states the minimum population size of 

components inspected by this program and states that those inspections should be performed 

on the bounding or leading components most susceptible to aging due to time in service, 

severity of operating condition, and lowest design margin. Subsequent to the issuance of the 

SER with open items, the staff issued LR-ISG-2015-01. By letter dated April 13, 2016, the 

applicant revised its Selective Leaching program to credit the recommendations associated with 

the selection of buried components for selective leaching inspections discussed in 

LR-ISG-2015-01. The applicant also removed reference to LR-ISG-2011-03.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M33.

Staff-Identified Difference. LRA Section B.2.1.22 does not include aluminum bronze as a 

material susceptible to selective leaching and does not take an exception to GALL Report 

AMP XI.M33. This staff-identified difference affects the “program description.” The staff’s

review of the LRA and UFSAR supplement confirmed that there are no aluminum bronze 

components in the scope of license renewal.
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The staff reviewed the difference between the LRA AMP and the GALL Report AMP, which 

should have been identified as an exception, and finds it acceptable because there are no 

aluminum bronze components in the scope of license renewal. Therefore, the aspects of the 

AMP associated with the staff-identified difference are not applicable.

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M33 as modified by LR-ISG-2011-03 and LR-ISG-2012-02. 

The staff also reviewed the difference between the LRA AMP and the GALL Report AMP 

associated with the “program description” and dispositioned the staff-identified difference as 

acceptable. The staff finds that the AMP, with the staff-identified exceptions, is adequate to 

manage the applicable aging effects.

The staff finds the applicant’s use of the recommendations associated with the selection of 

buried components for selective leaching inspections discussed in LR-ISG-2015-01 in lieu of 

LR-ISG-2011-03 acceptable. As stated in LR-ISG-2015-01, “the recommendations in 

AMP XI.M41 related to reductions in the extent of inspections for AMP XI.M33, ‘Selective 

Leaching,’ have been moved to AMP XI.M33 [from LR-ISG-2011-03] with no technical 

changes.”

Operating Experience. LRA Section B.2.1.22 summarizes operating experience related to the 

Selective Leaching program. The staff reviewed operating experience information in the 

application and during the audit to determine whether the applicable aging effects and industry 

and plant-specific operating experience were reviewed by the applicant. As discussed in the 

Audit Report, the staff conducted an independent search of the plant operating experience 

information to determine whether the applicant had adequately evaluated and incorporated

operating experience related to this program. The staff did not identify any operating 

experience that would indicate that the applicant should consider modifying its proposed 

program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M33 was evaluated.

UFSAR Supplement. LRA Section A.2.1.22 provides the UFSAR supplement for the Selective 

Leaching program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant committed to implement the new Selective Leaching program 

before the period of extended operation for managing the effects of aging for applicable 

components. The staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Selective Leaching program, 

the staff concludes that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. In addition, the staff evaluated a staff-identified difference 

and determined that the AMP, with the staff-identified difference, is adequate to manage the 

applicable aging effects. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation, as required by 
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10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Unit 1 One-time Inspection of ASME Code Class 1 Small-Bore Piping

Summary of Technical Information in the Application. LRA Section B.2.1.23 describes the 

applicant’s Unit 1 One-time Inspection of ASME Code Class 1 Small-Bore Piping program, as a 

new condition motoring program that will manage cracking of small-bore reactor coolant piping 

consistent with GALL Report AMP XI.M35. The LRA states that the program will perform

one-time inspection of a sample of ASME Code Class 1 piping less than nominal pipe size 

(NPS) 4-inches and greater than or equal to NPS 1-inch in Unit 1. The LRA also states that a 

one-time inspection program is applicable to LSCS, Unit 1, to adequately manage the aging 

effect of cracking for ASME Code Class 1 small-bore piping due to SCC, cyclical loading, and 

thermal stratification or thermal turbulence. The LRA further states that use of the program is 

consistent with GALL Report AMP XI.M35, which is limited to plants that have not experienced 

cracking of ASME Code Class 1 small-bore piping due to SCC, cyclical loading, and thermal 

stratification or thermal turbulence. The LRA states that the scope of the program includes 

one-time inspection of a sample of ASME Code Class 1 piping less than NPS 4-inches and 

greater than or equal to NPS 1-inch for pipes, fittings, branch connections, and full penetration 

(butt) welds and partial penetration (socket) welds.

The LRA originally included a single One-time Inspection of ASME Code Class 1 Small-Bore 

Piping program to manage cracking of small-bore reactor coolant piping in both units at LSCS. 

However, during the review, the applicant revised the program to only apply to LSCS, Unit 1, 

and created a new plant-specific program to manage cracking of small-bore reactor coolant 

piping in LSCS, Unit 2. The staff evaluation below concerns the LSCS, Unit 1, program, and the 

plant-specific program for LSCS, Unit 2, is discussed in SER Section 3.0.3.3.2.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M35.

For the “detection of aging effects” program element, the staff determined the need for 

additional information, which resulted in the issuance of RAIs, as discussed below.

The staff noted that GALL Report AMP XI.M35 states under the “detection of aging effects” 

program element that “[t]his inspection should be performed at a sufficient number of locations 

to ensure an adequate sample. This number, or sample size, is based on susceptibility, 

inspectability, dose considerations, operating experience, and limiting locations of the total 

population of ASME Code Class 1 small-bore piping locations.” Because LRA 

Sections B.2.1.23 and A.2.1.23 did not provide the total number of in-scope small-bore piping 

welds, it was not clear to the staff how the inspection sample will be selected and thus whether 

a sufficient number of locations will be inspected to ensure that cracking will be adequately 

managed. By letter dated July 7, 2015, the staff issued RAI B.2.1.23-1, requesting that the 

applicant provide the population of in-scope small-bore piping welds for each weld type 

(i.e., butt welds and socket welds) at each unit. The staff also requested that, based on the 

population, the applicant justify the adequacy of the selected sample size for each type of weld.

By letter dated August 6, 2015, the applicant responded to RAI B.2.1.23-1 and provided the 

approximate population of ASME Code Section III, Class 1, in-scope small-bore piping butt 
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welds and socket welds for both units. The applicant stated that the one-time inspection sample

size for LSCS, Unit 1, will include at least 3 percent of the population of butt welds (108) and the

population of socket welds (483), with a maximum of 10 butt welds and socket welds. The 

applicant also stated that the sampling methodology for LSCS, Unit 1, is consistent with the 

guidance provided in GALL Report AMP XI.M35 for a unit that has not experienced age-related 

failure of in-scope small-bore piping. The applicant further stated that because LSCS, Unit 2, 

has experienced age-related failure of a Class 1 small-bore piping, a plant-specific periodic 

inspection program will be implemented for LSCS, Unit 2, consistent with the guidance provided 

in GALL Report AMP XI.M35. As part of its response, the applicant revised LRA 

Sections A.2.1.23 and B.2.1.23 to include the number of LSCS, Unit 1, small-bore piping welds.

The staff noted that the applicant provided information on the total number of small-bore piping 

welds and the selected sample sizes. The staff also noted that the applicant’s sampling 

methodology for the population of its small-bore piping welds is consistent with the inspection 

sampling guidance provided in GALL Report AMP XI.M35, which recommends that the 

inspection plan should include 3 percent of the weld population or a maximum of 10 welds for 

each weld type for units that have more than 30 years of operation and have not experienced 

age-related failures (LSCS, Unit 1). The staff’s concern described in RAI B.2.1.23-1 for LSCS, 

Unit 1, is resolved. The staff further noted that the applicant stated that it will implement a 

plant-specific periodic inspection program for LSCS, Unit 2, consistent with the guidance 

provided in GALL Report AMP XI.M35. The staff’s evaluation of the applicant’s plant-specific 

AMP for LSCS, Unit 2, is provided in SER Section 3.0.3.3.2.

The staff noted that GALL Report AMP XI.M35 states, under the “detection of aging effects” 

program element, that the one-time inspection under this program does not apply to plants that 

have experienced cracking in ASME Code Class 1 small-bore piping due to stress corrosion, 

cyclical (including thermal, mechanical, and vibration fatigue) loading, or thermal stratification 

and thermal turbulence. LRA Section B.2.1.23 states that LSCS, Units 1 and 2, have not 

experienced this type of cracking. However, the LRA also states that the applicant’s review 

identified two issues with ASME Code Class 1 small-bore piping welds during startup of LSCS, 

Unit 1, in 1983. The LRA further states that a pinhole leak was identified on an ASME Code 

Class 1 small-bore socket weld in 2005 at LSCS, Unit 2. The applicant states that the pinhole 

leak was caused by an inclusion or defect in a weld repair performed in 1995. Based on the 

staff’s review of the available information, the staff determined that the documented failures 

were most likely age related and caused by vibration and/or thermal fatigue. Given the 

documented operating experience at LSCS of multiple failures of socket welds, it is not clear to 

the staff why the applicant has determined that a one-time inspection of its socket weld 

population would be applicable.

By letter dated July 7, 2015, the staff issued RAI B.2.1.23-2 and requested that the applicant 

provide information in terms of metallurgical analysis to support the determination that the 

multiple socket weld failures described above do not constitute failures of ASME Code Class 1 

small-bore piping due to cyclical mechanical or thermal fatigue. The staff further requested that, 

if the referenced failures of ASME Code Class 1 small-bore socket welds could be attributed to 

vibration or thermal fatigue induced cracking, the applicant should provide a plant-specific 

program that includes periodic inspections; otherwise, it should justify how the One-time 

Inspection of ASME Code Class 1 Small Bore Piping program will adequately manage cracking 

consistent with the guidance provided in the GALL Report AMP.

By letter dated August 6, 2015, the applicant provided its response to RAI B.2.1.23-2 and stated 

that the socket weld failures for LSCS, Unit 1, on the drain line connections to the main steam 
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isolation valves, occurred after less than 9 months of intermittent service during the initial cycle 

of the unit. The applicant also stated that the causes for these failures were determined to be 

improper welding, installation, less-than-optimum preheat treatment, and choice of welding 

electrodes. The applicant further stated that the corrective actions from these failures included 

design changes and rewelding all similar socket welds on the drain line connections to the main 

steam isolation valves using improved welding procedures and using instrumentation to verify 

that abnormal vibrations and frequencies do not exist. The applicant stated that LSCS, Unit 1, 

has operated for more than 32 years with no subsequent indications of cracking or degradation 

on any of its ASME Class 1 small-bore piping; therefore, the One-time Inspection of ASME 

Code Class 1 Small-Bore Piping program is considered applicable and consistent with the 

guidance provided in GALL Report AMP XI.M35.

The staff noted that, based on the operating information provided in the RAI response, the 

failures in 1983 at LSCS, Unit 1, were most likely fabrication related and not age related and 

were successfully mitigated by the applicant’s design changes. Because the issues related to 

the failures were successfully mitigated, and because the failures were not attributed to 

age-related degradation as described in GALL Report AMP XI.M35, the staff finds the 

applicant’s use of the One-time Inspection of ASME Code Class 1 Small-Bore Piping program to 

manage the aging of the LSCS, Unit 1, acceptable. Therefore, the staff’s concern in 

RAI B.2.1.23-2, as it related to LSCS, Unit 1, is resolved. The staff’s evaluation of the 

applicant’s plant-specific AMP for LSCS, Unit 2, is provided in SER Section 3.0.3.3.2.

Based on its audit and review of the applicant’s responses to RAIs B.2.1.23-1 and B.2.1.23-2, 

the staff finds that program elements 1 through 6 for which the applicant claimed consistency 

with the GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M35.

Operating Experience. LRA Section B.2.1.23 summarizes operating experience related to the 

applicant’s program. The LRA states that the applicant performed an extensive review of plant 

operating experience of ASME Code Class 1 small-bore piping, which included review of the 

corrective action program database, review of correspondence to the NRC, and interviews with 

the LSCS ISI program owner. The applicant stated that the review did not identify any cracking 

of ASME Code Class 1 piping due to fatigue or SCC. The applicant also stated that the review 

identified two issues with welds during startup in 1983 and a pinhole leak in 2005. The 

applicant further stated that the root cause evaluations concluded that these issues were 

fabrication related.

The applicant stated that, since 2002 (for LSCS, Unit 1) and 2003 (for LSCS, Unit 2), it has 

performed periodic examinations of ASME Code Class 1 small-bore piping butt welds and 

socket welds, and there were no unacceptable indications except for the pinhole leak in 2005.

As stated earlier, the applicant provided additional operating experience information in response 

to RAI B.2.1.23-2 and has determined that the pinhole leak for Unit 2 was age related. 

Consequently, the applicant stated that for LSCS, Unit 2, it will implement a plant-specific AMP 

that includes periodic inspections to manage aging of ASME Class 1 small-bore piping. (The 

staff’s evaluation of this program is discussed in SER Section 3.0.3.3.2.)

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 
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whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program for LSCS, Unit 1.

Based on its audit, review of the application, and review of the applicant’s response to 

RAI B.2.1.23-2, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which the GALL Report AMP XI.M35 was 

evaluated.

UFSAR Supplement. LRA Section A.2.1.23, as revised by letter dated August 6, 2015, provides 

the UFSAR supplement for the Unit 1 One-time Inspection of ASME Code Class 1 Small-Bore 

Piping program at LSCS, Unit 1. The staff reviewed this UFSAR supplement description of the 

program and noted that it is consistent with the recommended description in SRP-LR

Table 3.0–1. The staff also noted that the applicant committed to implement the new Unit 1 

One-time Inspection of ASME Code Class 1 Small-Bore Piping program within the 6 years 

before the period of extended operation. The staff finds that the information in the UFSAR 

supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Unit 1 One-time Inspection of 

ASME Code Class 1 Small-Bore Piping program at LSCS, Unit 1, the staff concludes that those 

program elements for which the applicant claimed consistency with the GALL Report are 

consistent. The staff concludes that the applicant has demonstrated that the effects of aging will 

be adequately managed so that the intended function(s) will be maintained consistent with the 

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d).

External Surfaces Monitoring of Mechanical Components

Summary of Technical Information in the Application. LRA Section B.2.1.24 describes the 

External Surfaces Monitoring of Mechanical Components program as a new program that is 

consistent with GALL Report AMP XI.M36, “External Surfaces Monitoring of Mechanical 

Components,” as modified by LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire 

Water Systems, Atmospheric Storage Tanks, and Corrosion under Insulation,” and 

LR-ISG-2011-03, “Changes to the Generic Aging Lessons Learned (GALL) Report Revision 2 

Aging Management Program (AMP) XI.M41, ‘Buried and Underground Piping and Tanks.’” The 

LRA states that the program is a condition monitoring program that directs that visual 

inspections of external surfaces of components must be performed during system inspections 

and walkdowns. The LRA also states that the AMP manages the aging effects of cracking, 

hardening and loss of strength, loss of material, and reduced thermal insulation resistance of 

metallic and elastomeric materials through visual inspection of external surfaces for evidence of 

loss of material, cracking, and changes in material properties. The LRA further states that it will 

perform periodic representative inspection of outdoor insulated components except tanks and of 

indoor insulated components and tanks where the process fluid temperature is below the dew 

point. The program also specifies that acceptance criteria for each component and aging effect 

combination are defined to ensure that the need for corrective actions is identified.
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Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M36, as modified by 

LR-ISG-2011-03 and LR-ISG-2012-02. For the “parameters monitored or inspected” and 

“detection of aging effects” program elements, the staff determined the need for additional 

information, which resulted in the issuance of RAIs, as discussed below.

The “detection of aging effects” program element in GALL Report AMP XI.M36 recommends 

that “[t]ightly adhering insulation is considered to be a separate population from the remainder of 

insulation installed on in-scope components. The entire population of in-scope piping that has 

tightly adhering insulation is visually inspected for damage to the moisture barrier with the same 

frequency as for other types of insulation inspections.” LRA Section B.2.1.24 states in the 

“program description” that “the program does not require removal of tightly-adhering insulation 

that is impermeable to moisture unless there is evidence of damage to the moisture barrier. 

Instead, the program includes visual inspection of the entire accessible population of piping and 

components during each 10-year period of the period of extended operation.” It is not clear to 

the staff which criteria were used to identify components as “accessible” and what the basis for 

the acceptability of not inspecting inaccessible insulation was. By letter dated July 7, 2015, the

staff issued RAI B.2.1.24-1 requesting that the applicant explain the criteria used in establishing 

categories of the “accessible” population and justify program adequacy if only the “accessible” 

population is inspected. In addition, the RAI requested the insulation material type and 

environment for the inaccessible insulation.

In its response dated August 6, 2015, the applicant stated that it had reviewed all of the tightly 

adhering insulation locations and had confirmed that there is no insulation in these locations that 

would be considered inaccessible. As a result, the applicant updated LRA Section B.2.1.24 and 

removed the word “accessible” from the program. The staff finds the applicant’s response 

acceptable because visual inspections will be performed consistent with GALL Report 

AMP XI.M36. The staff’s concern described in RAI B.2.1.24-1 is resolved.

The “detection of aging effects” program element in GALL Report AMP XI.M36 recommends 

that “[f]or all outdoor components (except tanks) and any indoor components exposed to 

condensation (because the in-scope component is operated below the dew point), inspections 

are conducted of each material type (e.g., steel, stainless steel, copper alloy, aluminum) and 

environment (e.g., air-outdoor, moist air, air accompanied by leakage) where condensation or 

moisture on the surfaces of the component could occur routinely or seasonally.” LRA 

Section B.2.1.24 states in the “program description” that “[i]nspections are conducted for each 

external environment where condensation or moisture on the surfaces of the component could 

occur routinely or seasonally.” It is not clear to the staff that “each external environment” will 

include each material type and environment as provided in the GALL Report guidance. By letter 

dated July 7, 2015, the staff issued RAI B.2.1.24-2 requesting that the applicant explain what 

“each external environment” refers to and provide an exception with justification if any 

material/environment combination will be exempted.

In its response dated August 6, 2015, the applicant stated that the phrase “external 

environments” refers to the two environments that concern the program for corrosion under 

insulation: outdoor air and indoor air. The applicant also stated that inspections for corrosion 

under insulation will include “all material/environment combinations, and, therefore, no 

material/environment combinations will be exempted.” As a result, the applicant updated LRA 

Section B.2.1.24 to make the clarification. The staff finds the applicant’s response acceptable 

because, consistent with GALL Report AMP XI.M36, the applicant will inspect for corrosion 
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under insulation on all material/environment combinations and will not take any exemptions to 

any material/environment combinations. The staff’s concern described in RAI B.2.1.24-2 is 

resolved.

Based on its audit and review of the applicant’s responses to RAIs B.2.1.24-1 and B.2.1.24-2, 

the staff finds that program elements 1 through 6 for which the applicant claimed consistency 

with the GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M36.

Operating Experience. LRA Section B.2.1.24 summarizes operating experience related to the 

External Surfaces Monitoring of Mechanical Components program. The LRA provides several 

examples related to external surfaces monitoring from 2003 to 2009. In one instance, during a 

walkdown of the LSCS, Unit 2, service air in 2009, a leaking valve was noticed to have caused 

material degradation to the equipment below it. This condition was entered into the corrective 

action program. Actions included an assessment and a repair before loss of intended function 

of the affected components. Another instance describes that, during operator rounds in 2008, a 

leaking service water pipe was identified in the Lake Screen House. The condition was entered 

into the corrective action program. The applicant performed an evaluation and discovered a 

through-wall leak in the piping. The applicant also performed an extent of condition review on 

other insulated piping in environments with similar wetting conditions. Repairs were made as 

appropriate.

The staff reviewed operating experience information in the application during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M36, as modified by LR-ISG-2011-03 and LR-ISG-2012-02, was 

evaluated.

UFSAR Supplement. LRA Section A.2.1.24 provides the UFSAR supplement for the External 

Surfaces Monitoring of Mechanical Components program. The staff reviewed this UFSAR 

supplement description of the program and noted that it is consistent with the recommended 

description in SRP-LR Table 3.0-1, as modified by LR-ISG-2012-02. The staff also noted that 

the applicant committed to implementing the new External Surfaces Monitoring of Mechanical 

Components program to manage the effects of aging prior to the period of extended operation. 

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program.

Conclusion. On the basis of its audit and review of the applicant’s External Surfaces Monitoring 

of Mechanical Components program, the staff concludes that those program elements for which 

the applicant claimed consistency with the GALL Report are consistent. The staff concludes 

that the applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR for this AMP 
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and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Summary of Technical Information in the Application. LRA Section B.2.1.25 describes the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program as a 

new program that is consistent with GALL Report AMP XI.M38, “Inspection of Internal Surfaces 

in Miscellaneous Piping and Ducting Components,” as modified by LR-ISG-2012-02, “Aging 

Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and 

Corrosion under Insulation.” The LRA states that the program is a condition monitoring program 

intended to manage the applicable aging effects by directing that visual inspections of internal 

surfaces of components within the scope of license renewal must be performed when they are 

made accessible during periodic system and component surveillances or during the 

performance of maintenance activities. The LRA also states that the program provides 

assurance that condensation, diesel exhaust, and wastewater environments are not causing 

material degradation that could result in loss of intended function. The program specifies 

examination methodology as visual inspections of the internal surfaces of metallic components 

and other components that are exposed to condensation, diesel exhaust, and wastewater. The 

program also specifies that acceptance criteria for each component and aging effect

combination are defined to ensure that the need for corrective actions is identified.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M38, as modified by 

LR-ISG-2012-02. Based on its audit, the staff finds that program elements 1 through 6 for which 

the applicant claimed consistency with the GALL Report are consistent with the corresponding 

program elements of GALL Report AMP XI.M38.

Operating Experience. LRA Section B.2.1.25 summarizes operating experience related to the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program. The 

LRA provides an example related to corrosion in plant floor drain piping. The LRA states that 

the program will include periodic inspections of the subject drain systems to ensure that 

recurring aging effects are adequately managed during the period of extended operation.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M38, as modified by LR-ISG-2012-02, was evaluated.

UFSAR Supplement. LRA Section A.2.1.25 provides the UFSAR supplement for the Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components program. The staff 

reviewed this UFSAR supplement description of the program and noted that it is consistent with 
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the recommended description in SRP-LR Table 3.0-1, as modified by LR-ISG-2012-02. The 

staff also noted that the applicant committed to implementing the program to manage the effects 

of aging before the period of extended operation. The staff finds that the information in the 

UFSAR supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components program, the staff concludes that 

those program elements for which the applicant claimed consistency with the GALL Report are 

consistent. The staff concludes that the applicant has demonstrated that the effects of aging will 

be adequately managed so that the intended function(s) will be maintained consistent with the 

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). Based on its 

review, the staff concludes that the UFSAR supplement provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Lubricating Oil Analysis

Summary of Technical Information in the Application. LRA Section B.2.1.26 describes the 

existing Lubricating Oil Analysis program as consistent with the GALL Report AMP XI.M39, 

Lubricating Oil Analysis program. The LRA states that the AMP addresses loss of material and 

reduction of heat transfer in piping, piping components, piping elements, heat exchangers, and 

tanks within the scope of license renewal exposed to a lubricating oil environment. The LRA 

also states that the AMP proposes to manage these aging effects through a condition 

monitoring program that provides monitoring of the oil condition.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M.39. Based on its audit, the 

staff finds that program elements 1 through 6 for which the applicant claimed consistency with 

the GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M39.

Operating Experience. LRA Section B.2.1.26 summarizes operating experience related to the 

Lubricating Oil Analysis program. In May 2010 the applicant performed an oil analysis for the 

diesel fire pump engine and noted that the trending data indicated an increase in wear particle 

count (WPC). The applicant entered this into the corrective action program. The applicant used 

a direct reading ferrograph instrument to measure WPC (i.e., the sum of large particles (Dl) of 5-

to 10-μm size plus small particles (Ds) of less than 5-μm size). The WPC value of 104 placed 

the “A” diesel fire pump engine above the expected WPC value of 100. In the same month, the 

applicant performed an oil flush and change-out of the lubricating oil for the diesel fire pump 

engine. In November 2010 the lubricating oil was sampled and analyzed, and again the 

analysis identified a high WPC. The lubricating oil analysis also indicated higher than expected 

levels of iron and lead, which are typically associated with cylinder, bearing, or bushing wear. 

The performance of analytical ferrography validated the lubricating oil analysis sample results. 

In December 2010 the applicant overhauled this engine and performed another oil flush and 

change-out of the lubricating oil for the diesel fire pump engine. Subsequent lubricating oil 

sampling and analyses for the “A” diesel fire pump engine have demonstrated acceptable WPC 

values and a decreasing trend in WPC.

In August 2007 the applicant performed a lubricating oil analysis of the “B” diesel fire pump 

engine and identified contamination particulates consisting of small ferrous wear particles, 

copper wear particles, iron oxide, and sealant material. The applicant entered this into the 
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corrective action program, and an issue report was initiated. Chemical analysis further indicated 

a higher-than-normal level of sodium, suggesting the presence of engine coolant in the lube oil.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M39 was evaluated.

UFSAR Supplement. LRA Section A.2.1.26 provides the UFSAR supplement for the Lubricating 

Oil Analysis program. The staff reviewed this UFSAR supplement description of the program 

and noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The 

staff also noted that the applicant committed to ongoing implementation of the existing 

Lubricating Oil Analysis program for managing the effects of aging for applicable components 

during the period of extended operation. The staff finds that the information in the UFSAR 

supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Lubricating Oil Analysis 

program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

10 CFR Part 50, Appendix J

Summary of Technical Information in the Application. LRA Section B.2.1.32 describes the 

existing 10 CFR Part 50, Appendix J program as consistent with GALL Report AMP XI.S4, 

“10 CFR Part 50, Appendix J.” The LRA states that the AMP addresses loss of material, loss of 

leak tightness, and loss of bolting preload in the primary containment and systems penetrating 

containment. The program also manages loss of sealing due to degradation of containment 

gaskets and seals. The environments include uncontrolled air-indoor and treated water. The 

LRA further states that the AMP manages these aging effects through pressure tests performed 

in accordance with the regulations in Appendix J, “Primary Reactor Containment Leakage 

Testing for Water-Cooled Power Reactors,” to 10 CFR Part 50, “Domestic Licensing of 

Production and Utilization Facilities.”

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.S4. Based on its audit, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 
3-49

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.S4.

Operating Experience. LRA Section B.2.1.32 summarizes operating experience related to the 

10 CFR Part 50, Appendix J program. The LRA provides the results of the last Type A 

integrated leak rate test for both units and notes that they were both below the allowable limit. 

The LRA further discusses an isolation valve that failed a local leak rate test in 2011. The valve 

was repaired and the subsequent local leak rate test was completed with acceptable results.

The staff reviewed the operating experience information in the application and during the audit 

to determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.S4 was evaluated.

UFSAR Supplement. LRA Section A.2.1.32 provides the UFSAR supplement for the 

10 CFR Part 50, Appendix J program. The staff reviewed this UFSAR supplement description 

of the program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff also noted that the applicant committed to ongoing implementation of the 

existing 10 CFR Part 50, Appendix J program for managing the effects of aging for applicable 

components during the period of extended operation (Commitment No. 32). The staff finds that 

the information in the UFSAR supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s 10 CFR Part 50, Appendix J 

program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Protective Coating Monitoring and Maintenance Program

Summary of Technical Information in the Application. LRA Section B.2.1.36 describes the 

existing Protective Coating Monitoring and Maintenance Program as consistent with 

GALL Report AMP XI.S8, “Protective Coating Monitoring and Maintenance Program.” The 

program is a mitigative and condition monitoring program that manages the effects of loss of 

coating integrity of Service Level I coatings inside the containment in air-indoor and treated 

water environments. The program includes coating system selection, application, inspection, 

assessment, maintenance, and repair for any condition that adversely affects the ability of 

Service Level I coatings to function as intended. The LRA also states that the program provides 

controls over the amount of unqualified coating, which is defined as coating inside the primary 
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containment that has not passed the required laboratory testing, including irradiation and 

simulated design basis accident conditions.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.S8. Based on its audit, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.S8.

Operating Experience. LRA Section B.2.1.36 summarizes operating experience related to the 

Protective Coating Monitoring and Maintenance Program. The applicant provided the following 

operating experience. In 2013, during an LSCS, Unit 2, outage, the site coatings coordinator 

performed inspections of the primary containment drywell and various areas where Service 

Level I coating repairs were performed. The applicant identified areas for repair and performed 

coating repairs with qualified Service Level I epoxy coatings. The inspection identified a cap 

and blind flange in the drywell that required coating; a work order was generated, and the areas 

were subsequently recoated.

In 2010, during a LSCS, Unit 1, outage, several areas were identified as requiring coating 

touch-up repairs. The applicant identified various conduit supports, a cable tray support, a tube 

support, and several liner locations for recoating. The applicant performed the recoating during 

the following 2012 outage and used approved materials and qualified personnel and 

procedures.

In 2008, during an LSCS, Unit 1, outage, inspections were performed on coated components in 

the suppression pool. Several uncoated areas and degraded coatings were identified on the 

Main Steam Relief Valve (MSRV) struts and welded lugs. These areas were entered into the 

corrective action program and were evaluated by the site coatings coordinator. The applicant 

determined that degraded coating on 34 struts was unqualified and entered the struts in the 

undocumented, unqualified coatings log. The inspections of the MSRV struts and lugs identified 

minor surface corrosion with no significant loss of material. The applicant indicated that it will 

continue to monitor the MSRV struts each outage.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.S8 was evaluated.

UFSAR Supplement. LRA Section A.2.1.36 provides the UFSAR supplement for the Protective 

Coating Monitoring and Maintenance Program. The staff reviewed this UFSAR supplement

description of the program and noted that it is consistent with the recommended description in 
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SRP-LR Table 3.0-1. The staff also noted that the applicant committed to ongoing 

implementation of the existing Protective Coating Monitoring and Maintenance Program for 

managing the effects of aging for applicable components during the period of extended 

operation. The staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Protective Coating Monitoring 

and Maintenance Program, the staff concludes that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

Insulation Material for Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements

Summary of Technical Information in the Application. LRA Section B.2.1.37 describes the new 

Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements program as consistent with GALL Report AMP XI.E1,

“Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements.” The LRA states that the Insulation Material for 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements program is a condition monitoring program that will be used to manage the 

effects of reduced resistance of the insulation material for non-EQ cables and connections 

within the scope of license renewal that are subject to adverse localized environments caused 

by heat, radiation, and moisture. The program visually inspects accessible cable and 

connection insulation material located in adverse localized environments at least once every 

10 years. Further, the LRA states that cable and connection insulation material is visually 

inspected for indications of reduced insulation resistance, such as embrittlement, discoloration, 

cracking, melting, swelling, or surface contamination that could be an incipient conductor, and 

insulation aging degradation from temperature, radiation, or moisture.

The LRA states that the program will be informed and enhanced when necessary through the 

systematic and ongoing review of both plant-specific and industry operating experience. The 

operating experience referenced in the LRA is stated by the applicant to provide objective 

evidence that the program will be effective in assuring that intended functions are maintained 

consistent with the CLB for the period of extended operation. The new Insulation Material for 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements program will be implemented, and the first inspections will be completed before 

the period of extended operation.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.E1. Based on its audit, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.E1.
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Operating Experience. LRA Section B.2.1.37 summarizes operating experience related to the 

Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements program. The LRA operating experience discussion 

includes an example from 1990 in which heat-related aging and degradation of cable insulation 

material in the feedwater heater bay was identified. The cable insulation material degradation 

was attributed to the elevated location in the feedwater heater bay space and the cable 

proximity to steam piping. The cables were evaluated by the applicant and found to be 

operable. Subsequent corrective actions included the addition of forced ventilation, the 

insulating of turbine bypass lines and other components, inspections to ensure the cable 

degradation rate was relatively slow over time, the monitoring of feedwater bay temperatures, 

and implementation of long-term cable condition monitoring.

Another example discussed in the LRA is an industry operating experience review performed for 

NRC IN 2010-02, “Construction-Related Experience with Cables, Connectors, and Junction 

Boxes,” dated January 28, 2010. The applicant evaluated IN 2010-02 applicability to LSCS 

design and construction practices and plant operating experience. The applicant concluded 

that, based on the its review, including original plant design and construction processes, the 

improper cable installation practices referenced in IN 2010-02 were not applicable to LSCS.

The LRA includes additional discussion on the performance of cable walkdowns performed in 

response to Institute of Nuclear Power Operations (INPO) guidance for cable condition 

monitoring. The walkdowns were performed to identify cables exposed to potentially adverse

environment or conditions in the plant. The applicant completed walkdowns in non-outage 

accessible areas with outage accessible area walkdowns to be performed during future 

outages. The walkdowns found that cable environments were within their design parameters 

and that existing conditions were also acceptable.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.E1 was evaluated.

UFSAR Supplement. LRA Section A.2.1.37 provides the UFSAR supplement for the Insulation 

Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements program. The staff reviewed this UFSAR supplement description of 

the program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff also noted that the applicant committed (Commitment No. 37) to 

implement the new Insulation Material for Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements program before the period of extended 

operation. The program and initial visual inspections will be implemented before the period of 

extended operation and at least once every 10 years thereafter for managing the effects of 

aging for applicable components. The staff finds that the information in the UFSAR supplement

is an adequate summary description of the program.
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Conclusion. On the basis of its audit and review of the applicant’s Insulation Material for 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements program the staff concludes that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

Insulation Material for Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation 

Circuits

Summary of Technical Information in the Application. LRA Section B.2.1.38 describes the new

Insulation Material for Electrical Cables and Connectors Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Used in Instrumentation Circuits program as 

consistent with GALL Report AMP XI.E2, “Insulation Material for Electrical Cables and 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in 

Instrumentation Circuits.” The LRA states that the Insulation Material for Electrical Cables and 

Connectors Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in 

Instrumentation Circuits is a condition monitoring program that will be used to manage the aging 

mechanisms and effects of reduced insulation resistance in instrumentation circuits with 

sensitive, high-voltage, low-level current signals. The LRA includes portions of the Neutron 

Monitoring System, the Radiation Monitoring System, and the Area Radiation Monitoring 

System in this program. As stated in the LRA, the following instrumentation circuits are within 

the scope of the program:

• Neutron Monitoring System

− source range monitors (SRMs)

− intermediate range monitors (IRMs)

− local power range monitors (LPRMs)

• Process Radiation Monitoring System

− main steam line radiation monitors

− control room ventilation intake radiation monitors

− standby gas treatment stack effluent monitor

− station vent stack wide range gas monitor

• Area Radiation Monitoring System

− off-gas area radiation monitors

The applicant identified portions of these systems as being located in areas where cables and 

connections could be subjected to an adverse localized environment caused by temperature, 

radiation, and moisture, which can result in reduced insulation resistance causing increases in

leakage currents. Calibration testing is performed by the program when the cable is included in 

the calibrated circuit with the calibration results evaluated for indications of aging effects based 

on calibration acceptance criteria. When the in-scope instrumentation cables are not included 

as part of the calibration, the LRA stated that a proven cable test, which is effective in 

determining cable insulation condition, will be performed.
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The operating experience referenced in the LRA is stated by the applicant to provide objective 

evidence that the program will be effective in ensuring that intended functions are maintained 

consistent with the CLB for the period of extended operation.

The LRA specifies that the new program will be implemented before the period of extended 

operation, with the first evaluation of calibration/surveillance or cable test results completed 

before the period of extended operation and performed at least once every 10 years thereafter. 

The cable test frequency will be based on an engineering evaluation with a test performed at 

least once every 10 years.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.E2. Based on its audit, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.E2.

Operating Experience. LRA Section B.2.1.38 summarizes operating experience related to the 

Insulation Material for Electrical Cables and Connectors Not Subject to 10 CFR 50.49

Environmental Qualification Requirements Used in Instrumentation Circuits program. The LRA 

operating experience discussion includes an example from February 2010 in which SRM 

insulation shield to ground resistance was found to be degraded with a possible failure of 

connector electrical noise isolation. The degraded condition was entered into the corrective 

action program, and a work order was issued to repair the SRM connector along with two 

additional connectors. The applicant installed new connectors. Subsequent testing was 

completed satisfactorily.

An additional example of operating experience occurred in January 2010 in which activities 

during maintenance identified several Local Power Range Monitor (LPRM) circuits with high 

shield-to-ground resistance. The applicant determined that technical specification operability

requirements continued to be met. The LPRM circuit’s high shield-to-ground resistance was 

entered into the corrective action program and a work order was issued to repair the 

connectors. Subsequent testing of the LPRM cable circuits indicated satisfactory test results.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.E2 was evaluated.

UFSAR Supplement. LRA Section A.2.1.38 provides the UFSAR supplement for the Insulation 

Material for Electrical Cables and Connectors Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Used in Instrumentation Circuits program. The staff reviewed this 

UFSAR supplement description of the program and noted that it is consistent with the 
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recommended description in SRP-LR Table 3.0-1. The staff also noted that the applicant 

committed (Commitment No. 38) to implement the new Insulation Material for Electrical Cables 

and Connectors Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used 

in Instrumentation Circuits program before the period of extended operation. The first review of 

calibration/surveillance results or cable test results will be completed before the period of 

extended operation and at least once every 10 years thereafter. The cable test frequency will 

be based on an engineering evaluation with a test performed at least once every 10 years for 

managing the effects of aging for applicable components. The staff finds that the information in 

the UFSAR supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Insulation Material for 

Electrical Cables and Connectors Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits program, the staff concludes that those program 

elements for which the applicant claimed consistency with the GALL Report are consistent. The 

staff concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements

Summary of Technical Information in the Application. LRA Section B.2.1.39 describes the new 

Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements program as consistent with GALL Report AMP XI.E3, “Inaccessible Power 

Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.” The applicant 

stated that the Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements program will be used to manage the aging effect of reduced 

insulation resistance of non-EQ in-scope inaccessible power cables exposed to significant 

moisture. The LRA defines an inaccessible power cable as greater than or equal to 400 V. The 

applicant’s program will test in-scope inaccessible power cables using one or more proven tests 

for detecting reduced cable insulation system resistance caused by wetting or submergence. 

The LRA AMP specifies a test frequency of at least once every 6 years with the first test to be 

completed before the period of extended operation. The applicant’s program adjusts the test 

frequency based on test results and operating experience. In addition, the LRA AMP will take 

periodic actions to prevent an in-scope inaccessible power cable from being exposed to 

significant moisture, including manhole inspections for water collection. The LRA states that the 

frequency for inspections will be established and adjusted based on plant-specific operating 

experience and event-driven inspections, such as heavy rain or flooding. The first inspections 

implemented by the Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements program will be completed before the period of extended operation 

with inspections performed at least annually during the period of extended operation.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.E3. Based on its audit, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.E3.
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Operating Experience. LRA Section B.2.1.39 summarizes operating experience related to the 

Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements program. The staff reviewed operating experience information in the application 

and during the audit to determine whether the applicable aging effects and industry and 

plant-specific operating experience were reviewed by the applicant. As discussed in the Audit 

Report, the staff conducted an independent search of the plant operating experience information 

to determine whether the applicant had adequately evaluated and incorporated operating 

experience related to this program.

The staff reviewed recent integrated inspection reports for inspection findings concerning 

in-scope manholes and inaccessible cables. No findings were noted for in-scope manholes or 

inaccessible power cable submergence. During the audit, the staff reviewed cable vault 

drawings and performed a walkdown of in-scope manholes for manhole cover integrity and 

susceptibility to water runoff. The staff reviewed corrective actions and completed work orders, 

including modifications to install sump pumps in manholes MH5 and MH6 and planned sump 

pump installation for in-scope manholes MH3 and MH4 to limit water intrusion in these 

manholes. The staff also reviewed recent in-scope power cable test results, which indicated 

“satisfactory” for the in-scope inaccessible power cables. The applicant’s response to 

GL 2007-01, “Inaccessible or Underground Power Cable Failures that Disable Accident 

Mitigation Systems or Cause Plant Transients,” dated February 7, 2007, stated that LSCS had 

no history of failures of inaccessible or underground power cables within the scope of 

10 CFR 50.65, “Requirements for Monitoring the Effectiveness of Maintenance at Nuclear 

Power Plants,” for voltages from 480 V to 15,000 VAC. During the audit, the staff also noted 

that the LSCS has not experienced any in-scope inaccessible power cable failures after the 

plant response to GL 2007-01. The applicant provided additional operating experience 

examples, including the evaluation of applicable industry operating experience; inaccessible 

cable inspection and testing practices; and corrective actions, including testing; sump pump 

modifications; cable condition monitoring; periodic manhole inspections; and extent of condition, 

repair, or replacement. The staff did not identify any operating experience that would indicate 

that the applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.E3 was evaluated.

UFSAR Supplement. LRA Section A.2.1.39 provides the UFSAR supplement for the 

Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements program. The staff reviewed this UFSAR supplement description of the program 

and noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The 

staff also noted that the applicant committed (Commitment No. 39) to implement the new 

Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements program initial tests and inspections before the period of extended operation and 

to perform cable testing at least every 6 years and manhole inspections at least annually for 

managing the effects of aging for applicable components during the period of extended 

operation. More frequent test or inspections may occur based on test or inspection results and 

operating experience. The staff finds that the information in the UFSAR supplement is an 

adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Inaccessible Power Cables 

Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program, the staff 
3-57

concludes that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements

Summary of Technical Information in the Application. LRA Section B.2.1.41 describes the new

Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements program as consistent with GALL Report AMP XI.E6, “Electrical Cable 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.” The 

LRA states that the Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements program will be used to manage increased resistance of connection 

of the various metals used for electrical contacts in the metallic parts of cable connections 

exposed to air-indoor, controlled or uncontrolled, or air-outdoor conditions. The LRA also states 

that the AMP proposes to implement one-time testing of a representative sample of non-EQ 

electrical cable connections to ensure either that increased resistance of connection does not 

occur or that the existing preventive maintenance program is effective so that a periodic 

inspection program is not required. This one-time program will provide additional confirmation 

to support industry operating experience that shows that electrical connections have not

experienced a high degree of failures and that existing installation and maintenance practices 

are effective. This one-time program will also confirm that there are no aging effects requiring 

management during the period of extended operation.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.E6. Based on its audit, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.E6. The staff finds that the AMP is adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.41 summarizes operating experience related to the 

Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements program. The Non-EQ Cable Connections program is a new program with 

industry and plant operating experience considered in the implementation of the program. The 

LRA states that plant operating experience provides objective evidence that the new program 

will be effective in ensuring that intended functions are maintained consistent with the CLB for 

the period of extended operation. The LRA states that in August 2013 a hot spot was identified 

on a single phase on the line side of the breaker for one of the station heating system chillers 

during routine thermography inspections. The degraded condition was evaluated by the 

corrective action program, and repairs were made before equipment failure. In another example 

in June 2013 a thermal anomaly was found during thermography inspections. Followup 

corrective actions included tightening the bolted terminal connections, and the subsequent 

thermal imaging indicated that the elevated temperature condition was no longer present.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 
3-58

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.E6 was evaluated.

UFSAR Supplement. LRA Section A.2.1.41 provides the UFSAR supplement for the Electrical 

Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements 

program. The staff reviewed this UFSAR supplement description of the program and noted that 

it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff also noted

that the applicant committed (Commitment No. 41) to implement the new Electrical Cable 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program 

and one-time test before the period of extended operation for managing the effects of aging for

applicable components. The staff finds that the information in the UFSAR supplement is an 

adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Electrical Cable Connections 

Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program, the staff 

concludes that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Environmental Qualification (EQ) of Electric Components

Summary of Technical Information in the Application. LRA Section B.3.1.3 describes the 

existing Environmental Qualification (EQ) of Electric Components program as an existing 

preventive program that manages the aging of electrical equipment within the scope of 

10 CFR 50.49, “Environmental Qualification of Electric Equipment Important to Safety for 

Nuclear Power Plants.” The LRA states that the Environmental Qualification (EQ) of Electric 

Components program is consistent with the 10 elements of GALL Report AMP X.E1, 

“Environmental Qualification (EQ) of Electric Components.” The LRA states that the program 

establishes, demonstrates, and documents the level of qualification, qualified configurations, 

maintenance, surveillance, and replacements necessary to meet 10 CFR 50.49. The LRA also 

states that the EQ program determines the qualified life for equipment within the scope of the 

program and that required actions, such as replacement or refurbishment, are implemented 

before the end of qualified life so that the EQ aging limit of the equipment is not exceeded. The 

applicant concluded in the LRA that the aging effects addressed by the EQ program are 

adequately managed so that the intended function(s) of components within the scope of 

10 CFR 50.49 are maintained consistent with the CLB during the period of extended operation.

Staff Evaluation. SRP-LR Section 4.4.2.1.3, “10 CFR 54.21(c)(1)(iii),” and GALL Report 

Chapter X, “Time-Limited Aging Analyses Evaluation of Aging Management Programs under 
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10 CFR 54.21(c)(1)(iii),” determined that plant EQ programs, which implement the requirements 

of 10 CFR 50.49, are viewed as an acceptable AMP to address EQ according to 

10 CFR 54.21(c)(1)(iii).

During its audit, the staff reviewed the applicant’s claim of consistency with the GALL Report. 

The staff compared program elements 1 through 6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP X.E1. Based on its audit, the staff finds 

that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP X.E1.

Operating Experience. LRA Section B.3.1.3 summarizes operating experience related to the 

Environmental Qualification of Electric Components program. The LRA identified plant 

operating experience examples. A summary of the operating experience is given below.

The applicant referenced a June 2013 Focused Area Self-Assessment (FASA) that was 

completed for the applicant’s EQ program. The applicant stated that the FASA was focused on 

whether EQ maintenance requirements for motors are consistent with input information from the 

vendor, relevant corporate and plant maintenance programs, and operating experience. The 

FASA concluded that the EQ maintenance requirements are consistent with source 

documentation and industry practice with no deficiencies noted.

The applicant also referenced a FASA performed in May and June 2011 that assessed technical 

program elements to verify that EQ components are installed and maintained effectively in 

compliance with EQ documentation. The FASA concluded that the program meets 

requirements and is satisfactorily implemented at LSCS. The FASA identified recommendations 

along with six deficiencies that were subsequently corrected.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

Operating experience reviewed included the review of quarterly EQ program health reports 

issued for 2009, 2010, 2011, 2012, and 2013. All health reports reviewed indicate a program 

rating of “green.” The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP X.E1 was evaluated.

UFSAR Supplement. LRA Section A.3.1.3 provides the UFSAR supplement for the 

Environmental Qualification of Electric Components program. The staff reviewed this UFSAR 

supplement description of the program and noted that it is consistent with the recommended 

description and TLAA evaluation in SRP-LR Table 4.4-2 and SRP-LR Section 3.6.2.5, “FSAR 

Supplement,” acceptance criteria guidelines. The staff also noted that the applicant committed 
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(Commitment No. 45) to ongoing implementation of the existing Environmental Qualification of 

Electric Components program for managing the effects of aging for applicable components 

during the period of extended operation. The staff finds that the information in the UFSAR 

supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Environmental Qualification 

of Electric Components program, the staff concludes that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

3.0.3.2 AMPs Consistent with the GALL Report with Exceptions or Enhancements

In LRA Appendix B, the applicant stated that the following AMPs are, or will be, consistent with 

the GALL Report, with exceptions or enhancements:

• Water Chemistry

• Reactor Head Closure Stud Bolting

• BWR Vessel Internals

• Bolting Integrity

• Open-Cycle Cooling Water System

• Closed Treated Water Systems

• Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems

• Compressed Air Monitoring

• Fire Protection

• Fire Water System

• Aboveground Metallic Tanks

• Fuel Oil Chemistry

• Monitoring of Neutron-Absorbing Materials Other Than Boraflex

• Buried and Underground Piping

• ASME Section XI, Subsection IWE

• ASME Section XI, Subsection IWL

• ASME Section XI, Subsection IWF

• Masonry Walls

• Structures Monitoring

• RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants

• Metal Enclosed Bus
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• Fatigue Monitoring

• Concrete Containment Tendon Prestress

For AMPs that the applicant claimed are consistent with the GALL Report, with one or more 

exceptions or enhancements, the staff performed an audit and review to confirm that those 

attributes or features of the program, for which the applicant claimed consistency with the 

GALL Report are indeed consistent. The staff reviewed the exceptions to the GALL Report to 

determine whether they are acceptable and adequate. The staff also reviewed the 

enhancements to determine whether they will make the AMP consistent with the GALL Report 

AMP to which it is compared. The results of the staff’s audits and reviews are documented in 

the following sections.

Water Chemistry

Summary of Technical Information in the Application. LRA Section B.2.1.2 describes the 

existing Water Chemistry program as consistent, with an exception, with GALL Report 

AMP XI.M2, “Water Chemistry.” The LRA states that the AMP addresses the reactor vessel, 

reactor internals, piping, piping elements, piping components, heat exchangers, and tanks

exposed to treated water to manage loss of material, cracking, and reduction of heat transfer. 

The LRA also states that the AMP proposes to manage these aging effects through periodic 

monitoring of the treated water and control of known detrimental contaminants, such as 

chlorides, dissolved oxygen, and sulfate concentrations below the levels known to result in loss 

of material or cracking in accordance with BWRVIP-190, Revision 1, “BWR Vessel and Internals

Project, Volume 1: BWR Water Chemistry Guidelines – Mandatory, Needed, and Good Practice 

Guidance and Volume 2: BWR Water Chemistry Guidelines – Technical Basis,” 

EPRI 3002002623, dated April 24, 2014. Additionally, the LRA states that water chemistry 

programs may not be effective in low-flow or stagnant-flow areas of plant systems. Therefore, 

the components located in such areas will receive a one-time inspection as part of the 

One-Time Inspection program before the period of extended operation.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M2. The staff also reviewed the 

portions of the “scope of program” program element associated with the exception to determine 

whether the program will be adequate to manage the aging effects for which it is credited. The 

staff’s evaluation of this exception follows.

Exception 1. LRA Section B.2.1.2 includes an exception to the “scope of program” program 

element. In this exception the applicant stated that LSCS will be using BWRVIP-190, 

Revision 1, rather than the GALL Report recommendation of Revision 0. The staff reviewed this 

exception against the corresponding program elements in GALL Report AMP XI.M2 and finds it 

acceptable because the more recent revision of BWRVIP-190 incorporates the latest industry 

operating experience and best practices. Additionally, BWRVIP-190, Revision 1, does not take 

away or relax any of the BWRVIP-190, Revision 0, recommendations.

Based on its audit of the applicant’s Water Chemistry program, the staff finds that program 

elements 1 through 6 for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.M2. The staff 

also reviewed the exception associated with the “scope of program” program element and the 
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justification and finds that the AMP, with the exception, is adequate to manage the applicable 

aging effects.

Operating Experience. LRA Section B.2.1.2 summarizes operating experience related to the 

Water Chemistry program. The applicant described an incident in November 2002 in which

chloride concentrations in the reactor coolant exceeded EPRI Action Level 1 limits during an 

LSCS, Unit 2, startup. The cause of the excursion was quickly identified and concentrations 

were returned to normal in a timely manner. In an incident in December 2009, the LSCS, 

Unit 2, suppression pool conductivity, turbidity, and nitrate levels were found to be increased. 

The applicant determined that this was the result of a suppression pool contamination event that 

occurred in 2007 and attributed the delay in increased levels to an extended mixing time due to 

the large volume of the suppression pool. The applicant continued to sample and perform 

evaluations from the various sample points to ensure that the pool did not have localized 

contamination or pocketing issues. The applicant stated that these examples provide objective 

evidence that the Water Chemistry program will be effective in ensuring that the intended 

functions are maintained for the period of extended operation.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M2 was evaluated.

UFSAR Supplement. LRA Section A.2.1.2 provides the UFSAR supplement for the Water 

Chemistry program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant committed to ongoing implementation of the existing Water 

Chemistry program for managing the effects of aging for applicable components during the 

period of extended operation. The staff finds that the information in the UFSAR supplement is 

an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Water Chemistry program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. In addition, the staff reviewed the exception and its 

justifications and determines that the AMP, with the exception, is adequate to manage the 

applicable aging effects. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).
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Reactor Head Closure Stud Bolting

Summary of Technical Information in the Application. LRA Section B.2.1.3 describes the 

existing Reactor Head Closure Stud Bolting program as consistent, with exceptions, with 

GALL Report XI.M3, “Reactor Head Closure Stud Bolting.” The LRA states that it is a condition 

monitoring and preventive program that includes ASME Code Section XI examinations of 

reactor head closure studs and associated nuts, washers, bushings, and flange threads to 

manage cracking and loss of material. The LRA also states that it manages the aging effects in 

an air-with-reactor coolant leakage environment. The LRA further states that it implements 

ASME Code Section XI, Subsection IWB, Table IWB-2500-1, inspection requirements with 

visual and volumetric examinations to monitor for cracking, loss of material, and coolant 

leakage.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 and aspects of program 

elements not associated with the exceptions of the applicant’s program with the corresponding 

program elements of GALL Report AMP XI.M3. Based on its audit, the staff finds that program 

elements 1 through 6 for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.M3.

Exceptions. LRA Section B.2.1.3 states that the applicant reviewed Certified Material Test 

Reports data of the in-scope components and noted that the yield strength in certain parts are 

slightly over 150 ksi. The staff reviewed the exceptions associated with the “preventive actions”

and “corrective actions” program elements. The staff noted that the GALL Report guidance 

recommends yield strength of the bolting materials to be lower than 150 ksi. In its review, the 

staff also noted that the recommendation to use closure bolting with measured yield strength of 

less than 150 ksi is related to a threshold susceptibility of higher strength materials to SCC. A 

review of the applicant’s justification of the exceptions indicated that the applicant’s reactor head 

closure studs are fabricated from SA-540 Grade B24 material and that nuts and washers are 

fabricated from SA-540 Grade B23 material with a specified minimum yield strength of 130 ksi

and with a minimum tensile strength of 145 ksi. The applicant has appropriately and 

conservatively assumed that the closure bolting material is susceptible to SCC and performs 

periodic visual and volumetric examinations in accordance with the ASME Code Section XI. 

Specifically, to manage cracking due to SCC, the applicant’s program includes UT examination 

of each closure stud during each inspection period. The staff finds that the UT examination 

provides reasonable assurance that SCC in closure studs will be detected and managed before 

loss of intended function occurs. Volumetric examinations of the closure studs performed in the 

past have not indicated any evidence of SCC. In addition, periodic visual examinations will 

detect other indications of degradation, such as loss of materials, if it occurs. Therefore, the 

staff finds the applicant’s exceptions to the “preventive actions” and “corrective actions” program 

elements concerning use of material with yield strength equal to or greater than 150 ksi 

acceptable.

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M3. The staff also reviewed the exceptions associated with 

the “preventive actions” and “corrective actions” program elements and finds them acceptable. 

The staff finds that the AMP, with the exceptions, is adequate to manage the applicable aging 

effects during the period of extended operation.
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Operating Experience. LRA Section B.2.1.3 summarizes operating experience related to the 

Reactor Head Closure Stud Bolting program. The applicant provided a few examples related to 

its plant-specific operating experience. The applicant stated that, during the 2004 LSCS, Unit 1, 

outage, it performed UT examination of reactor head closure studs and flange threads on Stud

Locations 47 through 68 and visually examined all closure nuts and washers at these locations.

The applicant also discussed that it performed similar examinations at Stud Locations 1 through 

22 in 2008 and Locations 23 through 46 in 2012. In addition, the applicant discussed similar 

inspections for LSCS, Unit 2, for all locations during the 2007, 2009, and 2011 outages. The 

applicant further stated that no recordable indications were detected during these inspections.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M3 was evaluated.

UFSAR Supplement. LRA Section A.2.1.3 provides the UFSAR supplement for the Reactor 

Head Closure Stud Bolting program. The staff reviewed this UFSAR supplement description of 

the program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff also noted that the applicant committed to implementing the Reactor 

Head Closure Stud Bolting program during the period of extended operation for managing the 

effects of aging for applicable components. The staff finds that the information in the UFSAR 

supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Reactor Head Closure Stud 

Bolting program, the staff concludes that those program elements for which the applicant

claimed consistency with the GALL Report are consistent. In addition, the staff evaluated the 

exceptions associated with the “preventive actions” and “corrective actions” program elements 

and determined that the AMP, with the exceptions, is adequate to manage the applicable aging 

effects. The staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d).

BWR Vessel Internals

Summary of Technical Information in the Application. LRA Section B.2.1.9 describes the 

existing BWR Vessel Internals program as consistent, with enhancements, with GALL Report 

AMP XI.M9, “BWR Vessel Internals.” The BWR Vessel Internals program addresses BWR 

vessel internal components to manage cracking, loss of material, and loss of fracture toughness 

through inspection and flaw evaluation in conformance with applicable BWRVIP reports and 

ASME Code Section XI guidelines. The Water Chemistry program also is used with the BWR 
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Vessel Internals program to mitigate these aging effects through management of water 

chemistry. The existing BWR Vessel Internals program includes periodic inspections of X-750 

alloy reactor vessel internal components to provide for timely identification of cracks due to 

thermal aging and neutron irradiation embrittlement. LSCS, Units 1 and 2, do not include any 

reactor vessel internal components that are fabricated from precipitation-hardened martensitic 

stainless steel or martensitic stainless steel.

LRA Appendix C lists the following BWRVIP reports that are credited for the BWR Vessel 

Internals Program:

• BWRVIP-18-R1-A, “BWR Core Spray Internals Inspection and Flaw Evaluation 

Guidelines”

• BWRVIP-25, “BWR Core Plate Inspection and Flaw Evaluation Guidelines”

• BWRVIP-26-A, “BWR Top Guide Inspection and Flaw Evaluation Guidelines”

• BWRVIP-27-A, “BWR Standby Liquid Control System/Core Plate Delta-P Inspection and 

Flaw Evaluation Guidelines”

• BWRVIP-38, “BWR Shroud Support Inspection and Flaw Evaluation Guidelines”

• BWRVIP-41, “BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines 

(Revision 3)”

• BWRVIP-42-A, “BWR LPCI Coupling Inspection and Flaw Evaluation Guidelines”

• BWRVIP-47-A, “BWR Lower Plenum Inspection and Flaw Evaluation Guidelines”

• BWRVIP-48-A, “Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines”

• BWRVIP-49-A, “Instrument Penetration Inspection and Flaw Evaluation Guidelines”

• BWRVIP-74-A, “BWR Reactor Vessel Inspection and Flaw Evaluation Guidelines for 

License Renewal”

• BWRVIP-76, “BWR Core Shroud Inspection and Flaw Evaluation Guidelines, 

Revision 1”

LRA Appendix C also contains the applicant’s responses to license renewal applicant action 

items (AAIs) that were identified in the NRC staff’s SEs for the applicable BWRVIP reports. The 

responses include three license renewal AAIs applicable to all BWRVIP reports and several 

other license renewal AAIs applicable to specific BWRVIP reports. The staff’s evaluation of the 

applicant’s responses to these AAIs is documented in the “Staff Evaluation” subsection for this 

AMP.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M9. The staff also reviewed the 

portions of the “scope of program,” “parameters monitored or inspected,” “detection of aging 

effects,” and “acceptance criteria” program elements associated with enhancements to 

determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B.2.1.9 includes an enhancement to the “scope of program” and 

“acceptance criteria” program elements. In this enhancement, the applicant stated that cast 
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austenitic stainless steel (CASS) reactor vessel internal components will be evaluated for 

susceptibility of loss of fracture toughness due to thermal embrittlement. For components that 

have the material properties that cannot be determined to perform this evaluation, the applicant 

will assume that the materials are susceptible to thermal aging. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.M9 and 

finds it acceptable because when it is implemented, it will manage the effects of thermal 

embrittlement of CASS reactor vessel internal components consistent with the 

recommendations in the GALL Report to ensure that the intended functions will be maintained 

during the period of extended operation.

Enhancement 2. LRA Section B.2.1.9 includes an enhancement to the “scope of program” 

program element. In this enhancement, the applicant stated that CASS reactor vessel internal 

components will be evaluated for susceptibility of loss of fracture toughness due to neutron 

embrittlement. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.M9 and finds it acceptable because, when it is implemented, 

it will manage the effects of neutron embrittlement of CASS reactor vessel internal components 

consistent with the recommendations in the GALL Report to ensure that the intended functions 

will be maintained during the period of extended operation.

Enhancement 3. LRA Section B.2.1.9 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “acceptance criteria” program elements. In this 

enhancement, the applicant stated that the required periodic inspections will be specified for the 

CASS reactor vessel internal components that are determined to be susceptible to loss of 

fracture toughness due to thermal aging and neutron irradiation embrittlement. The initial 

inspection will be performed before or within 5 years of entering the period of extended 

operation. The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.M9 and finds it acceptable because when it is implemented, it will ensure 

that susceptible CASS vessel internals components will be inspected for evidence of any 

cracking that could cause failure due to the loss of the material’s fracture toughness caused by 

thermal or neutron embrittlement.

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M9. In addition, the staff reviewed the enhancements 

associated with the “scope of program,” “parameters monitored or inspected,” “detection of 

aging effects,” and “acceptance criteria” program elements and finds that, when implemented, 

they will make the AMP adequate to manage the applicable aging effects.

Enhancement 4. By letter dated January 14, 2016, the applicant supplemented its LRA to 

include Enhancement 4. In this supplement, the applicant stated that the “scope of program” 

program element of the BWR Vessel Internals program will be enhanced to install core plate 

wedges no later than 6 months prior to the period of extended operation, or before the end of 

the last refueling outage prior to the period of extended operation, whichever occurs later; or, 

submit an inspection plan for the core plate rim hold-down bolts with a supporting analysis for 

NRC approval at least 2 years prior to entering the period of extended operation.

The staff noted that this enhancement is associated with the applicant’s response to Action 

Item 5 in BWRVIP-25, which is evaluated and documented in the Review of License Renewal 

Applicant Action Items – Appendix C section of this evaluation. The staff reviewed 

Enhancement 4 against the corresponding program elements in GALL Report AMP XI.M9 and 

finds it acceptable because (a) it ensures that an analysis justifying its inspection basis to the 
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NRC, and (b) it ensures that loss of preload/stress relaxation in the core plate rim hold-down 

bolts will be managed during the period of extended operation. The staff confirmed that when 

Enhancement 4 is implemented, the applicant’s basis will be consistent with the “scope of 

program” program element in GALL Report AMP XI.M9.

Review of License Renewal Applicant Action Items – Appendix C: The LRA references the 

BWRVIP reports, which have been reviewed and approved by the staff, as part of its AMPs for 

the reactor vessel and its internal components. As part of the staff’s approval of these BWRVIP 

reports, the staff’s SEs on the reports included a number of license renewal AAIs to ensure that 

adequate bases are established for applying the reports to the CLB. BWR applicants applying 

for license renewal of their facilities were requested to include their responses to the AAIs in 

their LRAs.

Several BWRVIP documents credited for LSCS license renewal have common action items for 

license renewal in the NRC SEs on the topical reports. The applicant provided the following 

responses to the three common license renewal action items:

(1) The applicant’s BWR Vessel Internals program for the reactor vessel internal components 

is bounded by the BWRVIP reports.

(2) The applicant’s UFSAR supplement addresses a summary of the programs and activities 

specified in the applicable BWRVIP reports.

(3) No technical specification changes have been identified as a result of implementing the 

AMP for the reactor vessel internal components.

For the first common license renewal AAI, the staff confirmed that the BWRVIP reports 

incorporated by the applicant bound the BWR Vessel Internals program.

For the second common license renewal AAI, the staff verified that the LRA includes a UFSAR 

supplement (LRA Section A.2.1.9) for the BWR Vessel Internals program and that the program 

summary description adequately explains how the applicable BWRVIP inspection, evaluation, 

and repair criteria reports will be used to manage aging in the reactor internals at LSCS.

For the third common license renewal AAI, the staff confirmed that the applicant would not need 

to add any new Technical Specification requirements for the reactor internals or modify any 

existing Technical Specification requirements that may apply to reactor internal components.

In addition to these three common AAIs, the LRA provides the applicant’s responses to the 

report-specific license renewal AAIs that were specified by the staff in its SEs for BWRVIP 

reports credited for the BWR Vessel Internals program. The following paragraphs address the 

staff’s evaluation of the applicant’s responses to these report-specific AAIs.

For AAI 4 in BWRVIP-18-A, Revision 1, the applicant is requested to identify and evaluate any 

potential TLAA issues that may impact the structural integrity of the subject reactor pressure 

vessel internal components. The applicant’s response states that cumulative fatigue damage 

was identified and evaluated as a TLAA for core spray piping and components internal to the 

reactor vessel, as discussed in LRA Section 4.3.4. The staff confirmed that the LRA addresses 

a TLAA for managing the effects of fatigue on the reactor vessel internals and, therefore, finds 

the applicant’s response to the AAI acceptable. The staff’s evaluation of LRA Section 4.3.4 is 

documented in SER Section 4.3.4.
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For AAI 4 in BWRVIP-25, the applicant is requested to identify and evaluate the projected stress 

relaxation of the rim hold-down bolts as a potential TLAA issue. The applicant’s response 

states that stress relaxation has been identified and evaluated as a TLAA for reactor pressure 

vessel core plate rim hold-down bolts, as discussed in LRA Section 4.2.8. The staff confirmed 

that the LRA addresses a TLAA for managing the effects of loss of preload of these bolts and,

therefore, finds the applicant’s response to the AAI acceptable. The staff’s evaluation of LRA 

Section 4.2.8 is documented in SER Section 4.2.8.

For AAI 5 in BWRVIP-25, the applicant is requested to continue to perform inspections of the 

rim hold-down bolts. By letter dated January 14, 2016, the applicant amended its response to 

Action Item 5 of BWRVIP-25. In the amended response, the applicant states that inspection of 

the core plate rim hold-down bolts will be in compliance with BWRVIP guidance prior to and 

through the period of extended operation. The applicant stated that the BWR Vessel Internals 

program will be enhanced such that the applicant will either: (a) install core plate wedges no 

later than 6 months prior to entering the period of extended operation, or (b) submit an 

inspection plan for the core plate rim hold-down bolts with a supporting analysis for NRC 

approval at least 2 years prior to entering the period of extended operation. The staff noted that 

this enhancement is consistent with the program elements of GALL Report AMP XI.M9. The 

staff finds the applicant’s response acceptable because (a) it ensures that an analysis justifying 

its inspection basis to the NRC, and (b) it ensures that loss of preload/stress relaxation in the 

core plate rim hold-down bolts will be managed during the period of extended operation.

The staff finds the applicant’s response acceptable because compliance with the BWRVIP 

guidance will ensure that loss of preload/stress relaxation of the core plate rim hold-down bolts 

will be managed during the period of extended operation.

For AAI 4 in BWRVIP-26-A, the applicant is requested to identify and evaluate the projected 

accumulated neutron fluence as a potential TLAA issue. The applicant’s response states that 

the neutron fluence threshold for irradiation-assisted stress corrosion cracking (IASCC)

susceptibility has been exceeded for the reactor vessel internal components. Fluence is 

identified and evaluated as a TLAA for the reactor vessel internals, as discussed in LRA 

Section 4.2.1, but no TLAA has been identified to manage the aging effects. The applicant 

further states that the aging effects of the top guide will be managed by inspections conducted 

as part of the BWR Vessel Internals program in accordance with the guidance provided in 

BWRVIP-183. The staff confirmed that, in LRA Table 3.1.2-3, the applicant identified cracking 

as an applicable AERM for the top guide and uses the BWR Vessel Internals program to 

manage the aging effect. The staff finds the applicant’s response acceptable because the 

applicant identifies cracking as an applicable aging effect for the top guide components and 

credits its BWR Vessel Internals program and its BWRVIP-183 inspections for aging 

management. The staff noted that this approach adequately addresses management of IASCC, 

which may be induced in the top guide components when the neutron fluence exceeds the 

threshold defined in BWRVIP-26-A. The staff’s evaluation of the BWR Vessel Internals program 

is documented in this SER section.

For AAI 4 in BWRVIP-27-A, the applicant is requested to identify and evaluate the projected 

fatigue cumulative usage factors as a potential TLAA issue. The applicant’s response states 

that cumulative fatigue damage was identified and evaluated as a TLAA for the standby liquid 

control system/core plate dP penetration, as discussed in LRA Sections 4.3.1 and 4.3.3. The 

staff confirmed that the LRA addresses a TLAA for managing the effects of fatigue on the 

penetration and, therefore, finds the applicant’s response to the AAI acceptable. The staff’s 
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evaluation of LRA Sections 4.3.1 and 4.3.3 is documented in SER Sections 4.3.1 and 4.3.3, 

respectively.

For AAI 4 in BWRVIP-42-A, the applicant is requested to identify and evaluate the projected 

fatigue cumulative usage factors as a potential TLAA issue. The applicant’s response states 

that cumulative fatigue damage was identified and evaluated as a TLAA for the low-pressure 

coolant injection (LPCI) coupling, as discussed in LRA Section 4.3.4. The staff confirmed that 

the LRA addresses a TLAA for managing the effects of fatigue on the LPCI coupling and, 

therefore, finds the applicant’s response to the AAI acceptable. The staff’s evaluation of LRA 

Section 4.3.4 is documented in SER Section 4.3.4.

For AAI 5 in BWRVIP-42-A, the applicant is requested to address the inspection of inaccessible 

welds in the LPCI nozzle coupling to the reactor vessel and core shroud if referencing 

BWRVIP-42. The applicant’s response states that inspection of the LPCI coupling is performed 

in accordance with BWRVIP-42-A. The applicant states that portions of the sleeve flange to 

thermal sleeve weld at the RPV are inaccessible. The applicant inspected similar welds and 

identified no flaws for either units. The applicant’s response states that similar welds will be 

inspected and will assume leakage from any inaccessible welds if flaws are identified in similar 

accessible welds. If 75 percent of similar inspectable welds are cracked, the applicant will 

develop an inspection method to inspect the inaccessible welds. The staff noted that 

BWRVIP-42-A states that there are no inspection techniques currently available for inaccessible 

thermal sleeve welds, which is being addressed by the BWRVIP Inspection Committee. The 

BWRVIP-42-A report further states that the condition of the inaccessible welds can be 

determined using the conditions of similar inspectable welds. The staff finds the applicant’s 

response acceptable because the applicant can determine the condition of the inaccessible 

welds using its evaluation of similar inspectable welds and their inspection results, consistent 

with the guidance in BWRVIP-42-A. The applicant will also develop a plant-specific inspection 

method for these inaccessible welds, if necessary, before a generic inspection technique is 

developed by the BWRVIP Inspection Committee.

For AAI 4 in BWRVIP-47-A, the applicant is requested to identify and evaluate the projected 

cumulative usage factor as a potential TLAA issue. The applicant’s response states that 

cumulative fatigue damage was identified and evaluated as a TLAA for the reactor vessel incore 

instrumentation penetrations and control rod drive penetrations, as discussed in LRA

Sections 4.3.1 and 4.3.4. The staff confirmed that the LRA addresses a TLAA for managing the 

effects of fatigue on these penetrations and, therefore, finds the applicant’s response to the AAI

acceptable. The staff’s evaluation of LRA Sections 4.3.1 and 4.3.4 is documented in SER 

Sections 4.3.1 and 4.3.4, respectively.

For AAI 4 in BWRVIP-74-A, the applicant is requested to identify an AMP for the vessel flange 

leak detection (VFLD) line. The applicant’s response states that VFLD nozzles and piping are 

included in the scope of license renewal. The LSCS, Unit 1, nozzle is made from carbon steel, 

and the LSCS, Unit 2, nozzle is a penetration made from nickel alloy. The VFLD piping for both 

units are from carbon steel material. The applicant states that cracking in the Unit 2 nickel alloy 

nozzle is managed with the ASME Code Section XI ISI program and Water Chemistry program. 

The staff finds the applicant’s use of these AMPs to manage cracking acceptable because the 

combination of these two programs will adequately identify the aging degradation in a timely 

manner and because controlling water chemistry will enable the applicant to effectively mitigate

the occurrence of any cracking in the VFLD nozzle.
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The applicant further stated that loss of material in the carbon steel VFLD piping will be 

managed using the Water Chemistry program and One-Time Inspection program. The staff 

finds the use of these programs acceptable because the combination of these two programs will 

control water chemistry to manage the occurrence of loss of material and will be able to 

adequately determine whether aging degradation is found. The applicant stated that the carbon 

steel piping and LSCS, Unit 1, nozzle are not susceptible to cracking, which the staff finds 

acceptable because SRP-LR Section 3.1.2.2.4.1 identifies only stainless steel and nickel alloy 

VFLD lines as the material and component combinations susceptible to cracking. The staff’s 

evaluations of the ASME Code Section XI ISI program, Water Chemistry program, and 

One-Time Inspection program are documented in SER Sections 3.0.3.1.1, 3.0.3.2.1, and 

3.0.3.1.9, respectively.

For AAI 5 in BWRVIP-74-A, the applicant is requested to describe how each plant-specific AMP 

addresses the 10 elements of the program. The applicant’s response states that there are no 

plant-specific AMPs credited for managing aging of RPV components and that description of the 

AMPs credited for managing RPV components are provided in LRA Appendix B. The staff 

reviewed LRA Appendix B and finds the applicant’s response acceptable because the 

applicant’s program in LRA Appendix B adequately addresses the 10 elements of the 

GALL Report AMP.

For AAI 6 in BWRVIP-74-A, the applicant is requested to use water chemistry programs based 

on monitoring and control guidelines for reactor water chemistry. The applicant’s response 

states that the Water Chemistry program monitors and controls reactor water chemistry in 

accordance with BWRVIP-190, which supersedes BWRVIP-29. The staff noted that the BWR 

water chemistry guidelines in BWRVIP-190 represent the updated version of the EPRI BWRVIP 

water chemistry guidelines in BWRVIP-29 that mitigate that effects of water chemistry on 

component degradation and aging. The staff noted that the corresponding criteria in 

BWRVIP-190 implement acceptable water chemistry control practices, including establishment 

of conservative action levels (i.e., acceptance criteria) for the water chemistry parameters, to 

perform appropriate corrective actions if those action levels are exceeded. Therefore, staff finds 

the applicant’s response acceptable because (1) the applicant confirmed its conformance with 

the water chemistry guidelines in BWRVIP-190, (2) the implemented guidelines will provide 

adequate management of water chemistry at the plant, and (3) the applicant’s water chemistry 

control will effectively prevent or mitigate aging effects on the aging of components (e.g., loss of 

material due to general, pitting or crevice corrosion, SCC, or IGSCC).

For AAI 7 in BWRVIP-74-A, the applicant is requested to identify its reactor vessel material 

surveillance program. The applicant’s response states that LSCS received NRC approval to 

use the BWRVIP integrated surveillance program (ISP) and applied it to the Reactor Vessel 

Surveillance program. The staff verified that the applicant’s reactor vessel material surveillance 

program is given in LRA Section B.2.1.20, “Reactor Vessel Surveillance.” The staff confirmed 

that the applicant adequately addressed the action item by stating that the applicant’s program 

is an ISP that complies with the requirements for ISPs in Appendix H to 10 CFR Part 50, 

“Domestic Licensing of Production and Utilization Facilities.” The staff finds this response 

acceptable because the applicant has included its Reactor Vessel Surveillance program in the 

LRA. The staff’s evaluation of the Reactor Vessel Surveillance program and the program’s 

basis for generating relevant reactor vessel embrittlement data for neutron irradiation 

embrittlement TLAAs is documented in SER Section 3.0.3.1.8.

For AAI 8 in BWRVIP-74-A, the applicant is requested to verify that its original fatigue design 

cycles have been updated to 60 years of operation and address the effects of environmental 
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fatigue. The applicant’s response states that fatigue during the period of extended operation, 

including environmentally assisted fatigue, has been addressed. The staff verified that the 

applicant has included the metal fatigue evaluations and environmentally assisted fatigue 

evaluation in LRA Section 4.3. Therefore, the staff finds the applicant’s response to the AAI

acceptable. The staff’s evaluations of the metal fatigue analyses and environmentally assisted 

fatigue analyses for ASME Code Class 1 and the metal fatigue analyses for non-Class 1 

components is documented in SER Section 4.3.

For AAI 9 in BWRVIP-74-A, the applicant is requested to demonstrate that the beltline materials 

meet the Charpy upper-shelf energy (USE) criteria specified in BWRVIP-74-A Appendix B. The 

applicant’s response states that P-T curves were developed, as discussed in LRA Section 4.2.4, 

and will be updated as required by Appendix G, “Fracture Toughness Requirements,” to 

10 CFR Part 50. The staff confirmed that the LRA addresses the applicant’s TLAA for 

managing the aging effects associated with P-T limits, as discussed in LRA Section 4.2.4 and, 

therefore, finds the applicant’s response to the AAI acceptable. The staff’s evaluation of LRA 

Section 4.2.4 is documented in SER Section 4.2.4.

For AAI 10 in BWRVIP-74-A, the applicant is requested to develop a set of P-T curves for the 

heatup and cooldown operating conditions during the period of extended operation. The 

applicant’s response states that Charpy USE values for the period of extended operation were 

determined in accordance with the methodology included in RG 1.99, Revision 2, as discussed 

in LRA Section 4.2.2. The staff confirmed that the applicant included its TLAA for USE in LRA 

Section 4.2.2. Therefore, the staff finds the applicant’s response to the AAI acceptable. The 

staff’s evaluation of the TLAA for USE is documented in SER Section 4.2.2.

For AAI 11 in BWRVIP-74-A, the applicant can obtain relief from the inservice inspection of the 

circumferential welds during the license renewal period. The applicant’s response states that 

the circumferential welds for each unit will satisfy the limiting conditional failure frequency at the 

end of the period of extended operation. The applicant’s response stated that relief from the 

inservice inspection of the circumferential welds during the period of extended operation is 

discussed in LRA Section 4.2.6, which states that an extension of this relief for the period of 

extended operation will be submitted to the NRC in accordance with 10 CFR 50.55a. The staff 

confirmed that the applicant included reactor vessel probability of failure analyses (i.e., TLAAs) 

for the reactor vessel circumferential welds in LRA Section 4.2.6 and will use these TLAAs as 

the basis for submitting a future inservice inspection relief request for the reactor vessel 

circumferential welds during the period of extended operation. Therefore, the staff finds the 

applicant’s response to the AAI acceptable. The staff’s evaluation of this TLAA is documented 

in SER Section 4.2.6.

For AAI 12 in BWRVIP-74-A, the applicant is requested to monitor axial beltline weld 

embrittlement. The applicant’s response states that the Axial Weld Failure Probability 

Assessment Analyses have been identified as a TLAA, as discussed in LRA Section 4.2.5. The 

applicant stated that the TLAA evaluation shows that the mean RTNDT of the limiting axial 

beltline weld for each unit will be less than the bounding criteria specified in the BWRVIP report 

at the end of the period of extended operation. The staff confirmed that the applicant included 

the applicable TLAA for the reactor vessel axial welds in LRA Section 4.2.5. Therefore, the staff 

finds the applicant’s response to the AAI acceptable. The staff’s evaluation of the probability of 

failure analysis TLAA for the reactor vessel axial welds is documented in SER Section 4.2.5.

For AAI 13 in BWRVIP-74-A, the applicant is requested to either perform neutron fluence 

calculations using staff-approved methodology or submit plant-specific methodology for staff 
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review. The applicant’s response states that the neutron fluence during the period of extended 

operation was determined using NRC-approved methodology, as discussed in LRA 

Section 4.2.1. The staff verified that the applicant has included its neutron fluence calculations 

for the reactor vessel beltline components (including those in the extended portion of the 

beltline) in LRA Section 4.2.1 and that the neutron fluence values for these components have 

been appropriately extended to the end of the period of extended operation (i.e., to 52 EFPY). 

Therefore, the staff finds the applicant’s response to the AAI acceptable. The staff’s evaluation 

of the neutron fluence analysis in LRA Section 4.2.1 is documented in SER Section 4.2.1.

For AAI 14 in BWRVIP-74-A, the applicant is requested to re-evaluate indications, evaluated in 

accordance with ASME Code Section XI to the end of the original operating term, for the period 

of extended operation. The applicant’s response states that there are no components within the 

ASME Code Class 1 reactor coolant pressure boundary with indications that have been 

previously analytically evaluated until the end of the 40-year service period. The staff reviewed 

the LRA and the UFSAR and verified the applicant’s claim. Therefore, the staff finds the 

applicant’s response to the AAI acceptable.

For AAI 4 in BWRVIP-76, Revision 1, the applicant is requested to reference BWRVIP-14-A, 

BWRVIP-99-A, and BWRVIP-100-A in its evaluation procedures for cracked core shroud welds 

in the reactor vessel internals AMP and to confirm that it will incorporate any emerging 

inspection guidelines. The applicant’s response states that the BWR Vessel Internals program 

references these BWRVIP reports, specifies that the crack growth rate evaluations and fracture 

toughness values in the reports will be used, and confirms that emerging inspection guidelines 

will be incorporated into the program. The staff verified that the applicant has included these 

BWRVIP reports as part of the methodologies that will be applied in accordance with the BWR 

Vessel Internals program. Therefore, the staff finds the applicant’s response to the AAI 

acceptable.

For AAI 5 in BWRVIP-76, Revision 1, the applicant is requested to incorporate the tie rod 

cracking operating experience at Hatch 1 into its AMPs. The applicant’s response states that 

the core shrouds at both units have not been modified to include tie rod repairs. The staff 

reviewed the UFSAR and verified that the applicant has yet to implement any core shroud 

modifications associated with the installation of tie rod repair assemblies. Therefore, the staff 

finds the applicant’s response to the AAI acceptable because the staff reviewed the UFSAR and 

confirmed that the core shroud designs do not include tie rod repair assemblies.

For AAI 6 in BWRVIP-76, Revision 1, the applicant is requested to identify the aging effects for 

the core shrouds and core shroud assembly components if a repair design modification has 

been implemented and to identify the specific AMPs or TLAAs that will be used to manage the 

effects for the period of extended operation. The applicant’s response states that cumulative 

fatigue damage, cracking, and loss of material have been identified as aging effects requiring 

management for the core shrouds. The BWR Vessel Internals program and Water Chemistry 

program will be used to manage cracking and loss of material, and the Fatigue Monitoring 

program will be used to manage cumulative fatigue damage. The staff reviewed the LRA and 

confirmed that these aging effects have been identified and will be managed during the period 

of extended operation. Therefore, the staff finds the applicant’s response to the AAI acceptable. 

The staff’s evaluations of the BWR Vessel Internals program, the Water Chemistry program, 

and the Fatigue Monitoring program are documented in SER Sections 3.0.3.2.3, 3.0.3.2.1, and 

3.0.3.2.22, respectively.
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For AAI 7 in BWRVIP-76, Revision 1, the applicant is requested to identify and manage 

applicable aging effects for core shroud components or core shroud repair assembly 

components that are made from materials other than stainless steel or nickel alloy. The 

applicant’s response states that this is not applicable because the core shrouds, including 

welds, are fabricated from stainless steel and nickel alloy and that no core shroud repair 

assembly components have been added. The staff finds this acceptable because the staff 

reviewed the UFSAR and confirmed the applicant’s response.

For AAI 8 in BWRVIP-76, Revision 1, the applicant is requested to reference BWRVIP-99 and 

BWRVIP-100-A in its reactor vessel internals AMP. The applicant’s response states that these 

two BWRVIP reports are referenced in the BWR Vessel Internals program. The staff confirmed 

these BWRVIP documents are referenced in the applicant’s program and, therefore, finds the 

applicant’s response to the AAI acceptable.

Operating Experience. LRA Section B.2.1.9 summarizes operating experience related to the 

BWR Vessel Internals program. The staff reviewed operating experience information in the 

application and during the audit to determine whether the applicable aging effects and industry 

and plant-specific operating experience were reviewed by the applicant. As discussed in the 

Audit Report, the staff also conducted an independent search of the plant operating experience 

information to determine whether the applicant had adequately evaluated and incorporated 

operating experience related to this program.

The staff noted that the applicant has identified relevant plant-specific operating experience. 

The LRA states that in 2004, all of the LSCS, Unit 1, jet pump riser brace RS-8 and RS-9 welds 

were visually inspected, and indications were noted. As a result, corrective actions were 

initiated, and a clamp was installed at the slip joint on all 20 jet pumps. The staff noted that 

BWRVIP-41 and industry sources discuss operating experience related to degradation due to jet 

pump vibration. However, the LRA does not clearly address whether the applicant’s program 

resolved the concern about jet pump vibration resulting from slip joint leakage flow instability, 

pump resonance, or turbulent flow. The LRA does not address assessment of plant-specific 

operating experience regarding jet pump vibration and loss of material due to wear of jet pump 

wedges and restrainer brackets at their interfaces. The staff needed additional information to 

determine whether the program needs to be enhanced with additional aging management 

activities and inspections based on adequate assessment of operating experience.

By letter dated June 8, 2015, the staff issued RAI B.2.1.9-1, requesting the applicant to 

(1) discuss how the applicant’s program resolved the concern about jet pump vibration for 

LSCS, Units 1 and 2, and (2) provide the assessment of plant-specific operating experience 

regarding jet pump vibration and loss of material due to wear of jet pump wedges and restrainer 

brackets at their interfaces, including a justification for why the BWR Vessel Internals program 

would not need to be enhanced.

By letter dated July 1, 2015, the applicant responded to RAI B.2.1.9-1. For LSCS, Unit 1, the 

applicant stated that it mitigated vibration caused by leakage at the jet pump slip joints through 

the installation of slip joint clamps. The applicant confirmed that the slip joint clamp installations 

arrested the vibration caused by slip joint leakage flow instability. The applicant also installed 

riser brace clamps to structurally replace the RS-9 welds. The applicant re-examined the 

indications found on the RS-9 welds and found no change, which indicates that vibration has 

been mitigated. For LSCS, Unit 2, the applicant stated that the jet pump inlet mixers were 

replaced with inlet mixers that have a labyrinth seal design, which reduces vibration through 

increases in the slip joint differential pressure. The applicant stated that no indications have 
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been identified in the LSCS, Unit 2, RS-9 welds. The staff finds this portion of the applicant’s 

response acceptable because the applicant performed adequate corrective actions, consistent 

with the guidance in BWRVIP-41, to mitigate the degradation due to jet pump vibration and 

because post-corrective action examinations have determined that wear rates of the jet pump 

components have been reduced or ceased.

In its response to RAI B.2.1.9-1, the applicant also stated that a program enhancement to the 

BWR Vessel Internals program was not identified to manage jet pump degradation due to jet 

pump vibration because the corrective actions, examination techniques, and criteria for scope 

expansion are performed in accordance with BWRVIP-41. The applicant further stated that, 

because the BWR Vessel Internals program references BWRVIP-41 and because it will 

implement any revisions to this report, no enhancement is necessary to the AMP. In addition, to 

address operating experience associated with main wedge wear, the applicant has incorporated 

industry guidance and operating experience into its BWR Vessel Internals program, which 

includes BWRVIP Letter 2014-019 and General Electric-Hitachi Safety Communications 12-12 

and 12-14. These industry sources contain examination criteria, scope expansion criteria, and 

re-examination requirements. The staff finds this portion of the applicant’s response acceptable 

because (1) the applicant has already incorporated the guidance in BWRVIP-41 and industry 

guidelines in the BWR Vessel Internals program and (2) the applicant will continue to evaluate 

future plant-specific and industry operating experience and incorporate industry guidelines to 

ensure that aging is effectively managed for the jet pump components during the period of 

extended operation. The staff’s concerns in RAI B.2.1.9-1 are resolved.

Based on its audit and review of the application and review of the applicant’s response to 

RAI B.2.1.9-1, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and that implementation of the program has resulted in the 

applicant taking corrective actions. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP XI.M9 was 

evaluated.

UFSAR Supplement. LRA Section A.2.1.9 provides the UFSAR supplement for the BWR 

Vessel Internals program. The staff reviewed this UFSAR supplement description of the 

program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff also noted that the applicant committed to (1) evaluate CASS reactor 

vessel internals components for susceptibility to thermal embrittlement before the period of 

extended operation, (2) evaluate CASS reactor vessel internals components for susceptibility to 

neutron embrittlement before the period of extended operation and (3) specify the required 

periodic inspection of CASS components susceptible to loss of fracture toughness due to 

thermal and neutron embrittlement before or within 5 years of entering the period of extended 

operation.

By letter dated January 14, 2016, the applicant amended its UFSAR supplement to include 

Enhancement 4, which states that the applicant will either (a) install core plate wedges no later 

than 6 months prior to entering the period of extended operation, or (b) submit an inspection 

plan for the core plate rim hold-down bolts with a supporting analysis for NRC approval at least 

two years prior to entering the period of extended operation.

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program.
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Conclusion. On the basis of its audit and review of the applicant’s BWR Vessel Internals 

program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the 

enhancements and confirmed that their implementation before the period of extended operation 

will make the AMP adequate to manage the applicable aging effects. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

Bolting Integrity

Summary of Technical Information in the Application. LRA Section B.2.1.11 describes the 

existing Bolting Integrity program as consistent, with enhancements, with GALL Report 

AMP XI.M18, “Bolting Integrity.” The LRA states that the AMP manages the aging effects of 

cracking, loss of material, and loss of preload of closure bolting for pressure-retaining 

components within the scope of license renewal. The AMP implements the GALL Report

recommended guidance in NUREG-1339, “Resolution of Generic Safety Issue 29: Bolting 

Degradation or Failure in Nuclear Power Plants,” dated June 1990; EPRI NP-5769, 

“Degradation and Failure of Bolting in Nuclear Power Plants”; and EPRI TR-104213, “Bolted 

Joint Maintenance and Applications Guide,” for material selection, use of lubricants, proper 

torqueing, and leakage evaluations. The AMP also relies on periodic visual inspections, 

performed at least once every RFO, to detect signs of leakage and age-related degradation of 

pressure-retaining closure bolts in ASME Code and non-ASME Code Section XI, Class 1, 2, 

and 3 systems. Volumetric inspections of ASME Section XI Class 1, 2, and 3 bolts, nuts, and 

washers are performed in accordance with ASME Section XI, Subsections IWB, IWC, and IWD.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M18.

The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” and “corrective actions” program elements associated 

with enhancements to determine whether the program will be adequate to manage the aging 

effects for which it is credited. By letter dated July 7, 2015, the staff issued RAI 3.2.2.1.1-1 

requesting the applicant to justify the aging management inspection parameters and frequency 

of inspection of submerged bolts in the suppression pool emergency core cooling system 

(ECCS), reactor core isolation cooling (RCIC) system suction strainers, the service water diver 

safety barriers, and diesel fire pump suctions screens. The RAI also requested that the 

applicant justify the aging management inspection parameters of submerged bolts in the lake 

screen house traveling screens framework. The staff’s discussion of its concern and review of 

the applicant’s response to RAI 3.2.2.1.1-1, dated August 6, 2015, are documented in SER 

Sections 3.2.2.1.2 and 3.3.2.1.5. The submerged bolts discussed in RAI 3.2.2.1.1-1 are also 

associated with Enhancements 4, 5, and 6 of this AMP. The staff’s evaluation of the 

enhancements to the Bolting Integrity program, as revised by the applicant’s response to 

RAI 3.2.2.1.1-1, follows.

Enhancement 1. LRA Section B.2.1.11 includes an enhancement to the “preventive actions,” 

“parameters monitored or inspected,” “detection of aging effects,” and “corrective actions,” 

program elements. In this enhancement, the applicant stated that it will implement guidance in 
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the AMP to “ensure proper specification of bolting material, lubricant and sealants, storage, and 

installation torque or tension to prevent or mitigate degradation and failure of closure bolting for 

pressure-retaining bolted joints.” The GALL Report AMP XI.M18 “preventive actions,” 

“parameters monitored or inspected,” “detection of aging effects,” and “corrective actions”

program elements recommend the implementation of the guidelines in EPRI-NP 5769, 

NUREG-1339, and EPRI TR-104213 to prevent and mitigate degradation and failure of closure 

bolting. During the AMP audit, the staff reviewed the Bolting Integrity program basis document 

and existing procedures. As part of its review, the staff verified that the guidelines 

recommended by the GALL Report AMP XI.M18 were either already included in the existing 

procedures or were identified in the program basis document as guidelines to be added to the 

procedures before the period of extended operation. The staff reviewed this enhancement 

against the corresponding program elements in GALL Report AMP XI.M18 and finds it 

acceptable because, when it is implemented, the guidelines recommended by GALL Report 

AMP XI.M18 for selection of bolting material, use of lubricants, storage, and application of 

proper torque will be incorporated into the Bolting Integrity program.

Enhancement 2. LRA Section B.2.1.11 includes an enhancement to the “preventive actions” 

and “corrective actions” program elements. In this enhancement, the applicant stated that the 

use of molybdenum disulfide (MoS2) lubricants on pressure-retaining bolts will be prohibited. 

The “preventive actions” program element of GALL Report AMP XI.M18 states that lubricants 

containing MoS2 should not be used because MoS2 has been shown to be a potential 

contributor to SCC. The “corrective actions” program element of GALL Report AMP XI.M18 

recommends that the replacement of ASME and non-ASME Code Class pressure-retaining 

bolting be performed consistent with the guidance in EPRI NP-5769 and EPRI TR-104213. The 

staff notes that the guidance in EPRI NP-5769 states that a common factor in the failure of 

closure bolting due to SCC appears to be the use of lubricants containing MoS2. In addition, 

EPRI TR-104213 states, in part, that the use of lubricants containing sulfides (e.g., MoS2) is 

undesirable because it contributes to SCC. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M18 and finds it acceptable because,

when it is implemented, the use of MoS2 will be prohibited to prevent the aging effect of SCC in 

closure bolts, consistent with the recommendations in the GALL Report AMP XI.M18.

Enhancement 3. LRA Section B.2.1.11 includes an enhancement to the “preventive actions,” 

“parameters monitored or inspected,” and “corrective actions” program elements. In this 

enhancement, the applicant stated that the use of high-strength bolts (actual yield strength 

greater than or equal to 150 ksi) will be minimized and that it will monitor high-strength bolts 

(regardless of code classification) for cracking in accordance with ASME Code Section XI, 

Table IWB-2500-1, Examination Category B-G-1. The “preventive actions” program element of 

GALL Report AMP XI.M18 recommends using bolting material with an actual measured yield 

strength limited to less than 150 ksi. The GALL Report AMP XI.M18 also recommends 

monitoring high-strength bolting with actual yield strength greater than or equal to 150 ksi for 

cracking and performing volumetric examination of high-strength closure bolts (regardless of 

code classification) in accordance with ASME Code Section XI, Table IWB-2500-1, Examination 

Category B-G-1, to detect cracking. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M18 and finds it acceptable because

the use of high strength bolts will be minimized, and if high-strength bolting with actual yield 

strength greater than or equal to 150 ksi is installed, it will be subject to volumetric examinations 

to detect cracking due to SCC before a loss of intended function.

Enhancement 4. LRA Section B.2.1.11 includes an enhancement to the “parameters monitored 

or inspected” and “detection of aging effects” program elements. In this enhancement, the 
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applicant stated that inspections for loss of material and loss of preload of the submerged 

bolting in the suppression pool ECCS and RCIC system suction strainers will be performed 

during each ISI interval (i.e., once every 10 years). By letter dated August 6, 2015, the 

applicant clarified that these inspections will consist of visual inspections of 100 percent of the 

accessible surfaces of bolt heads, nuts, and threaded bolt shank beyond the nut and physical 

manipulation of the nuts to ensure that the nuts are not loose.

The GALL Report AMP XI.M18 recommends that closure bolting be inspected for loss of 

material and loss of preload. The GALL Report also recommends that for components that are 

not accessible, visual inspections should be conducted at a frequency not to exceed 10 years.

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.M18 and finds it acceptable because visual inspection of 100 percent of 

the accessible bolts and physical manipulation of the nuts at a 10-year frequency provides 

reasonable assurance that the effects of aging on the suppression pool ECCS and RCIC 

system suction strainers bolting will be adequately managed because, in all instances, the 

accessible and inaccessible bolting are exposed to the same environment.

Enhancement 5. LRA Section B.2.1.11 includes an enhancement to “parameters monitored or 

inspected,” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that the submerged bolts in the service water diver safety barriers and diesel 

fire pump suction screens will be subject to inspection for loss of material and loss of preload 

once every RFO interval. By letter dated August 6, 2015, the applicant clarified that these 

inspections will consist of visual inspections of 100 percent of the accessible surfaces of bolts 

and physical manipulation of the nuts to ensure that the nuts are not loose. GALL Report 

AMP XI.M18 recommends that closure bolting is inspected for loss of material and loss of 

preload. The GALL Report also states that pressure-retaining bolted connections should be 

inspected at least once per refueling cycle. The staff finds that performing these inspections 

provides reasonable assurance that the effects of aging of the inaccessible bolting in the service 

water diver safety barriers and diesel fire pump suctions screens will be adequately managed 

because, in all instances, the accessible and inaccessible bolting are exposed to the same 

environment. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.M18 and finds it acceptable because when it is implemented, 

visual inspections for loss of material and loss of preload for service water diver safety barriers 

and diesel fire pump suctions screens will be performed once every RFO consistent with the 

recommendations in GALL Report AMP XI.M18.

Enhancement 6. LRA Section B.2.1.11 includes an enhancement to “parameters monitored or 

inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that inspection for loss of material and loss of preload of the submerged bolting 

in the lake screen house traveling screens framework will be performed once every RFO 

interval. By letter dated August 6, 2015, the applicant clarified that these inspections will consist 

of visual inspections of 100 percent of the accessible surfaces of bolts and physical 

manipulation of the nuts to ensure that the nuts are not loose. GALL Report AMP XI.M18 

recommends that closure bolting be inspected for loss of material and loss of preload. The 

GALL Report also states that pressure-retaining bolted connections should be inspected at least 

once per RFO. The staff finds that performing these inspections provides reasonable 

assurance that the effects of aging of the inaccessible bolting in the lake screen house traveling 

screens framework will be adequately managed because, in all instances, the accessible and 

inaccessible bolting are exposed to the same environment. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.M18 and 

finds it acceptable because, when it is implemented, visual inspections for loss of material and 
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loss of preload for the lake screen house traveling screens framework will be performed once 

every RFO consistent with the recommendations in GALL Report AMP XI.M18.

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M18. In addition, the staff reviewed the enhancements 

associated with the “preventive actions,” “parameters monitored or inspected,” “detection of 

aging effects,” and “corrective actions” program elements and finds that, when implemented, 

they will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.11 summarizes operating experience related to the 

Bolting Integrity program. In January 2002, during maintenance of the internals for the reactor 

recirculation “A” loop flow control valve, 1 of 12 studs failed due to overtorquing. The applicant 

entered the condition into its corrective action program and performed UT and magnetic particle 

(MT) examinations of the remaining 11 studs. Based on the examination results the applicant 

found cracking on 10 of the 11 remaining studs and determined that the cracking was present 

before the overtorquing failure. The applicant replaced all bonnet-to-body studs. Additional 

corrective actions taken included performing UT examinations on the corresponding “B” loop 

valve studs; examining both LSCS, Units 1 and 2, valve studs for which no cracks were 

identified; incorporating Belleville washers into the bolted joint design; and implementing 

enhancements to the personnel training and work procedures in the use of hydraulic torque 

wrenches.

In February 2010, the applicant identified corrosion in the bolting and end cover of a cooling 

water strainer. The corrosion was caused by a packing leak from the strainer manual backwash 

valve. Corrective actions taken by the applicant included entering the condition into the 

corrective action program, reworking the bolted joint, replacing bolting hardware if needed,

performing walkdowns of the remaining strainers in the system, replacing and reconfiguring 

strainers to prevent recurrence of the condition, and performing periodic inspections to identify 

corrosion and packing leaks.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M18 was evaluated.

UFSAR Supplement. LRA Section A.2.1.11, as revised by letter dated August 6, 2015, provides 

the UFSAR supplement for the Bolting Integrity program. The staff reviewed this UFSAR 

supplement description of the program and noted that it is consistent with the recommended 

description in SRP-LR Table 3.0-1. The staff also noted that the applicant committed to 

implement the enhancement to the program before the period of extended operation. The staff 
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finds that the information in the UFSAR supplement is an adequate summary description of the 

program.

Conclusion. On the basis of its audit and review of the applicant’s Bolting Integrity program, the 

staff determines that those program elements for which the applicant claimed consistency with 

the GALL Report are consistent. In addition, the staff reviewed the enhancements and 

confirmed that their implementation before the period of extended operation will make the AMP 

adequate to manage the applicable aging effects. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Open-Cycle Cooling Water System

Summary of Technical Information in the Application. LRA Section B.2.1.12 describes the 

existing Open-Cycle Cooling Water System program as consistent, with enhancements, with 

GALL Report AMP XI.M20, “Open-Cycle Cooling Water System,” as modified by 

LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric 

Storage Tanks, and Corrosion under Insulation.” The LRA states that the program manages 

heat exchanger and piping components of safety-related and nonsafety-related systems 

exposed to a raw water environment. Activities for the program are consistent with the 

commitments to NRC GL 89-13, “Service Water System Problems Affecting Safety-Related 

Equipment,” dated July 18, 1989, and include system surveillances and chemical injections to 

manage biofouling; periodic testing, visual inspections, and cleaning of heat exchangers to 

manage reduction of heat transfer; and inspections and routine maintenance of components to 

manage corrosion, erosion, sediment deposition, and biofouling.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M20.

The staff also reviewed the portions of the “parameters monitored or inspected,” “detection of 

aging effects,” and “monitoring and trending” program elements associated with the 

enhancements to determine whether the program will be adequate to manage the aging effects 

for which it is credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B.2.1.12 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “monitoring and trending” program elements. In 

this enhancement, the applicant stated that a minimum of 10 inspections will be performed on 

aboveground piping in the essential cooling water system every 24 months until the rate of 

degradation due to microbiologically-influenced corrosion no longer meets the recurring internal 

corrosion criteria given in LR-ISG-2012-02. The enhancement includes periodic reviews of the 

selected inspection locations to validate their relevance and to make adjustments as 

appropriate. A portion of the samples for this enhancement will be at locations with similar 

process conditions to those in the buried portions of the piping to provide sufficient 

understanding of the buried piping condition. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M20, as modified by 

LR-ISG-2012-02, and finds it acceptable because, when it is implemented, the program’s

additional inspections will improve the aging management of recurring internal corrosion due to 
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microbiologically-influenced corrosion in the safety-related portions of the open-cycle cooling 

water system.

Enhancement 2. LRA Section B.2.1.12 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “monitoring and trending” program elements. In 

this enhancement, the applicant stated that a minimum of 10 inspections will be performed on 

aboveground piping in the nonessential cooling water system every 24 months until the rate of

degradation due to microbiologically-influenced corrosion no longer meets the recurring internal 

corrosion criteria given in LR-ISG-2012-02. The enhancement includes periodic reviews of the 

selected inspection locations to validate their relevance and to make adjustments as 

appropriate. A portion of the samples for this enhancement will be at locations with similar 

process conditions to those in the buried portions of the piping to provide sufficient 

understanding of the buried piping condition. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M20, as modified by 

LR-ISG-2012-02, and finds it acceptable because, when it is implemented, the program’s 

additional inspections will improve the aging management of recurring internal corrosion due to 

microbiologically-influenced corrosion in the nonsafety-related portions of the open-cycle cooling 

water system.

Enhancement 3. LRA Section B.2.1.12 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “monitoring and trending” program elements. In 

this enhancement, the applicant stated that an inspection method to provide an indication of wall 

thickness will be selected to examine buried piping to supplement the aboveground piping 

inspection locations. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.M20, as modified by LR-ISG-2012-02, and finds it acceptable 

because additional inspections of buried piping will augment the information derived from the 

aboveground piping inspections and will provide better management of recurring internal 

corrosion due to microbiologically-influenced corrosion.

Enhancement 4. LRA Section B.2.1.12 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “monitoring and trending” program elements. In 

this enhancement, the applicant stated that visual inspections will be performed on the interior 

surface of buried portions of the essential and nonessential cooling water systems whenever the 

piping internal surfaces are accessed during maintenance or repair activities. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.M20, as modified by LR-ISG-2012-02, and finds it acceptable because, when it is 

implemented, the program will provide additional inspections to better manage recurring internal 

corrosion due to microbiologically-influenced corrosion.

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M20, as modified by LR-ISG-2012-02. The staff reviewed the

enhancements associated with the “parameters monitored or inspected,” “detection of aging 

effects,” and “monitoring and trending” program elements and finds that, when implemented, 

they will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.12 summarizes operating experience related to the 

Open-Cycle Cooling Water System program. The applicant described the identification and 

subsequent replacement of degraded seal cooler piping during a periodic wall thickness 

inspection that was conducted as part of the GL 89-13 program. Based on the finding, 

additional locations were selected for inspections. The applicant also described the 
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identification and resolution of low-flow issues from periodic surveillance tests in the core 

standby cooling system. The associated common cause evaluation recommended 

improvements to the program that addressed more frequent and higher flow rate flushing, 

expansion of the chemical cleanout of coolers to include connected piping, and increased 

concentrations of chemicals used for silt dispersion and biofouling.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M20 was evaluated.

UFSAR Supplement. LRA Section A.2.1.12 provides the UFSAR supplement for the 

Open-Cycle Cooling Water System program. The staff reviewed this UFSAR supplement 

description of the program and noted that it is consistent with the recommended description in 

SRP-LR Table 3.0-1. The staff also noted that the applicant committed to implement the four 

enhancements to the program before the period of extended operation. The staff finds that the 

information in the UFSAR is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Open-Cycle Cooling Water 

System program, the staff determines that those program elements that the applicant claimed 

were consistent with the GALL Report are consistent with AMP XI.M20. In addition, the staff 

reviewed the enhancements and confirmed that their implementation before the period of 

extended operation will make the AMP adequate to manage the applicable aging effects. The 

staff concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CRF 54.21(d).

Closed Treated Water Systems

Summary of Technical Information in the Application. LRA Section B.2.1.13, as modified by 

letter dated August 6, 2015, describes the existing Closed Treated Water Systems program as 

consistent, with enhancements, with GALL Report AMP XI.M21A “Closed Treated Water 

Systems,” as modified by LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water 

Systems, Atmospheric Storage Tanks, and Corrosion under Insulation.” The program manages 

loss of material, cracking, and reduction of heat transfer in components exposed to closed cycle 

cooling water. The program provides mitigative measures and monitors water chemistry 

parameters based on EPRI 1007820, “Closed Cooling Water Chemistry Guideline,” and uses 

nitrite-based water treatment, including pH control and corrosion inhibitors. The program 

includes opportunistic and periodic visual inspections or nondestructive examinations to identify 

the presence of corrosion, SCC, or fouling to prevent significant age-related degradation.
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Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M21A. For the “parameters 

monitored or inspected” and “detection of aging effects” program elements, the staff determined 

the need for additional information, which resulted in the issuance of RAIs, as discussed below.

The “detection of aging effects” program element in GALL Report AMP XI.M21A recommends 

that a representative sample of piping and components be inspected. Although the applicant 

stated that the program will be enhanced to include periodic inspections and nondestructive 

examinations of a representative sample, the LRA and onsite documentation did not include any 

details relating to the sample size. The staff noted that this was inconsistent with the guidance 

in SRP-LR Section A.1.2.3.4, “Detection of Aging Effects,” in that the basis for the sample size 

should be provided whenever sampling is used to represent a larger population of components. 

To address this concern, by letter dated July 7, 2015, the staff issued RAI B.2.1.13-1,

requesting that the applicant provide details related to the size of the representative sample 

associated with the enhancement to the program.

In its response dated August 6, 2015, the applicant stated that due to the small number of 

stainless steel components in the “closed cycle cooling water greater than 140 °F” environment, 

the sample will consist of 20 percent of the components in each unit. For the “closed cycle 

cooling water” environment, each sample will consist of 25 components. The applicant stated 

that the inspection locations will be selected based on the likelihood of age-related degradation 

and that the repetitive tasks to perform these inspections will have a frequency interval not to 

exceed once every 10 years. The staff notes that the program currently includes opportunistic 

visual inspections of components whenever a closed cycle cooling water system boundary is 

opened. The staff finds the applicant’s response acceptable because the proposed sample size 

of 20 percent or 25 components is consistent with guidance provided in other GALL Report 

AMPs that use sampling. The staff’s concern described in RAI B.2.1.13-1 is resolved.

During its reviews related to the “detection of aging effects” program element, the staff noted 

that the only components being managed for reduction of heat transfer by this AMP were heat 

exchanger tubes in LRA Table 3.3.2-8, “Diesel Generator and Auxiliaries System.” The staff 

also noted that the heat exchanger tubes for the drywell penetration cooling coils in LRA 

Table 3.3.2-1, “Closed Cycle Cooling Water System,” are not being managed for reduction of 

heat transfer because the cooling provided to the drywell penetrations does not need to be 

credited for license renewal. In that regard, the staff noted that AMR item 3.5.1-3, associated 

with aging management of concrete exposed to elevated temperatures, is designated as “not 

applicable” because localized concrete temperatures greater than 200 °F have not been 

reported. The staff noted that, although cooling of the drywell penetrations may not be required 

to be credited, cooling provided by the drywell penetrations coils is the reason why localized 

concrete temperatures greater than 200 °F were not reported. It was unclear to the staff how 

aging effects related to elevated temperatures adjacent to the drywell penetrations could be 

considered not applicable unless heat transfer for the associated cooling coils was being 

managed. By letter dated July 7, 2015, the staff issued RAI B.2.1.13-2, requesting that the 

applicant either identify the activities that will be credited for ensuring local temperatures will be 

maintained less than 200 °F or provide the plant-specific AMP described in 

SRP-LR, item 3.5.1-3, for managing reduction of strength and modulus for concrete due to 

elevated temperatures.

In its response dated August 6, 2015, the applicant stated that the penetration cooling coils 

prevent heat-induced degradation of the local concrete surrounding the penetrations during 
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normal modes of reactor operation. Although the applicant did not consider this preventive 

measure as a license renewal intended function, it recognized the need to ensure that this 

preventive measure is maintained. Consequently, the applicant revised LRA Sections A.2.1.13 

and B.2.1.13 to include an enhancement to the Closed Treated Water Systems program to 

perform monthly monitoring and trending of the cooling coil outlet temperatures to ensure 

adequate cooling is being provided to the concrete adjacent to the drywell penetrations. The 

staff finds the applicant’s response acceptable because the enhancement to the Closed Treated 

Water Systems program will ensure that the preventive measure provided by cooling the 

concrete adjacent to the drywell penetrations will be maintained during the period of extended 

operation. The staff’s concern described in RAI B.2.1.13-2 is resolved.

The staff also reviewed the portions of the “parameters monitored or inspected,” “detection of 

aging effects,” and “monitoring and trending” program elements associated with the 

enhancements to determine whether the program will be adequate to manage the aging effects 

for which it is credited. The staff’s evaluation of the enhancements follows.

Enhancement 1. LRA Section B.2.1.13 includes an enhancement to the “parameters monitored 

or inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that condition monitoring, including visual inspections and nondestructive 

examinations, will be performed on a representative sample of piping and components at an 

interval not to exceed 10 years. Aspects of this enhancement were the subject of 

RAI B.2.1.13-1 and are discussed above. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M21A and, as discussed above, finds 

this enhancement acceptable because inspecting a representative sample of piping and 

components exposed to closed cycle cooling water is consistent with the GALL Report AMP.

Enhancement 2. As modified by letter dated August 6, 2015, LRA Section B.2.1.13 includes an 

enhancement to the “parameters monitored or inspected” and “monitoring and trending” 

program elements. In this enhancement, the applicant stated that drywell penetration cooling 

coil outlet temperatures will be monitored and trended monthly to ensure that adequate cooling 

is being provided to the concrete adjacent to the drywell penetrations. This enhancement 

resulted from RAI B.2.1.13-2, and, as discussed above, the staff finds this enhancement 

acceptable because it will ensure that the preventive measure provided by cooling the concrete 

adjacent to the drywell penetrations will be maintained during the period of extended operation.

Based on its audit and review of the applicant’s responses to RAIs B.2.1.13-1 and B.2.1.13-2, 

the staff finds that the program elements 1 through 6, for which the applicant claimed 

consistency with the GALL Report, are consistent with the corresponding program elements of 

GALL Report AMP XI.M21A. The staff also reviewed the enhancements associated with the 

“parameters monitored or trended,” “detection of aging effects,” and “monitoring and trending” 

program elements and their justifications and finds that, when implemented, they will make the 

AMP adequate to manage the aging effects.

Operating Experience. LRA Section B.2.1.13 summarizes operating experience related to the 

Closed Treated Water Systems program. The applicant identified an issue in 2003 with the pH 

and ammonia levels during routine sampling of the containment chilled water system and 

required chemical adjustments to bring chemistry parameters within acceptance limits. 

Although this eventually resolved the issue, as part of the corrective action process, chemistry 

personnel assessed the need for multiple chemical additions, concluded that the current biocide 

may not be effective, and identified an acceptable alternative biocide based on EPRI guidance 

and benchmarking at another station. The applicant also identified an issue in 2010 with low 
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nitrite levels in the turbine building closed cooling water system. After a repeat occurrence 

following chemical adjustments, the applicant determined that a system leak in the supply to the 

station air compressor resulted in frequent water makeup, causing the nitrite level to be outside 

its acceptance limit. Corrective actions to repair the leak and to restore chemistry within 

acceptance limits appropriately resolved the issue.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff identified operating experience for which it determined the need for 

additional clarification, which resulted in the issuance of RAIs, as discussed below.

During its review of plant-specific operating experience, the staff noted that AR00299270, 

AR00200440, and AR00200183 identified cracking in heat exchanger tubes associated with the 

reactor recirculation pump motor coolers. However, the heat exchanger tubes and tube side 

components for the motor coolers in LRA Table 3.1.2-1, “Reactor Coolant Pressure Boundary 

System,” did not identify cracking as an aging effect being managed for these components. By 

letter dated July 7, 2015, the staff issued RAI B.2.1.13-3, requesting that the applicant either 

provide the technical bases to show that cracking does not need to be managed for these 

components or provide additional AMR items that address cracking.

In its response dated August 6, 2015, the applicant stated that the three operating experience 

reports cited in the RAI related to a single event from 2004. The applicant also stated that 

following eddy current testing, inspection, and analysis by industry experts, the cracking was 

determined to originate from the external surface of the tubes, which is exposed to air not 

cooling water. The analysis concluded that the degradation was due to external contamination 

introduced through manufacturing practices or through inadequate storage practices before

installation. The applicant’s corrective and extent of condition actions included nondestructive 

examinations of all reactor recirculation pump motor coolers and repairs to any tubes as 

indicated by eddy current results.

During its review of the above issue, the applicant determined that the material for the reactor 

recirculation pump cooler tubes was copper alloy greater than 15-percent zinc instead of less 

than 15-percent zinc, as originally shown in LRA Table 3.1.2-1. Consequently, the applicant 

revised LRA Table 3.3.1, item 3.3.1-72, and LRA Table 3.1.2-1 to reflect the change in material 

and to add cracking and selective leaching as aging effects requiring management. The 

applicant also performed an extent of condition review and identified similar errors for the 

specified materials in tanks and valve bodies for the fire protection system. The applicant 

revised LRA Table 3.3.2-12 to correct the identified inconsistencies. The staff finds the 

response acceptable because the applicant will ultimately manage cracking of the reactor 

recirculation pump motor coolers based on the revised tube material. Even though the 

operating experience reports involved external cracking, aging management of cracking for tube 

internal surfaces will require additional eddy current testing that, as the applicant has 

demonstrated, is able to identify cracking initiated on the external surfaces of the tubes. In 

addition, the staff considers the applicant’s extent of condition reviews to identify comparable 

cracking in the other pump motor coolers and to identify comparable inconsistencies in the tube 

materials to be reasonable corrective actions. The staff’s concerns described in RAI B.2.1.13-3 

are resolved.
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In consideration of industry operating experience related to this program, the staff reviewed the 

applicant’s evaluation associated with Licensee Event Report 263/2014-01, “Primary System 

Leakage Found in Recirculation Pump Upper Seal Heat Exchanger.” The event report 

addresses cracking in a stainless steel heat exchanger tube caused by unrecognized localized 

boiling that led to an unexpectedly high concentration of chlorides from the chemistry 

constituents in the reactor building closed cooling water system. The applicant’s evaluation of 

the event report states that the heat exchanger configuration at LSCS (describe as “a tube

within a tube,” as compared to the “tube within a box” described in the licensee event report) 

does not allow similar chloride concentrations and that, because the heat exchanger is external 

to the pump, it is visually inspected at each outage. In its review of the applicant’s evaluation, 

the staff was concerned that a similar heat exchanger configuration would allow similar chloride 

concentrations and that visual inspections during the outage could not detect cracking of the 

interior tube. By letter dated July 7, 2015, the staff issued RAI B.2.1.13-4 requesting the 

applicant to provide an assessment of the operating experience evaluation discussed above.

In its response dated August 6, 2015, the applicant stated that, although LSCS’s recirculation 

pump seal coolers have a similar configuration to the coolers described in the licensee event 

report, other design differences minimize the probability of this type of event from occurring at 

LSCS. The critical difference is that the recirculation pump seal water is not reactor water; 

instead, it is seal purge water from the control rod drive system, which is less than 140 °F 

during normal operation. This is well below the boiling point of the reactor building closed 

cooling water system, and chloride concentration, as described in the licensee event report,

cannot occur.

However, as part of its evaluation, the applicant determined that the stainless steel seal cooler 

tubes can be exposed to temperatures greater than 140 °F, based on operating data, and that 

cracking is an applicable aging effect for the recirculation pump seal cooler. In addition, the 

applicant also discovered that the seal coolers were inadvertently omitted from LRA 

Tables 2.3.1-1, 3.1.2-1, and 3.3.1. The applicant revised the applicable tables as part of its 

response and performed an extent of condition review to ensure similar omissions did not occur. 

The staff finds the response acceptable because, although design differences would not allow 

chloride concentration to occur similar to that in the licensee event report, the applicant will 

manage cracking of the stainless steel seal cooler tubes because these components can be 

exposed to temperatures greater than 140 °F. In addition, the staff considers the applicant’s 

extent of condition review for identifying comparable omissions in the LRA to be a reasonable 

corrective action. The staff’s concerns described in RAI B.2.1.13-4 are resolved.

Based on its Audit Report, review of the application, and review of the applicant’s responses to 

RAIs B.2.1.13-3 and B.2.1.13-4, the staff finds that the applicant has appropriately evaluated 

plant-specific and industry operating experience and that implementation of the program has 

resulted in the applicant taking corrective actions. In addition, the staff finds that the conditions 

and operating experience at the plant are bounded by those for which GALL Report 

AMP XI.M21A was evaluated.

UFSAR Supplement. LRA Section A.2.1.13, as modified by letter dated August 6, 2015, 

provides the UFSAR supplement for the Closed Treated Water Systems program. The staff 

reviewed this UFSAR supplement description of the program and noted that it is consistent with 

the recommended description in SRP-LR Table 3.0-1. The staff also noted that in Commitment

No. 13 the applicant will implement the two program enhancements discussed above before the 

period of extended operation. The staff finds that the information in the UFSAR supplement is 

an adequate summary description of the program.
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Conclusion. On the basis of its audit and review of the applicant’s Closed Treated Water 

Systems program, the staff determines that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent with AMP XI.M21A. The staff also 

reviewed the enhancements and confirmed that their implementation before the period of 

extended operation will make the AMP adequate to manage the applicable aging effects. The 

staff concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems

Summary of Technical Information in the Application. LRA Section B.2.1.14 describes the 

existing Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems program as consistent, with an enhancement, with GALL Report AMP XI.M23, 

“Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems.” 

The LRA states that the AMP manages the aging effects of loss of material for bridge, bridge 

rails, and bolting and trolley structural components for cranes, hoists, and rigging beams 

exposed to an air-indoor uncontrolled and treated water environments. The AMP also manages 

the aging effect of loss of preload for bolted connections. The LRA states that the AMP 

manages these aging effects through periodic inspections consistent with the ASME Code B.30 

series of standards. The AMP also has procedures and controls that implement the guidance in 

NUREG-0612, “Control of Heavy Loads at Nuclear Power Plants: Resolution of Generic 

Technical Activity A-36,” dated July 1980.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M23. The staff also reviewed the 

portions of the “scope of program,” “parameters monitored or inspected,” and “detection of aging 

effects” program elements associated with the enhancement to determine whether the program 

will be adequate to manage the aging effects for which it is credited. The staff’s evaluation of 

this enhancement follows.

Enhancement 1. LRA Section B.2.1.14 includes an enhancement to the “scope of program,” 

“parameters monitored or inspected,” and “detection of aging effects” program elements. In this 

enhancement, the applicant stated that additional guidance will be provided “to include 

inspection of structural components, rails, and bolting for loss of material due to corrosion; rails 

for loss of material due to wear; and bolted connections for loss of preload.” The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP XI.M23 

and finds it acceptable because this will make the Inspection of Overhead Heavy Load and Light 

Load (Related to Refueling) Handling Systems program consistent with the GALL Report 

AMP XI.M23 recommendations to manage the effects of loss of material due to corrosion or 

wear for crane rails and structural components and loss of preload for bolted connections.

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M23. In addition, the staff reviewed the enhancements 

associated with the “scope of program,” “parameters monitored or inspected,” and “detection of 
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aging effects” program elements and finds that, when implemented, they will make the AMP 

adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.14 summarizes operating experience related to the 

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems

program. The LRA states that, in June 2011, during a periodic inspection of the reactor building 

crane, the applicant detected signs of wear on the east and west side rails and associated 

bridge wheels of the crane. The applicant initiated a corrective action program issue report and 

took corrective actions to address this issue. Corrective actions taken by the applicant included 

working with the crane vendor to identify the cause of the damage, identifying that the cause of 

the damage was misalignment of the rails, making repairs to realign the rails, and replacing or 

repairing the wheels.

The LRA states that, in 2012, during inspection of the LSCS, Unit 2, turbine building crane, the 

applicant detected one sheared bolt and several loose structural bolts. The applicant initiated a 

corrective action program issue report to address this issue and removed the crane from service 

until repaired. As part of its corrective actions, the applicant determined that the bolts became 

loose due to the vibration in the trolley rails, which was caused by the increased friction at one 

of the cab wheels. The applicant inspected and repaired the cab wheels, tightened the loose 

bolts, and replaced the sheared bolt. To prevent recurrence of this issue the applicant revised 

its preventive maintenance tasks for the turbine and reactor building cranes to (1) include a 

requirement that a representative from the crane manufacturing company be present when 

performing annual periodic inspections and (2) use a man-lift during inspection of the cranes for 

a more thorough inspection.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M23 was evaluated.

UFSAR Supplement. LRA Section A.2.1.14 provides the UFSAR supplement for the Inspection 

of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems program. 

The staff reviewed this UFSAR supplement description of the program and noted that it is 

consistent with the recommended description in SRP-LR Table 3.0-1. The staff also noted that 

the applicant committed to implement the enhancement to the program before the period of 

extended operation. The staff finds that the information in the UFSAR supplement is an 

adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Inspection of Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems program, the staff 

determines that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. In addition, the staff reviewed the enhancement and confirmed 
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that its implementation before the period of extended operation will make the AMP adequate to 

manage the applicable aging effects. The staff concludes that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Compressed Air Monitoring

Summary of Technical Information in the Application. LRA Section B.2.1.15 describes the 

existing Compressed Air Monitoring program as consistent, with an exception and 

enhancements, with GALL Report AMP XI.M24, “Compressed Air Monitoring.” The LRA states 

that the AMP addresses loss of material on piping and components in a condensation 

environment in the compressed air systems. The LRA also states that the AMP proposes to 

manage the aging effect through monitoring of air moisture content and contaminants to 

maintain specified limits and through inspection of components for indications of loss of material 

due to corrosion. Additionally, the LRA states that the AMP is based on the response to NRC 

GL 88-14, “Instrument Air Supply System Problems Affecting Safety-Related Equipment,” dated 

August 8, 1988.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M24. The staff also reviewed the 

portions of the “parameters monitored or inspected,” “detection of aging effects,” “monitoring 

and trending,” and “acceptance criteria” program elements associated with the exception and 

enhancements to determine whether the program will be adequate to manage the aging effects 

for which it is credited. The staff’s evaluation of the exception and enhancements follows.

Exception 1. LRA Section B.2.1.15 includes an exception to the “monitoring and trending” 

program element. In this exception, the applicant stated that dew point testing and trending is 

performed quarterly rather than daily as recommended in the GALL Report. The staff noted that 

the applicant uses the guidance of Section 5.1, “Pressure Dew Point,” of American National 

Standard Institute (ANSI)/ISA-7.0.01-1996, “Quality Standard for Instrument Air,” approved 

November 12, 1996, which states that “a monitored alarm is preferred; however, if a monitored 

alarm is unavailable, per shift monitoring is recommended.” The staff also noted that the 

applicant’s instrument compressed air system dryer outlet dew points are continuously 

monitored by in-line detectors with automatic alarms in the main control room. On a quarterly 

basis, samples are taken from representative locations and are analyzed for dew point,

particulates, and hydrocarbons, which validates the dew point in-line detectors. The staff 

reviewed this exception against the corresponding program elements in GALL Report 

AMP XI.M24 and finds it acceptable because the applicant will continuously monitor the dew 

point, which will alert the applicant to any potential moisture within the system by an alarm in the 

control room. Additionally, taking quarterly air samples for dew point and contaminants is 

consistent with the guidance in ASME OM-S/G-1998, Part 17.

Enhancement 1. LRA Section B.2.1.15 includes an enhancement to the “parameters monitored 

or inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that inspection of internal surfaces of system filters, compressors, and 

after-coolers for signs of corrosion and corrosion products will be performed. The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP XI.M24 
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and finds it acceptable because, when it is implemented, it will be consistent with the 

GALL Report recommendations.

Enhancement 2. LRA Section B.2.1.15 includes an enhancement to the “Monitoring and 

Trending” program element. In this enhancement, the applicant stated that analysis and 

trending will be performed on the results from the air quality monitoring and visual inspection. 

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.M24 and finds it acceptable because, when it is implemented, it will be 

consistent with the GALL Report recommendations.

Enhancement 3. LRA Section B.2.1.15 includes an enhancement to the “Acceptance Criteria” 

program element. In this enhancement, the applicant stated that deficiencies will be 

documented in the corrective action program, which are identified during visual inspections of 

the internal surfaces of system components. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M24 and finds it acceptable because,

when it is implemented, it will be consistent with the GALL Report recommendations.

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M24. In addition, the staff reviewed the enhancements

associated with the “parameters monitored or inspected,” “detection of aging effects,” 

“monitoring and trending,” and “acceptance criteria” program elements and finds that, when 

implemented, they will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.15 summarizes operating experience related to the 

Compressed Air Monitoring program. The applicant described a recent quarterly sample that 

was taken from several locations in the instrument air and drywell pneumatic air systems and 

analyzed for dew point, hydrocarbons, and particulates. The results were within the acceptance 

criteria for each parameter. The applicant also described receiving an alarm for the station air 

dryer high humidity in February 2008. The condition was documented in the corrective action 

program, and the applicant determined that a circuit board in the humidity sensing circuit 

needed to be replaced. After the applicant replaced the circuit board, it calibrated the humidity 

sensor and returned the dryer to service.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M24 was evaluated.

UFSAR Supplement. LRA Section A.2.1.15 provides the UFSAR supplement for the 

Compressed Air Monitoring program. The staff reviewed this UFSAR supplement description of 

the program and noted that it is consistent with the recommended description in SRP-LR 
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Table 3.0-1. The staff also noted that the applicant committed to ongoing implementation of the 

existing Compressed Air Monitoring program for managing the effects of aging for applicable 

components during the period of extended operation and committed to implement the 

enhancements to the program before the period of extended operation. The staff finds that the 

information in the UFSAR supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Compressed Air Monitoring

program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report XI.M24 are consistent. In addition, the staff reviewed the 

exception and its justifications and determines that the AMP, with the exception, is adequate to 

manage the applicable aging effects. In addition, the staff reviewed the enhancements and 

confirmed that their implementation before the period of extended operation will make the AMP 

adequate to manage the applicable aging effects. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Fire Protection

Summary of Technical Information in the Application. LRA Section B.2.1.16 describes the

existing Fire Protection program as consistent, with enhancements, with GALL Report 

AMP XI.M26, “Fire Protection.” The LRA states that this program is a condition and performance 

monitoring program that manages the aging effects of the fire barriers and the low-pressure 

carbon dioxide (CO2) systems and associated components exposed to air-indoor uncontrolled 

and air-outdoor environments through the use of periodic inspections and functional testing. 

This program includes visual inspections of no less than 10 percent of each type of penetration 

seal at least once per refueling cycle (24 months). This program also includes visual 

examinations of the fire barrier walls, ceilings, and floors at least once per 24 months. In 

addition, the program encompasses periodic visual inspections and functional testing of the fire 

doors and the low-pressure CO2 fire suppression system components within the scope of 

license renewal.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M26. The staff also reviewed the 

portions of the “parameters monitored or inspected,” “detection of aging effects,” and 

“acceptance criteria” program elements associated with enhancements to determine whether 

the program will be adequate to manage the aging effects for which it is credited. The staff’s 

evaluation of these enhancements follows.

Enhancement 1. LRA Section B.2.1.16 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “acceptance criteria” program elements. In this 

enhancement, the applicant stated that it will perform periodic visual inspection of combustible 

liquid spill retaining curbs. GALL Report AMP XI.M26 recommends that components with a fire 

barrier function be managed for aging. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M26 and finds it acceptable because,

when it is implemented, it will apply periodic visual inspections to the combustible liquid spill 

retaining curbs consistent with the GALL Report.
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Enhancement 2. LRA Section B.2.1.16 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “acceptance criteria” program elements. In this 

enhancement, the applicant stated that it will perform periodic visual inspection for identification 

of corrosion that may lead to loss of material on the external surfaces of the low-pressure CO2

fire suppression systems. GALL Report AMP XI.M26 recommends that the CO2 fire 

suppression system be visually inspected for signs of corrosion. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.M26 and 

finds it acceptable because, when it is implemented, it will apply visual inspections to the 

external surfaces of the low-pressure CO2 systems visible to eyes consistent with the 

GALL Report. The staff noted that the applicant’s inspection technique is also consistent with 

the industry practice of avoiding disrupting factory-installed insulation when conducting visual 

inspections of the CO2 systems.

Enhancement 3. LRA Section B.2.1.16 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “acceptance criteria” program elements. In this 

enhancement, the applicant stated that it will provide additional inspection guidance to identify 

additional aging effects of (a) fire barrier walls, ceilings, and floor degradation, such as spalling, 

cracking, and loss of material for concrete, and (b) elastomeric fire barrier material degradation, 

such as loss of material, shrinkage, separation from walls and components, increased 

hardness, and loss of strength. GALL Report AMP XI.M26 recommends visual inspections of 

the fire barrier walls, ceilings, floors, and other fire barriers to detect any sign of degradation, 

such as spalling, cracking and loss of material caused by freeze-thaw, chemical attack, and 

reaction with aggregates. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.M26 and finds it acceptable because, when it is 

implemented, it will align its fire barrier inspections with the GALL Report guidance by explicitly 

specifying the examination of aging effects (e.g., spalling and cracking) during inspections.

Enhancement 4. LRA Section B.2.1.16 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “acceptance criteria” program elements. In this 

enhancement, the applicant stated that it will provide additional inspection guidance to identify 

degradation of fire barrier penetration seals for aging effects, such as loss of material, cracking, 

increased hardness, shrinkage, and loss of strength. GALL Report AMP XI.M26 recommends 

that visual inspections of penetration seals be performed to detect “any sign of degradation, 

such as cracking, seal separation from walls and components...that are directly caused by 

increased hardness, and shrinkage of seal material due to loss of material.” The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP XI.M26

and finds it acceptable because, when it is implemented, it will align the fire barrier inspections 

with the GALL Report guidance by explicitly specifying that examination of aging effects 

(e.g., shrinkage and increased hardness) during inspections.

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M26. In addition, the staff reviewed the enhancements

associated with the “parameters monitored or inspected,” “detection of aging effects,” and 

“acceptance criteria” program elements and finds that, when implemented, they will make the 

AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.16 summarizes operating experience related to the 

Fire Protection program. In January 2009, the applicant identified a damaged electrical fire seal 

in the auxiliary building while performing periodic inspection of fire penetration seals. A 

1-inch-diameter by 5-inch-deep hole through the outer gypsum layer was discovered. This 
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defect was entered into the corrective action program, scheduled for repair, and evaluated by 

Engineering for meeting the design requirements in the damaged state.

In January 2009, the applicant identified a damaged fire seal on the turbine building side of the 

electrical wall penetration seal separating the auxiliary building and the LSCS, Unit 2, turbine 

building. The damaged gypsum seal was approximately 7 inches (width) by 2 inches (height) by 

1 inch (depth). The condition was entered into the corrective action program. An evaluation 

was initiated to determine whether there was sufficient material left to maintain the fire barrier 

function.

In September 2005, a fire door was found inoperable because the door seam was damaged. 

Upon discovery, a compensatory measure of “once an hour fire watch” was instituted until the 

door was repaired and returned to service.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M26 was evaluated.

UFSAR Supplement. LRA Section A.2.1.16 provides the UFSAR supplement for the Fire 

Protection program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant committed to ongoing implementation of the existing Fire 

Protection program for managing the effects of aging for applicable components during the 

period of extended operation. The staff finds that the information in the UFSAR supplement is 

an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Fire Protection program, the 

staff determines that those program elements for which the applicant claimed consistency with 

the GALL Report are consistent. In addition, the staff reviewed the enhancements and 

confirmed that their implementation before the period of extended operation will make the AMP 

adequate to manage the applicable aging effects. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Fire Water System

Summary of Technical Information in the Application. LRA Section B.2.1.17 describes the 

existing Fire Water System program as consistent, with exceptions and enhancements, with 
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GALL Report AMP XI.M27, “Fire Water System,” as modified by LR-ISG-2012-02 “Aging 

Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and 

Corrosion under Insulation.” The LRA states that the AMP addresses sprinklers; nozzles; 

fittings; valve bodies; fire pump casings; hydrants; hose stations; standpipes; aboveground and 

buried piping; and components for water-based fire protection systems exposed to indoor 

uncontrolled air, outdoor air, condensation, and raw water to manage the effects of loss of 

material. The LRA also states that the AMP proposes to manage this aging effect through 

monitoring; performance monitoring; and preventive actions, such as periodic flushing and 

system performance testing.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M27. For the “detection of aging 

effects” and “acceptance criteria” program elements, the staff determined the need for additional 

information, which resulted in the issuance of RAIs, as discussed below.

The “detection of aging effects” program element in GALL Report AMP XI.M27, as amended by 

LR-ISG-2012-02, recommends the use of National Fire Protection Association (NFPA) 25, 

“Standard for the Inspection, Testing, and Maintenance of Water-Based Fire Protection 

Systems,” Section 13.2.5, for main drain testing, which includes criteria for trending and 

comparison of full flow pressures and for actions to take, such as identification and correction, 

when there is a 10-percent reduction in full flow pressure. However, during its audit, the staff 

found that the applicant’s Fire Water System program states that, if there is a difference of 5 psi 

when comparing full flow pressures from the previous test, an issue report will be generated. By 

letter dated June 8, 2015, the staff issued RAI B.2.1.17-5, requesting that the applicant justify 

how performing analysis and trending on changes in pressure will provide reasonable 

assurance that the main drain test will be consistent with NFPA 25 and GALL Report 

AMP XI.M27.

In its response dated July 1, 2015, the applicant stated that Enhancement 9 was added to the 

LRA. The enhancement is discussed below.

The “acceptance criteria” program element in GALL Report AMP XI.M27, as amended by 

LR-ISG-2012-02, recommends removing foreign organic or inorganic material from piping or 

sprinklers, determining its source, and correcting it. However, during the audit the staff found 

that the applicant’s Fire Water System program states that it will use the corrective action 

program to report any flow blockage found and that it will not remove the material, determine its 

source, and correct it. By letter dated June 8, 2015, the staff issued RAI B.2.1.17-3, requesting 

that the applicant justify how the current “acceptance criteria” program element is sufficient.

In its response dated July 1, 2015, the applicant stated that Enhancement 3 was modified to 

include the specific actions identified in GALL Report AMP XI.M27, program element 6. The 

staff’s evaluation is documented in the Enhancement 3 section of this AMP.

The staff also reviewed the portions of the “parameters monitored or inspected,” “detection of 

aging effects,” “monitoring and trending,” and “acceptance criteria” program elements 

associated with exceptions and enhancements to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

exceptions and enhancements follows.
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Original Exception 1. LRA Section B.2.1.17 includes an exception to the “detection of aging 

effects” program element. In this exception, the applicant stated that it does not perform annual 

main drain tests; instead, it performs alternative testing to meet the drain testing described in 

NFPA 25, Section 13.2.5. By letter dated June 8, 2015, the staff issued RAI B.2.1.17-1,

requesting that the applicant justify how the use of the proposed alternative testing methods to 

main drain tests will provide reasonable assurance that flow blockage will not occur.

In its response dated July 1, 2015, the applicant stated that it will perform main drain tests on all 

in-scope wet pipe sprinkler systems, dry pipe preaction sprinkler systems, and automatic deluge 

systems on an annual frequency, with the exception of two areas that will be on an RFO 

frequency, which is consistent with the recommendations in LR-ISG-2012-02.

The staff finds the applicant’s response acceptable because GALL Report AMP XI.M27, as 

modified by LR-ISG-2012-02, states that testing is to be performed in accordance with 

GALL Report AMP XI.M27 Table 4a, “Fire Water System Inspection and Testing 

Recommendations,” which includes main drain tests on the aforementioned systems. Because 

consistency with the GALL Report is being met for this aspect of the “detection of aging effects” 

program element, the applicant withdrew the original Exception 1. The staff’s concern 

described in RAI B.2.1.17-1 is resolved.

Exception 1. LRA Section B.2.1.17 includes an exception to the “detection of aging effects” 

program element. In this exception, the applicant stated that deluge systems for charcoal units 

cannot be tested with water and that they have no provisions to perform an air test to verify that

the spray openings are not obstructed. By letter dated June 8, 2015, the staff issued 

RAI B.2.1.17-2, requesting that the applicant justify the use of visual examinations every 5 years

in lieu of full flow or air tests for the charcoal filter deluge testing annually.

In its response dated July 1, 2015, the applicant stated that air testing of the charcoal filter 

deluge system will be performed on 8 of the 11 units in addition to valve cycling. The exception 

still remains because 3 of the 11 units have not been configured to allow for air testing or valve 

cycling. As such, these three units will have internal visual examinations performed if blockage 

is found in any of the aforementioned eight units.

Enhancement 6 was added to the LRA for the air testing of the 8 of the 11 systems on an 

annual frequency. Enhancement 7 was added to the LRA to perform inspections on the 

charcoal filter deluge nozzles and piping within the filter housing on a 24-month frequency.

The staff finds the applicant’s response acceptable because a representative sample of the 

charcoal filter deluge systems on either an annual or 24-month frequency will be performed, and 

it is consistent with GALL Report AMP XI.M27 Table 4a, “Fire Water System Inspection and 

Testing Recommendations,” which recommends using NFPA 25. The staff’s concern described 

in RAI B.2.1.17-2 is resolved.

Exception 2. LRA Section B.2.1.17 includes an exception to the “detection of aging effects” 

program element. In this exception, the applicant stated that, because variations in wall 

thickness are possible due to manufacturing tolerances, followup volumetric examinations will 

not be performed when the observed wall thickness is indicative of wall thickness below 

nominal, even when surface irregularities are detected. The applicant stated that it will perform 

periodic visual internal inspections for loss of material and flow blockage in conjunction with 

volumetric examinations when appropriate to evaluate unexpected levels of degradation. The 

staff reviewed this exception against the corresponding program element in GALL Report 
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AMP XI.M27 and finds it acceptable because the staff recognizes that piping may have wall 

thickness less than nominal due to manufacturing process variations.

Exception 3. LRA Section B.2.1.17 includes an exception to the “parameters monitored or 

inspected” and “detection of aging effects” program elements. In this exception, the applicant 

stated that external visual inspections of sprinkler systems are performed on a 24-month 

frequency, in accordance with the Technical Requirements Manual (TRM) Section 3.7.k, rather 

than on the annual basis stated in GALL Report AMP XI.M27, as modified by LR-ISG-2012-02. 

By letter dated June 8, 2015, the staff issued RAI B.2.1.17-4, requesting that the applicant 

justify the frequency of inspections for the sprinklers and the exclusion of visual examination 

criteria for leakage, loss of fluid in the glass bulbs, and loading from sprinkler inspections.

In its response dated July 1, 2015, the applicant stated that the NRC-approved TRM and Fire 

Protection Program establishes a 24-month inspection plan. In addition, inspection results did 

not identify any age-related degradation issues.

The applicant also stated that Enhancement 8 was added to identify the need to inspect for 

water leakage and loss of fluid in the glass bulbs. Loading was not added to the program 

because it is already contained in the site inspection procedure LOS-FP-SR3.

The staff finds the applicant’s response acceptable because the 24-month frequency was 

preapproved by the NRC and is in accordance with an RFO cycle frequency. Additionally, with 

the addition of Enhancement 8 to the LRA, the applicant is consistent with GALL Report 

AMP XI.M27, as modified by LR-ISG-2012-02, to provide reasonable assurance that sprinkler 

systems will be able to perform their intended function during the period of extended operation. 

The staff’s concern described in RAI B.2.1.17-4 is resolved.

Enhancement 1. LRA Section B.2.1.17 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “acceptance criteria” program elements. In this 

enhancement, the applicant stated that volumetric examinations will be performed every year at 

five locations on carbon steel aboveground fire water piping that is susceptible to 

microbiologically-induced corrosion to identify loss of material. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.M27 and 

finds it acceptable because, when implemented, it will inspect and detect degradation on a 

representative sampling basis at a specified frequency, in accordance with GALL Report 

AMP XI.M27, as modified by LR-ISG-2012-02.

Enhancement 2. LRA Section B.2.1.17 includes an enhancement to the “parameters monitored 

or inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that visual inspections will be performed for loss of material and flow 

obstructions of the accessible header piping and sparger external surfaces for the deluge 

systems located within filter plenums on a once per refueling cycle frequency. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.M27 and finds it acceptable because, when implemented, it will be consistent with 

GALL Report AMP XI.M27 in that inspections will be performed to detect degradation on a 

refueling cycle frequency.

Enhancement 3. LRA Section B.2.1.17 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “acceptance criteria” program elements. In this 

enhancement, the applicant stated that internal visual inspections of sprinkler and deluge 

system piping will be performed to identify internal corrosion and obstructions to flow. However, 
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if a flow obstruction is observed, the applicant will note the obstruction in the corrective action 

program. By letter dated June 8, 2015, the staff issued RAI B.2.1.17-3, requesting that the 

applicant provide justification for the “acceptance criteria” program element on removing foreign 

organic or inorganic material found obstructing piping or sprinklers and on determining and 

correcting its source versus simply adding the noted material in the corrective action program.

In its response dated July 1, 2015, the applicant stated that it added the guidance to remove, to 

determine the source, and to correct foreign material found obstructing piping or sprinklers to 

this enhancement to be consistent with the guidance in GALL Report AMP XI.M27, as modified 

by LR-ISG-2012-02.

The staff finds the applicant’s response acceptable because, with the addition of removing the

material, determining its source, and correcting foreign material found obstructing piping or 

sprinklers, it provides reasonable assurance that the fire water sprinkler and deluge system 

piping will be able to perform its intended function throughout the period of extended operation. 

The staff’s concern described in RAI B.2.1.17-3 is resolved.

Enhancement 4. LRA Section B.2.1.17 includes an enhancement to the “acceptance criteria” 

program element. In this enhancement, the applicant stated that it will perform obstruction 

evaluations of the fire water system when degraded conditions are identified by visual 

inspections, flow testing, or volumetric examinations. The staff reviewed this enhancement 

against the corresponding program elements in GALL Report AMP XI.M27 and finds it 

acceptable because, when implemented, it will perform various types of testing to detect and 

measure degradation in the fire water system for possible sources of materials that could cause 

pipe blockage.

Enhancement 5. LRA Section B.2.1.17 includes an enhancement to the “detection of aging 

effects” and “monitoring and trending” program elements. In this enhancement, the applicant 

stated that it will demonstrate the capability to provide the design pressure at required flow by 

performing flow tests for hose stations at the hydraulically most limiting locations for each zone 

of the system on a 5-year frequency. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M27 and finds it acceptable because, 

when implemented, it will provide reasonable assurance that the intended function, which is to 

ensure the required flow at the required pressure, will be maintained throughout the period of 

extended operation.

Enhancement 6. By letter dated July 1, 2015, the applicant revised LRA Sections A.2.1.17 and 

B.2.1.17 to include an enhancement to the “parameters monitored or inspected” and “detection 

of aging effects” program elements. In this enhancement, the applicant stated that for charcoal 

filter units it will perform annual air tests on the deluge systems, excluding three filter unit 

systems. In addition, visual internal examinations will be performed on the three excluded tests 

if blockage is found on any deluge system that could be generic in nature. The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP XI.M27 

and finds it acceptable as documented in Exception 1.

Enhancement 7. By letter dated July 1, 2015, the applicant revised LRA Sections A.2.1.17 and 

B.2.1.17 to include an enhancement to the “parameters monitored or inspected” and “detection 

of aging effects” program elements. In this enhancement, the applicant stated that it will 

perform visual inspections on a 24-month frequency of all charcoal filter unit deluge nozzles for 

verification that the nozzles are not obstructed and have proper orientation. The staff reviewed 
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this enhancement against the corresponding program elements in GALL Report AMP XI.M27 

and finds it acceptable as documented in Exception 1.

Enhancement 8. By Letter dated July 1, 2015, the applicant revised LRA Sections A.2.1.17 and 

B.2.1.17 to include an enhancement to the “parameters monitored or inspected” and “detection 

of aging effects” program elements. In this enhancement, the applicant stated that when 

performing visual inspections of sprinkler systems, it will include an inspection for water leakage 

and loss of fluid in the glass bulbs of sprinkler heads. The staff reviewed this enhancement 

against the corresponding program elements in GALL Report AMP XI.M27 and finds it 

acceptable because, when implemented, it will provide reasonable assurance that any 

sprinklers exhibiting signs of leakage and loss of fluid in the glass bulbs, along with the other 

inspection criteria already included, will be replaced, consistent with NFPA 25, in accordance 

with GALL Report AMP XI.M27, as amended by LR-ISG-2012-02.

Enhancement 9. By letter dated July 1, 2015, the applicant revised LRA Sections A.2.1.17 and 

B.2.1.17 to include an enhancement to the “monitoring and trending” and “acceptance criteria” 

program elements. In this enhancement, the applicant stated that for main drain testing, 

acceptance criteria will include the monitoring of flowing pressures from test to test. The 

applicant also stated that an issue report will be generated to determine the cause and to 

correct it, if necessary, if there is a 10-percent reduction in full flow pressure when compared to 

that of previously performed tests. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M27 and finds it acceptable because 

any degradation noted will be addressed with an issue report when a 10-percent reduction in full 

flow pressure compared to that of previously performed tests is identified. This provides 

reasonable assurance throughout the period of extended operation that a degrading trend will 

be identified and corrected to ensure that the intended function of the fire water system will be 

maintained. The staff’s concern described in RAI B.2.1.17-5 is resolved by the addition of this 

enhancement.

Enhancement 10. By letter dated July, 1, 2015, the applicant revised LRA Sections A.2.1.17

and B.2.1.17 to include an enhancement to the “parameters monitored or inspected,” “detection 

of aging effects,” and “monitoring and trending” program elements. In this enhancement, the 

applicant stated that a 2-year frequency for yard loop flow testing will be maintained until the 

section of piping from the pump house to node 515 is restored to normal flow conditions. The 

staff reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.M27 and finds it acceptable because, when implemented, it will use the corrective 

action program and past test data to ensure that the affected section of piping will perform its 

intended function throughout the period of extended operation.

Based on its audit and review of the applicant’s responses to RAIs B.2.1.17-1, B.2.1.17-2, 

B.2.1.17-3, B.2.1.17-4, and B.2.1.17-5, the staff finds that program elements 1 through 6 for 

which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.M27. The staff also reviewed the 

exceptions associated with the “detection of aging effects” program element and their 

justifications and finds that the AMP, with the exceptions, is adequate to manage the applicable 

aging effects. In addition, the staff reviewed the enhancements associated with the “parameters 

monitored or inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance 

criteria” program elements and finds that, when implemented, they will make the AMP adequate 

to manage the applicable aging effects.
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Operating Experience. LRA Section B.2.1.17 summarizes operating experience related to the 

Fire Water System program. In January 2012 and March 2010, through-wall leaks were 

identified in fire header piping and fire protection piping for the diesel generator, respectively, 

and were entered into the corrective action program. These were also evaluated as a part of 

the raw water corrosion program, and each of the leaking piping segments was isolated and 

replaced. An extent of condition review was performed, which resulted in UT examinations at 

additional locations that identified material loss. After a review of the operating experience by 

the applicant, instances of material loss, including recurring internal corrosion in the fire water 

system piping, were noted. Because of this noted material loss, the applicant stated it will 

perform inspections on the carbon steel fire water piping for corrosion and degradation of the 

piping internal surfaces to incorporate guidance from LR-ISG-2012-02.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

During its review, the staff identified operating experience for which it determined the need for 

additional clarification, which resulted in the issuance of an RAI, as discussed below.

During the audit of the applicant’s operating experience database, the staff noted that there 

were many issue reports generated on the fire water protection system regarding degradation of 

flow characteristics (i.e., C factor) in the underground fire loop, which is a raw water system. 

During the audit, the applicant provided a marked up copy of plant drawing M-775, sheet 1, 

showing the fire protection yard loop with annotated flow testing node points. The applicant

provided additional data to the staff on the C factor from years 2006 through 2014. Based on 

the staff’s review, the piping segment from the diesel-driven fire pump to node 515 shows a 

significant degrading trend. By letter dated June 8, 2015, the staff issued RAI B.2.1.17-6,

requesting that the applicant justify how the degraded section of the fire protection yard loop 

from the diesel-driven fire pump to node 515 will be able to perform its intended function with its 

current significant degrading trend.

In its response dated July 1, 2015, the applicant stated that the fire protection yard loop is 

required to be flow tested on a 36-month frequency, based on TRM Section 3.7.j.18. Even 

though the corrective action program must be used to note system degradation and to reduce 

the testing frequency to annually if the C factor is between 70 and 75, Enhancement 10 was 

added to the LRA to maintain a testing frequency of 24 months until the section of piping from 

the diesel-driven fire pump to node 515 is restored to normal flow conditions with a 

post-maintenance test, at which time the frequency would be returned to 36 months.

The staff finds the applicant’s response acceptable because the applicant is using the corrective 

action program and past test data to ensure that the affected section of piping will perform its 

intended function throughout the period of extended operation. The staff’s concern described in 

RAI B.2.1.17-6 is resolved.

Based on its audit and review of the application and review of the applicant’s response to 

RAI B.2.1.17-6, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and that implementation of the program has resulted in the 

applicant taking corrective actions. In addition, the staff finds that the conditions and operating 
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experience at the plant are bounded by those for which GALL Report AMP XI.M27 was

evaluated.

UFSAR Supplement. As amended by letter dated July 1, 2015, LRA Section A.2.1.17 provides 

the UFSAR supplement for the Fire Water System program. The staff reviewed this UFSAR 

supplement description of the program and noted that it is consistent with the recommended 

description in SRP-LR Table 3.0-1, as modified by LR-ISG-2012-02. The staff also noted that 

the applicant committed to implement the enhancements to the program before the period of 

extended operation. The staff finds that the information in the UFSAR supplement, as amended 

by letter dated July 1, 2015, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Fire Water System program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent with GALL Report AMP XI.M27. In addition, the staff 

reviewed the exceptions and their justifications and determines that the AMP, with the 

exceptions, is adequate to manage the applicable aging effects. In addition, the staff reviewed 

the enhancements and confirmed that their implementation before the period of extended 

operation will make the AMP adequate to manage the applicable aging effects. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Aboveground Metallic Tanks

Summary of Technical Information in the Application. LRA Section B.2.1.18, as amended by 

letter dated August 6, 2015, describes the existing Aboveground Metallic Tanks program as 

consistent, with enhancements, with GALL Report XI.M29, “Aboveground Metallic Tanks,” as 

modified by LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water Systems, 

Atmospheric Storage Tanks, and Corrosion under Insulation.” The LRA states that the AMP is a 

condition monitoring program that addresses outdoor tanks sited on soil or concrete and certain 

indoor large volume tanks exposed to outdoor air, concrete, condensation, soil, and treated 

water environments to manage the effects of loss of material and loss of sealing. The LRA also 

states that the AMP proposes to manage these aging effects through periodic visual inspections 

and volumetric examinations. The LRA further states that the only tanks within the scope of the 

AMP are the cycled condensate storage tanks, which are fabricated from aluminum alloys that 

are not susceptible to SCC.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M29. The staff also reviewed the 

portions of the “parameters monitored or inspected,” “detection of aging effects,” “monitoring 

and trending,” and “acceptance criteria” program elements associated with a staff-identified 

difference and enhancements to determine whether the program will be adequate to manage 

the aging effects for which it is credited. The staff’s evaluation of this staff-identified difference 

and enhancements follows.

Staff-Identified Difference. LRA Section B.2.1.18 does not manage the aging effect of cracking 

and does not take an exception to GALL Report AMP XI.M29. This staff-identified difference 

affects the “parameters monitored or inspected,” “detection of aging effects,” “monitoring and 
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trending,” and “acceptance criteria” program elements. During the audit, the staff reviewed 

drawings and construction details associated with the two cycled condensate storage tanks. 

The drawings specify that the tanks are constructed from 5454-O plate, 6061-T6 structural 

members, 6061-T6 piping, and 6061-O extruded shapes. The staff also noted that LRA 

Table 3.4.2-1, “Condensate System,” plant-specific note 3, states that the tanks are constructed 

from aluminum alloys that are not susceptible to SCC. AMR item 3.4.1-31, cites plant-specific 

note 3.

Aluminum alloy 5454 has a maximum magnesium content of 1.0 weight percent per 

ASTM B209-14, “Standard Specification for Aluminum and Aluminum-Alloy Sheet and Plate,” 

dated November 2014. The 5xxx series aluminum alloys are not susceptible to SCC unless the 

magnesium content is 3.5 weight percent or greater (1, 2). Therefore, aluminum alloy 5454-O is 

not susceptible to SCC. The 6xxx series aluminum alloys are highly resistant to SCC in all 

standard compositions, tempers, and product forms. Aluminum alloy 6061 is only susceptible to 

SCC after being exposed to nontypical heat treatments, which would be outside of standard 

material processes and specifications (1, 2). Aluminum alloy 6061 in the T6 and O temper is 

not a nontypical condition. Therefore, aluminum alloys 6061-T6 and 6061-O are not susceptible 

to SCC. The staff referenced the following two documents to confirm that the alloys are not 

susceptible to SCC:

(1) B.F. Brown, “Stress-Corrosion Cracking in High Strength Steels and in Titanium and 

Aluminum Alloys,” Naval Research Laboratory, 1972

(2) J.R. Davis, “Corrosion of Aluminum and Aluminum Alloys,” ASM International, 1999

The staff reviewed the difference between the LRA AMP and the GALL Report AMP, which 

should have been identified as an exception, and finds it acceptable because it has been 

verified that the materials of construction are aluminum alloy-temper combinations that are not 

susceptible to cracking due to SCC. Therefore, the aspects of the program elements 

associated with the staff-identified difference are not applicable to the in-scope tanks.

Enhancement 1. LRA Section B.2.1.18 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “monitoring and trending” program elements. In 

this enhancement, the applicant stated that visual inspections will be performed on all wetted 

and nonwetted interior surfaces on one of the two cycled condensate storage tanks for loss of 

material within 5 years before the period of extended operation. The LRA also states that if 

volumetric inspections are performed from the outside of the tank, instead of internal visual 

inspections, 25 percent of the tank surface area will be inspected. The LRA further states that if 

degradation is identified, periodic inspections will be conducted on both tanks at a frequency 

established based on the rate of degradation. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M29 and finds it acceptable because, 

when it is implemented, it will ensure that the extent of inspections, frequency of inspections, 

and parameters monitored will be consistent with GALL Report guidance.

Enhancement 2. LRA Section B.2.1.18 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “monitoring and trending” program elements. In 

this enhancement, the applicant stated that visual inspections will be performed on the external 

surfaces of both cycled condensate storage tanks for loss of material each refueling interval. 

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.M29 and finds it acceptable because, when it is implemented, it will 

ensure that the extent of inspections, frequency of inspections, and parameters monitored will 

be consistent with GALL Report guidance.
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Enhancement 3. LRA Section B.2.1.18, as amended by letter dated August 6, 2015, includes 

an enhancement to the “parameters monitored or inspected,” “detection of aging effects,” and 

“monitoring and trending” program elements. In this enhancement, the applicant stated that the 

tank bottoms of both cycled condensate storage tanks will be volumetrically examined for loss of 

material whenever they are drained. The LRA also states that the volumetric examinations of 

the tank bottoms will begin 10 years before the period of extended operation and each 10-year 

period after. The next inspection will cover approximately 20 percent of each tank bottom. The 

LRA states that the 20 percent will comprise the area extending 30 inches in from the shell and 

10 locations outside of the 30-inch band of approximately 1 ft2 in size. The results of this 

inspection will be used to determine the scope and locations of the subsequent inspection in 

accordance with the corrective action program. The staff reviewed this enhancement against 

the corresponding program elements in GALL Report AMP XI.M29 and finds it acceptable 

because, when it is implemented, it will ensure that age-related degradation of the tank bottoms 

is detected before the loss of intended function, as discussed in RAI B.2.1.18-1.

Enhancement 4. LRA Section B.2.1.18, as amended by letter dated August 6, 2015, includes 

an enhancement to the “parameters monitored or inspected” and “detection of aging effects” 

program elements. In this enhancement, the applicant stated that an inspection of the caulking 

at the perimeter of both cycled condensate storage tanks will be performed each refueling cycle. 

The visual inspection of the caulking is supplemented with physical manipulation. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.M29 and finds it acceptable because, when it is implemented, it will ensure that the 

caulking is inspected using methods and frequency consistent with GALL Report guidance.

Based on its audit and review of the applicant’s responses to RAIs B.2.1.18-1 and B.2.1.18-2, 

the staff finds that program elements 1 through 6 for which the applicant claimed consistency 

with the GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M29. The staff also reviewed a difference between the LRA AMP and the GALL Report 

AMP associated with the “parameters monitored or inspected,” “detection of aging effects,” 

“monitoring and trending,” and “acceptance criteria” program elements and dispositioned the 

staff-identified difference as acceptable. In addition, the staff reviewed the enhancements 

associated with the “parameters monitored or inspected,” “detection of aging effects,” 

“monitoring and trending,” and “acceptance criteria” program elements and finds that, when 

implemented, they will ensure that the AMP is adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.18 summarizes operating experience related to the 

Aboveground Metallic Tanks program. Degradation of the caulking at the perimeter of the base 

of the LSCS, Unit 2, cycled condensate storage tank was identified during a routine walkdown in 

October 2012. The LRA states that the operator that observed the degradation entered it into 

the corrective action program and that maintenance personnel repaired that caulk. The LRA 

also states that the LSCS, Unit 1, cycled condensate storage tank experienced leakage in 2010 

and that subsequent inspections revealed that loss of material had resulted in areas of thinning 

on both tank bottoms. Patches have been installed on the bottoms of both cycled condensate 

storage tanks to repair areas that were found to be below nominal thickness.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 
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to this program. The staff identified operating experience for which it determined the need for 

additional clarification that resulted in the issuance of an RAI, as discussed below.

The Aboveground Metallic Tanks program has an enhancement (Enhancement 3) to perform 

volumetric inspections in accordance with LR-ISG-2012-02, Table 4a. During the onsite audit of 

the applicant’s Aboveground Metallic Tanks program, the staff further reviewed operating 

experience associated with the aging of tank bottoms that the applicant cited in the LRA. The 

sufficiency of Enhancement 3 to effectively manage the tank bottoms for loss of material could 

not be determined during the audit. It was unclear to the staff if the extent and locations of the 

volumetric inspections being performed are sufficient to manage loss of material during the 

period of extended operation. By letter dated July 7, 2015, the staff issued RAI B.2.1.18-1, 

requesting that the applicant provide the extent of the volumetric inspections being performed 

and the methodology used to select the inspection location of the tank bottoms.

In its response dated August 6, 2015, the applicant stated that 100 percent of both tank bottoms 

have been inspected and that the inspection revealed that the tank bottom thinning is primarily 

located within 20 inches of the shell. The response also stated that the extent of the inspections 

being performed has been expanded to inspect 100 percent of the tank bottoms within 30 

inches of the shell in addition to 10 random locations elsewhere on the tank bottoms. The 

inspections will include all locations previously found to be susceptible to thinning. The 

inspections will be performed using a volumetric technique to identify locations of potential 

flaws, which will be re-inspected using a discrete UT technique. The response stated that the 

results of the inspection will be entered into the corrective actions program to determine the 

scope of subsequent inspections.

The staff finds the applicant’s response acceptable because the extent of the volumetric 

inspections being performed on the tank bottoms has been expanded and focuses on the 

locations that site-specific operating experience has shown to be most susceptible to loss of 

material. The expanded scope of the inspections will ensure that age-related degradation of the 

tank bottoms is detected before the loss of intended function. The applicant has also revised 

LRA Section A.2.1.18, Section B.2.1.18, Enhancement 3, and Commitment No. 18 to reflect the 

expanded inspections.

Based on its audit, review of the application, and review of the applicant’s response to 

RAI B.2.1.18-1, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and that implementation of the program has resulted in the 

applicant taking corrective actions. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP XI.M29 was 

evaluated.

UFSAR Supplement. LRA Section A.2.1.18, as amended by letter dated August 6, 2015, 

provides the UFSAR supplement for the Aboveground Metallic Tanks program. The staff 

reviewed this UFSAR supplement description of the program against the recommended 

description for this type of program as described in SRP-LR Table 3.0-1, as modified by 

LR-ISG-2012-02, and noted that the visual examination of caulking is not supplemented with 

physical manipulation. The licensing basis for this program for the period of extended operation 

may not be adequate if the applicant does not incorporate this information in its UFSAR 

supplement. By letter dated July 7, 2015, the staff issued RAI B.2.1.18-2, requesting that the 

applicant provide the technical basis used to determine that visual inspection of the caulking at 

the interface of the tank bottom and foundation, without supplemental physical manipulation, is 

adequate to assess the degradation of the caulking during the period of extended operation.
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In its response dated August 6, 2015, the applicant stated that its AMP has been revised to 

include the physical manipulation of caulking. The applicant has also revised LRA 

Section A.2.1.18, Section B.2.1.18, Enhancement 4, and Commitment No. 18 to reflect the 

inclusion of the physical manipulation of caulking.

The staff finds the applicant’s response acceptable because it is consistent with GALL Report 

AMP XI.M29 and SRP-LR Table 3.0-1, as modified by LR-ISG-2012-02. The staff’s concern 

described in B.2.1.18-2 is resolved. The staff also noted that the applicant committed 

(Commitment No. 18) to the implementation of the enhancements. The staff finds that the 

information in the UFSAR supplement, as amended by letter dated August 6, 2015, is an 

adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Aboveground Metallic Tanks 

program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff evaluated a 

staff-identified difference and determined that the AMP, with the staff-identified difference, is 

adequate to manage the applicable aging effects. The staff also reviewed the enhancements 

and confirmed that their implementation before the period of extended operation will make the 

AMP adequate to manage the applicable aging effects. The staff concludes that the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Fuel Oil Chemistry

Summary of Technical Information in the Application. LRA Section B.2.1.19 describes the 

existing Fuel Oil Chemistry program as consistent, with enhancements, with GALL Report 

AMP XI.M30, “Fuel Oil Chemistry.” The LRA states that the Fuel Oil Chemistry program

manages loss of material in piping, tanks, and other components exposed to an environment of 

fuel oil by periodically testing the quality of the fuel oil. The program monitors water, sediments, 

total particulate, and levels of microbiological activity. Additionally, the program periodically 

samples, drains, cleans, and internally inspects tanks for signs of moisture, contaminants, and 

corrosion. A one-time inspection activity will be performed to verify the effectiveness of the Fuel 

Oil Chemistry program.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M30. The staff also reviewed the 

portions of the “preventive actions,” “parameters monitored or inspected,” “detection of aging 

effects,” and “monitoring and trending” program elements associated with enhancements to 

determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B.2.1.19 includes an enhancement to the “parameters monitored 

or inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that the diesel fuel storage tanks will undergo a periodic (quarterly) sampling 

and analysis for water and sediment content, particulate concentration, and levels of 

microbiological organisms. The staff reviewed this enhancement against the corresponding 
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program elements in GALL Report AMP XI.M30 and finds it acceptable because, when it is 

implemented, it will make the applicant’s AMP program consistent with the GALL Report.

Enhancement 2. LRA Section B.2.1.19 includes an enhancement to the “parameters monitored 

or inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that the high pressure core spray (HPCS) diesel fuel storage tanks will undergo 

a periodic (quarterly) sampling and analysis for water and sediment content, particulate 

concentration, and levels of microbiological organisms. The staff reviewed this enhancement

against the corresponding program elements in GALL Report AMP XI.M30 and finds it 

acceptable because, when it is implemented, it will make the applicant’s AMP program 

consistent with the GALL Report.

Enhancement 3. LRA Section B.2.1.19 includes an enhancement to the “parameters monitored 

or inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that the diesel generator day tanks will undergo a periodic (quarterly) sampling 

and analysis for water and sediment content and levels of microbiological organisms. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.M30 and finds it acceptable because, when it is implemented, it will make the 

applicant’s AMP program consistent with the GALL Report.

Enhancement 4. LRA Section B.2.1.19 includes an enhancement to the “parameters monitored 

or inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that the HPCS diesel day tanks will undergo a periodic (quarterly) sampling and 

analysis for water and sediment content and levels of microbiological organisms. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.M30 and finds it acceptable because, when it is implemented, it will make the 

applicant’s AMP program consistent with the GALL Report.

Enhancement 5. LRA Section B.2.1.19 includes an enhancement to the “parameters monitored 

or inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that the diesel fire pump day tanks will undergo a periodic (quarterly) sampling 

and analysis for water and sediment content, particulate concentration, and levels of 

microbiological organisms. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.M30 and finds it acceptable because, when it is 

implemented, it will make the applicant’s AMP program consistent with the GALL Report.

Enhancement 6. LRA Section B.2.1.19 includes an enhancement to the “preventive actions” 

and “detection of aging effects” program elements. In this enhancement, the applicant stated 

that, for the diesel fire pump day tanks, it will perform periodic internal inspections at least once 

during the 10-year period before the period of extended operation and at least once every 

10 years during the period of extended operation. The tanks will be drained and cleaned; the 

internal surfaces visually inspected (if physically possible); and, if evidence of degradation is 

observed during inspections or if visual inspection is not possible, these diesel fuel tanks will be 

volumetrically inspected. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.M30 and finds it acceptable because, when it is 

implemented, it will make the applicant’s AMP program consistent with the GALL Report.

Enhancement 7. LRA Section B.2.1.19 includes an enhancement to the “detection of aging 

effects” program element. The diesel fuel storage tanks, HPCS diesel fuel storage tanks, diesel 

generator day tanks, and HPCS diesel day tanks are currently visually inspected at a 10-year 

frequency. In this enhancement, the applicant stated that the diesel fuel storage tanks, diesel 
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generator day tanks, HPCS diesel fuel storage tanks, and HPCS diesel day tanks will be 

subjected to a volumetric examination if evidence of degradation is observed during visual 

inspection or if visual inspection is not possible. The staff reviewed this enhancement against 

the corresponding program elements in GALL Report AMP XI.M30 and finds it acceptable 

because, when it is implemented, it will make the applicant’s AMP program consistent with the 

GALL Report.

Enhancement 8. LRA Section B.2.1.19 includes an enhancement to the “monitoring and 

trending” program element. In this enhancement, the applicant stated that, for all diesel tanks

within the scope of license renewal, it will perform periodic (quarterly) trending of water and 

sediment content, particulate concentration, and levels of microbiological organisms. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.M30 and finds it acceptable because, when it is implemented, it will make the 

applicant’s AMP program consistent with the GALL Report.

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M30. In addition, the staff reviewed the enhancements 

associated with the “preventive actions,” “parameters monitored or inspected,” “detection of 

aging effects,” and “monitoring and trending” program elements and finds that, when 

implemented, they will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.19 summarizes operating experience related to the 

Fuel Oil Chemistry program. In July 2013 the applicant identified a monthly surveillance 

procedure that lacked direction on reporting and trending. The system manager is responsible 

for reviewing the results of chemistry analyses. However, the procedure does not provide 

guidance to notify the system manager when water is discovered. The monthly surveillance 

procedure was revised to require the initiation of a corrective action program issue report and 

system manager notification upon the discovery of water during the monthly surveillance.

In September 2009, the results of the analysis for new fuel oil for the diesel fuel storage tank 

indicated that the fuel oil passed the water and sediment test but failed the clear and bright 

appearance test. A corrective action program issue report was initiated. Engineering evaluated 

the acceptability of adding the new fuel oil to the storage tank. The water and sediment test 

was determined to be the more rigorous test and would capture the percent volume of water 

that might be seen under the clear and bright appearance test. Based on this, it was concluded 

that the new fuel oil was acceptable for use.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M30 was evaluated.
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UFSAR Supplement. LRA Section A.2.1.19 provides the UFSAR supplement for the Fuel Oil 

Chemistry program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant committed to ongoing implementation of the existing Fuel Oil 

Chemistry program for managing the effects of aging for applicable components during the 

period of extended operation. The staff finds that the information in the UFSAR supplement is 

an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Fuel Oil Chemistry program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent GALL Report AMP XI.M30. In addition, the staff reviewed 

the enhancements and confirmed that their implementation before the period of extended 

operation will make the AMP adequate to manage the applicable aging effects. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Monitoring of Neutron-Absorbing Materials Other Than Boraflex

Summary of Technical Information in the Application. LRA Section B.2.1.27 describes the 

existing Monitoring of Neutron-Absorbing Materials Other Than Boraflex program as consistent, 

with an enhancement, with GALL Report AMP XI.M40, “Monitoring of Neutron-Absorbing 

Materials Other Than Boraflex.” The program is a condition monitoring program that includes 

periodic inspection and analysis of test coupons of the neutron-absorbing material in the spent 

fuel storage racks to determine whether the neutron-absorbing capability of the material has 

degraded in a treated water environment. The program ensures that the 5-percent subcriticality 

margin is maintained by monitoring loss of material, changes in dimension, and loss of 

neutron-absorbing capacity of the material. The LRA states that the neutron-absorbing material 

installed in the LSCS, Unit 1, spent fuel storage racks is Boral. The LSCS, Unit 2, spent fuel 

storage racks use Netco inserts, which consists of a Rio Tinto Alcan composite as the 

neutron-absorbing material.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M40. The staff also reviewed the 

portions of the “monitoring and trending” program element associated with an enhancement to 

determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of this enhancement follows.

Enhancement 1. LRA Section B.2.1.27 includes an enhancement to the “monitoring and 

trending” program element. In this enhancement, the applicant stated that, before the period of

extended operation, it will maintain the test coupon exposure so that it is bounding for the 

neutron-absorbing material in all spent fuel racks by relocating the coupon tree to a different 

spent fuel rack cell location each cycle and by surrounding the coupons with a greater number 

of freshly discharged fuel assemblies than that of any other cell location. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.M40 and 

finds it acceptable because the proposed coupon exposure plan will maintain the coupons as 

leading indicators for potential degradation of the Boral and the Netco inserts in the fuel storage 
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cells. The staff finds that, when this enhancement is implemented, it will make the AMP 

consistent with the recommendations of GALL Report AMP XI.M40.

Operating Experience. LRA Section B.2.1.27 summarizes operating experience related to the 

Monitoring of Neutron-Absorbing Materials Other Than Boraflex program. The applicant 

provided the following operating experience.

In 2004 and 2009, the applicant stated that Boral coupons were removed from the LSCS, Unit 1,

spent fuel pool and analyzed. The results of the post-irradiated coupon surveillance were 

compared to the original pre-irradiated data for evidence of blistering, swelling (bulging), loss of 

material, and decrease in boron-10 areal density to determine whether there has been any loss 

of neutron-absorption capability, and the applicant confirmed that no significant deterioration or 

degradation had occurred.

In 2009 and 2013, the applicant stated that Netco insert coupons for the fast start program were 

removed from the LSCS, Unit 2, spent fuel pool and analyzed. The results of the post-irradiated 

coupon surveillance were compared to the original pre-irradiated data for evidence of blistering, 

swelling (bulging), loss of material, and decrease in boron-10 areal density to determine 

whether there has been any loss of neutron-absorbing capability, and the applicant confirmed 

that no significant deterioration or degradation had occurred.

During the staff’s audit of this program, the applicant indicated that it completed installation of 

the Netco inserts in 2011, which replaced the previously credited Boraflex neutron-absorbing 

material. The applicant performed this action after identifying ongoing degradation of Boraflex. 

Boraflex is no longer credited for neutron absorption in the LSCS, Unit 2, spent fuel pool.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M40 was evaluated.

UFSAR Supplement. LRA Section A.2.1.27 provides the UFSAR supplement for the Monitoring 

of Neutron-Absorbing Materials Other Than Boraflex program. The staff reviewed this UFSAR 

supplement description of the program and noted that it is consistent with the recommended 

description in SRP-LR Table 3.0-1. The staff also noted that the applicant committed to ongoing 

implementation of the existing Monitoring of Neutron-Absorbing Materials Other Than Boraflex 

program for managing the effects of aging for applicable components during the period of 

extended operation. The staff finds that the information in the UFSAR supplement is an 

adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Monitoring of 

Neutron-Absorbing Materials Other Than Boraflex program, the staff determines that those 
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program elements for which the applicant claimed consistency with the GALL Report are 

consistent. In addition, the staff reviewed the enhancement and confirmed that its 

implementation before the period of extended operation will make the AMP adequate to manage 

the applicable aging effects. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Buried and Underground Piping

Summary of Technical Information in the Application. Subsequent to the issuance of the SER 

with open items, the staff issued LR-ISG-2015-01. By letter dated April 13, 2016, the applicant 

revised its Buried and Underground Piping program to address the changes in LR-ISG-2015-01. 

As modified, LRA Section B.2.1.28 describes the existing Buried and Underground Piping 

program as consistent, with enhancements, with GALL Report AMP XI.M41, “Buried and 

Underground Piping and Tanks,” as modified by LR-ISG-2015-01. The LRA states that the 

AMP addresses carbon steel and stainless steel buried and underground piping and piping 

components exposed to soil and outdoor air to manage the effects of cracking and loss of 

material. The LRA also states that the AMP proposes to manage these aging effects through 

periodic visual inspections; preventive and mitigative actions, including coatings, backfill quality, 

and cathodic protection; and periodic verification of the effectiveness of the cathodic protection 

system.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M41, as modified by 

LR-ISG-2011-03.

LRA Section B.2.1.28 states that soil corrosion probes may be used to verify the effectiveness 

of the cathodic protection system during annual surveys. The applicant stated that the probes 

will be placed in close proximity to the piping. The applicant also stated that other 

considerations for placement of the probes include (a) soil moisture content, pH, and resistivity, 

(b) location of anode beds, (c) proximity of the test points in relation to the pipe, nearby anode 

beds, and components with large buried surfaces that can affect cathodic protection readings 

and localized protection, and (d) the effect of cathodic shielding and large current collectors. 

Cathodic protection will be considered effective if less than 1 mil per year (mpy) is detected or if 

a remaining life calculation is performed, which demonstrates that the component intended 

function will be maintained through the period of extended operation. The remaining life option 

will only be used when volumetric thickness measurements were conducted on the pipe when 

the soil corrosion probe was installed. The applicant further stated that NACE International 

Publication 05107, “Report on Corrosion Probes in Soil or Concrete,” will be used during 

installation, use, and application of the results. Input will be used from equipment vendors, 

manufacturers, and individuals with a NACE International CP4, “Cathodic Protection Specialist,” 

qualification in regard to the installation and use of the probes.

The “acceptance criteria” program element of GALL Report AMP XI.M41, as modified by 

LR-ISG-2011-03, recommends either a -850 mV relative to a copper sulfate electrode instant off 

criterion or a 100-mV minimum polarization criterion to assess the effectiveness of a cathodic 

protection system. Although the applicant did not cite an exception for its use of a 1-mpy loss of 
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material as an acceptance criterion to demonstrate effectiveness of the cathodic protection 

system, the staff’s evaluation of the applicant’s proposal follows. The staff noted the following:

• Based on a review of NACE International Publication 05107, soil corrosion probes are 

capable of measuring corrosion rates of the probe by correlating increases in electrical 

resistance to a loss of material of the probe. The rate of corrosion of the probe provides 

a direct indication of the effectiveness of the cathodic protection system in the vicinity of 

the probe.

• NACE International Publication 05107 provides guidance on the installation and use of 

soil corrosion probes, including material type, size of probe, soil contact, proximity to the 

piping that it is representing, circuit configurations, corrosion rate calculation formulas, 

and acceptance criteria. Use of the guidance of this publication in conjunction with 

vendor, manufacturer, and NACE International-qualified cathodic protection expert 

recommendations can result in effectively determining the corrosion rate of buried 

components.

• The 1-mpy acceptance criterion is consistent with NACE International Publication 05107. 

The twofold acceptance criterion (i.e., 1 mpy, remaining life calculation) can be sufficient 

to provide reasonable assurance that either local cathodic protection is effective or 

ineffective, as the case may be.

• NACE offers four levels of qualification consisting of cathodic protection tester, cathodic 

protection technician, cathodic protection technologist, and cathodic protection specialist 

(NACE Courses CP 1 through CP 4). The staff noted that the NACE website (accessed 

on March 19, 2015), http://www.naceinstitute.org/Certification/, states that the NACE 

CP 4 Cathodic Protection Specialist is, “geared toward those persons involved in the 

design, installation, and maintenance of cathodic protection systems.”

The staff noted that the 1 mpy acceptance criterion is a standard industry value used to 

demonstrate an effective cathodic protection system. However, the staff did not find the 

applicant’s proposal acceptable because, in part, the staff lacked sufficient information to 

conclude that there is reasonable assurance that all buried in-scope piping would be capable of 

meeting its CLB intended function with 60 mils of corrosion that could occur through the end of 

the period of extended operation. By letter dated May 29, 2015, the staff issued RAI B.2.1.28-1,

requesting that the applicant state whether all buried in-scope components will be able to 

perform their licensing basis intended function(s) if a 60-mil loss of material were to occur 

through the end of the period of extended operation.

In its response dated June 25, 2015, the applicant stated that the buried in-scope piping is 

“capable of withstanding at least 60 mils of material loss from 87.5 percent of the nominal pipe 

wall thicknesses (manufacturers tolerance), while still maintaining their licensing basis intended 

function.”

The staff finds the applicant’s response acceptable because the applicant confirmed that the 

design tolerances for buried in-scope piping will accommodate the industry standard 1-mpy

acceptance criterion related to the effectiveness of a cathodic protection system. The staff’s 

concern described in RAI B.2.1.28-1 is resolved.

The staff finds the applicant’s proposal to use soil corrosion probes to assess the effectiveness 

of localized adequacy of cathodic protection acceptable because (a) based on industry-wide 

use, soil corrosion probes are capable of providing localized corrosion rates that can be 
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assessed against an acceptance criterion to demonstrate the effectiveness of a cathodic 

protection system, (b) soil corrosion data will be factored into the placement of soil corrosion 

probes, which will result in the probe data not being misleading due to potential soil impacts on 

corrosion rates, (c) the applicant identified appropriate factors to consider for site structure 

impacts (e.g., cathodic shielding and large current collectors), (d) an acceptance criterion of 

1 mpy is an industry-accepted value, and the applicant stated that all of its in-scope buried pipe 

has sufficient margin to accommodate this criterion throughout the period of extended operation, 

(e) as-found wall thickness measurements will be obtained when soil corrosion probes are 

installed, and these measurements will be used to determine a remaining life, thus eliminating 

the need to project corrosion rates that have occurred since installation, (f) NACE International 

Publication 05107 provides appropriate guidance on the installation and use of soil corrosion 

probes, and (g) personnel providing input for the location of soil corrosion probes, and the use 

of soil corrosion probe data, will be appropriately qualified.

The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements associated 

with enhancements to determine whether the program will be adequate to manage the aging 

effects for which it is credited. By letter dated April 13, 2016, the applicant revised 

Enhancement Nos. 3, 4, 6, and 7. The staff’s evaluation of these enhancements and changes 

follows.

Enhancement 1. LRA Section B.2.1.28 includes an enhancement to the “parameters monitored 

or inspected” program element. In this enhancement, the applicant stated that inspections for 

cracking of stainless steel piping will use a method that has been demonstrated to be capable of 

detecting cracking. The applicant also stated that inspections for cracking will only occur when 

coatings have been removed so that the base material is exposed. The staff reviewed this 

enhancement against the corresponding program element in GALL Report AMP XI.M41, as 

modified by LR-ISG-2015-01, and finds it acceptable because, when it is implemented, 

monitoring for cracking in stainless steel components will be consistent with GALL Report 

AMP XI.M41, as modified by LR-ISG-2015-01, in both the selection of inspection methods and 

when inspections for cracking will be conducted.

Enhancement 2. LRA Section B.2.1.28 includes an enhancement to the “preventive actions” 

program element. In this enhancement, the applicant stated that it will “[e]nsure [that] all 

underground carbon steel Essential Cooling Water System and Nonessential Cooling Water 

System piping and components within the scope of license renewal are coated in accordance 

with Table 1 of NACE SP0169-2007.” The staff reviewed this enhancement against the 

corresponding program element in GALL Report AMP XI.M41, as modified by LR-ISG-2015-01, 

and finds it acceptable because, when it is implemented, coating underground piping in 

accordance with Table 1 of NACE International SP0169-2007 is consistent with GALL Report 

AMP XI.M41, as modified by LR-ISG-2015-01, and the coating can ensure that loss of material 

will not occur. The staff noted that, by letter dated April 13, 2015, the applicant stated that, 

“[t]here is no cementitious piping within the scope of license renewal. All buried stainless steel 

piping and components within the scope of license renewal are coated.” The staff concluded 

that coating underground stainless steel piping is consistent with AMP XI.M41 as modified by 

LR-ISG-2015-01.

Enhancement 3. As amended by letter dated April 13, 2016, LRA Section B.2.1.28 includes an 

enhancement to the “acceptance criteria” program element. In this enhancement, the applicant 

stated that it will “[d]efine acceptable coating conditions as coating exhibiting either no evidence 

of degradation, or, the type and extent of coating damage evaluated as insignificant by” an 
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individual qualified by any one of the three methods recommended in AMP XI.M41 as modified 

by LR-ISG-2015-01.

The staff reviewed this enhancement against the corresponding program element in 

GALL Report AMP XI.M41, as modified by LR-ISG-2015-01, and finds it acceptable because,

when it is implemented, it will be consistent with GALL Report AMP XI.M41, as modified by 

LR-ISG-2015-01, and because using individuals with appropriate qualifications can result in 

effective inspections of the condition of coatings.

Enhancement 4. As amended by letter dated April 13, 2016, LRA Section B.2.1.28 includes an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that (a) the number of inspections of in-scope buried piping will be conducted in 

accordance with Table XI.M41-2, “Inspections of Buried and Underground Piping and Tanks,” of 

GALL Report AMP XI.M41, as modified by LR-ISG-2015-01, (b) inspections will be conducted in 

each 10-year period commencing 10 years before the period of extended operation, and 

(c) “[t]he number of inspections of buried piping will be based upon the as-found results of 

cathodic protection system availability and effectiveness.” The applicant also stated that the 

length of piping for each inspection will be based on the recommendations in LR-ISG-2015-01, 

Appendix B, item 4.c (“detection of aging effects” program element). The staff reviewed this 

enhancement against the corresponding program element in GALL Report AMP XI.M41, as 

modified by LR-ISG-2015-01, and finds it acceptable because, when it is implemented, the 

number of inspections of in-scope buried piping and frequency will be consistent with 

GALL Report AMP XI.M41, as modified by LR-ISG-2015-01.

Enhancement 5. LRA Section B.2.1.28 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that it will “[p]erform direct 

visual inspections of underground Essential Cooling Water System and Nonessential Cooling 

Water System piping within the scope of license renewal during each 10-year period, beginning 

10 years prior to the period of extended operation.” The staff reviewed this enhancement 

against the corresponding program element in GALL Report AMP XI.M41, as modified by 

LR-ISG-2015-01, and finds it acceptable because, when it is implemented, the periodicity of 

conducting underground piping inspections will be consistent with GALL Report AMP XI.M41, as 

modified by LR-ISG-2015-01.

Enhancement 6. As amended by letter dated April 13, 2016, LRA Section B.2.1.28 includes an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that:

When measured pipe wall thickness, projected to the end of the period of 

extended operation, does not meet the minimum pipe wall thickness 

requirements, the number of inspections within the affected piping categories will 

be doubled or increased by five (5), whichever is smaller. If adverse indications 

are found in the expanded sample, an analysis will be conducted to determine 

the extent of condition and extent of cause. The size of the followup inspections 

will be determined based on the analysis. Timing of the additional inspections will 

be based on the severity of the identified degradation and the consequences of 

leakage. The additional inspections will be performed within the same 10-year 

inspection interval in which the original degradation was identified, or within 

4-years after the end of the 10-year interval if the degradation was identified in 

the latter half of the 10-year interval. Expansion of sample size may be limited by 
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the extent of piping subject to the observed degradation mechanism or if the 

piping system or portion of the system is replaced.

The staff reviewed this enhancement against the corresponding program element in 

GALL Report AMP XI.M41, as modified by LR-ISG-2015-01, and finds it acceptable because,

when it is implemented, the number of additional inspections when adverse indications are 

detected and the timing of these inspections will be consistent with GALL Report AMP XI.M41, 

as modified by LR-ISG-2015-01.

Enhancement 7. As amended by letter dated April 13, 2016, LRA Section B.2.1.28 includes an 

enhancement to the “acceptance criteria” program element. In this enhancement, the applicant 

stated that it will use either the -850-mV instant off polarized potential criterion specified in 

NACE international SP0169-2007 or the corrosion rate demonstrated by soil corrosion probes to 

determine the effectiveness of the cathodic protection system. The applicant also stated that it 

will establish an upper limit of -1200 mV for pipe-to-soil potential measurements of coated pipes. 

The staff reviewed this enhancement against the corresponding program element in 

GALL Report AMP XI.M41, as modified by LR-ISG-2015-01, and finds it acceptable because,

when it is implemented, the -850-mV instant off criterion, upper limit of -1200 mV, and use of 

soil corrosion probes are consistent with the acceptance criteria in GALL Report AMP XI.M41, 

as modified by LR-ISG-2015-01. The staff’s evaluation of the acceptability of using soil 

corrosion probes is documented above.

Enhancement 8. LRA Section B.2.1.28 includes an enhancement to the “acceptance criteria” 

program element. In this enhancement, the applicant stated that it will “[c]onduct an extent of 

condition evaluation if observed coating damage caused by non-conforming backfill has been 

evaluated as significant. The extent of condition evaluation will be conducted to ensure that the 

as-left condition of backfill in the vicinity of the observed damage will not lead to further 

degradation.” The staff reviewed this enhancement against the corresponding program element

in GALL Report AMP XI.M41, as modified by LR-ISG-2015-01, and finds it acceptable because,

when it is implemented, it will be consistent with the extent of inspections for damage caused to 

coatings by backfill recommendations in GALL Report AMP XI.M41, as modified by 

LR-ISG-2015-01.

Based on its audit and review of the applicant’s response to RAI B.2.1.28-1 and letter dated 

April 13, 2016, the staff finds that program elements 1 through 6 for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.M41, as modified by LR-ISG-2015-01. The staff reviewed the 

enhancement associated with the “preventive actions,” “parameters monitored or inspected,” 

“detection of aging effects,” and “acceptance criteria” program elements and finds that, when 

implemented, they will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.28 summarizes operating experience related to the 

Buried and Underground Piping program. Since January 2009, several segments of piping 

sections have been excavated for inspection in various systems including fire protection, 

condensate, RCIC, diesel oil transfer, and service water. Thirty to 40 guided wave inspections 

have been conducted. Permanent guided wave collars have been typically installed during 

excavations. Soil corrosion probes have also been installed in some locations. During the 

inspection of piping in three excavations conducted in 2011, it was determined that the coating 

was intact and performing well, the backfill quality was excellent, and there was no exposed 

substrate or corrosion of the piping. Since 2009, improvements to the cathodic protection 

system have been performed, including upgrading cathodic protection rectifiers; installing 
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sacrificial anodes on the diesel generator fuel oil lines; conducting two soil samples and soil 

analyses; installing soil access ports to increase the accuracy of acquired data; installing 

several soil corrosion probes near safety-related pipes; installing several reference cells during 

buried pipe excavations to act as test points; and installing a new impressed-current system 

with anodes, rectifiers, and test points at the lake screen house.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M41, as modified by LR-ISG-2015-01, was evaluated.

UFSAR Supplement. As amended by letter dated April 13, 2016, LRA Section A.2.1.28 

provides the UFSAR supplement for the Buried and Underground Piping program. The staff 

reviewed this UFSAR supplement description of the program and noted that it is consistent with 

the recommended description in SRP-LR Table 3.0–1, as modified by LR-ISG-2015-01. The 

staff also noted that the applicant committed to implement the enhancements to the program 

before the period of extended operation and to complete inspections occurring prior to the 

period of extended operation no later than 6 months prior to the period of extended operation, or 

before the end of the last refueling outage prior to the period of extended operation, whichever 

is later. The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Buried and Underground 

Piping program, the staff determines that those program elements for which the applicant 

claimed consistency with AMP XI.M41, as modified by LR-ISG-2015-01, are consistent. The 

staff reviewed the enhancements and confirmed that their implementation before the period of 

extended operation will make the AMP adequate to manage the applicable aging effects. The 

staff concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

ASME Section XI, Subsection IWE

Summary of Technical Information in the Application. LRA Section B.2.1.29 describes the 

existing ASME Section XI, Subsection IWE program as consistent, with enhancements, with 

GALL Report AMP XI.S1, “ASME Section XI, Subsection IWE.” The LRA states that the 

program uses periodic visual and volumetric inspections to manage steel and stainless steel for 

loss of material, loss of preload, loss of leak tightness, and fretting or lockup. The program 

includes uncontrolled indoor air and treated water environments and includes components such 

as the containment liner plate and its integral attachments, downcomers and associated 
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bracing, pressure-retaining bolting for containment closure, containment hatches, and other 

containment pressure-retaining components.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.S1. For the “detection of aging 

effects” program element, the staff determined the need for additional information, which 

resulted in the issuance of an RAI as discussed below.

The “detection of aging effects” program element in GALL Report AMP XI.S1 recommends

surface examination to detect cracking in stainless steel penetration sleeves, dissimilar metal 

welds, bellows, and steel components that are subject to cyclic loading but have no CLB fatigue 

analysis. However, during its audit, the staff found that the applicant’s ASME Section XI, 

Subsection IWE, does not include supplemental surface examinations to detect cracking in 

stainless steel penetration sleeves or dissimilar metal welds. By letter dated June 19, 2015, the 

staff issued RAI B.2.1.29-1, requesting that the applicant state whether it will perform 

supplemental surface examinations and, if not, provide a technical justification for relying on 

visual examination.

In its response dated July 15, 2015, the applicant stated that all penetration sleeve components 

subject to cyclic loading at LSCS have an associated CLB fatigue analysis. The applicant 

further stated that no containment penetration bellows exist at LSCS. Stainless steel 

penetration sleeves and dissimilar metal welds do exist at LSCS; however, the licensee noted 

that these are completely within the Reactor Building and are protected from a corrosive 

environment. Furthermore, the majority of the sleeves are embedded in the containment wall 

and are unavailable for surface examination. The applicant noted that 10 CFR Part 50, 

Appendix J, Type B testing is not possible on many of the mechanical penetration sleeves; 

however, the sleeves are subjected to 10 CFR Part 50, Appendix J, Type A testing.

The staff finds the applicant’s response acceptable because the components have a fatigue 

analysis, the components are contained in a noncorrosive environment that generally precludes 

SCC, the applicant has no plant-specific operating experience with cracking of these 

components, and the components are subjected to 10 CFR Part 50, Appendix J, Type A testing 

and visual inspection under the ASME Section XI, Subsection IWE. Therefore, supplemental 

surface examinations are unnecessary. The staff’s concern described in RAI B.2.1.29-1 is 

resolved.

The staff also reviewed the portions of the “preventive actions,” and “monitoring and trending,” 

program elements associated with enhancements to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

enhancements follows.

Enhancement 1. LRA Section B.2.1.29 includes an enhancement to the “preventive actions”

program element. In this enhancement, the applicant stated that guidance will be provided for 

proper specification for bolting material, lubricant and sealants, and installation torque to help 

mitigate degradation of structural bolting. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.S1 and finds it acceptable because 

when it is implemented it will align the applicant’s AMP with the guidance provided in the 

GALL Report AMP regarding proper selection of bolting materials.
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Enhancement 2. LRA Section B.2.1.29 includes an enhancement to the “monitoring and 

trending” program element. In this enhancement, the applicant stated that UT thickness 

measurements will be performed on the Unit 2 drywell liner at 0 and 180 degrees for several 

feet below elevation 813 feet, if leakage is detected from the reactor cavity pool drain line welds. 

The staff reviewed this enhancement and finds it acceptable because when it is implemented it 

will provide an acceptable method (UT thickness measurements) for detecting degradation of 

the liner due to leakage from the reactor cavity pool drain lines. The operating experience 

associated with this enhancement is discussed further in the operating experience section 

below.

Based on its audit, and review of the applicant’s response to RAI B.2.1.29-1, the staff finds that 

program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.S1. In addition, the staff reviewed the enhancements associated with the “preventive 

actions,” and “monitoring and trending,” program elements and finds that, when implemented, 

they will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.29 summarizes operating experience related to the 

ASME Section XI, Subsection IWE program. A summary description of relevant operating 

experience that demonstrates that the inspections conducted under the program have been 

able to identify aging effects that are entered and evaluated in the corrective action program is 

provided below.

The LRA noted that, in 2006, two indications of corrosion were noted on the LSCS, Unit 1, 

drywell liner. This condition was entered into the corrective action program, and an engineering 

evaluation found the areas acceptable. In 2008, the areas were reinspected, including UT 

thickness measurements, with no changes identified. It was concluded that the areas were 

inactive and most likely resulted from initial construction.

The LRA also noted that, in 2010, a number of uncoated areas in the LSCS, Unit 1, drywell liner 

were found with light corrosion. The condition was entered into the corrective action program 

and found acceptable. However, the areas were coated to reduce future corrosion. The LRA 

noted that these examples demonstrate that the ASME Section XI, Subsection IWE program is 

effective in identifying degradation before loss of intended function.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

The staff identified operating experience for which it determined the need for additional 

clarification, which resulted in the issuance of an RAI, as discussed below.

The LRA discusses leakage from the LSCS, Unit 2, reactor cavity pool drain line welds at the 

interface with the cavity pool liner, which has been observed as seepage through the 

surrounding concrete. As discussed in the Audit Report, the NRC staff reviewed an action 

request during the audit that identified indications of reactor cavity leakage in a different location 

from where it has been historically identified. By letter dated June 19, 2015, the staff issued 

RAI B.2.1.29-2, requesting that the applicant explain how the existing AMP and associated 
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enhancement are adequate to address the new operating experience and why the proposed UT 

locations will be adequate.

In its response dated July 15, 2015, the applicant noted that the new leakage is at 

elevation 823 ft, approximately 9 ft above the previously identified source and above the primary 

containment drywell; therefore, it is unlikely to contact the containment drywell liner. In addition, 

the leakage is on the outside face of the concrete surrounding the reactor cavity pool liner, 

which is further away from the primary containment. The applicant noted that, even if water 

were to reach the drywell, industry operating experience indicates that corrosion will not occur 

because of the lack of oxygen in the region and because of the passivating effect on the 

leakage resulting from its passing through the highly alkaline 6-ft thick concrete wall. The 

applicant noted that the UT measurements were to confirm this fact and that measurements in 

1999, 2005, and 2015 confirm that no loss of material has occurred. Furthermore, 

ASME Section XI, Subsection IWL inspections have been conducted on the surrounding 

concrete and no indications of concrete or reinforcing steel have been identified. The applicant 

further stated that the existing locations are the appropriate locations for UT measurements 

because they are along the same azimuth as the new leakage and at the thinnest location of the 

liner with the limiting thickness for detecting loss of material due to corrosion.

The staff notes that there are two possible concerns when addressing leakage near the primary 

containment. One concern is the possible impact of the leakage on the liner, and the other is 

the possible impact of the leakage on the surrounding concrete. The staff reviewed the 

applicant’s response and noted that the applicant is addressing the possible impact on the liner 

by taking UT measurements at the most susceptible locations of the liner. The applicant is 

addressing the possible impact on the concrete by conducting the appropriate GALL Report 

recommended inspections. Neither of these inspections (the UT examinations or the concrete 

visual examinations) have identified indications of degradation. The staff finds the applicant’s 

response acceptable because the applicant is conducting appropriate inspections that can 

identify degradation of the liner and the surrounding concrete. The staff’s concern described in 

RAI B.2.1.29-2 is resolved.

Based on its audit and review of the application and review of the applicant’s response to 

RAI B.2.1.29-2, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and that implementation of the program has resulted in the 

applicant taking corrective actions. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP XI.S1 was 

evaluated.

UFSAR Supplement. LRA Section A.2.1.29 provides the UFSAR supplement for the ASME 

Section XI, Subsection IWE program. The staff reviewed this UFSAR supplement description of 

the program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff also noted that the applicant committed to implement the enhancements 

to the program before the period of extended operation (Commitment No. 29). The staff finds 

that the information in the UFSAR supplement is an adequate summary description of the 

program.

Conclusion. On the basis of its audit and review of the applicant’s ASME Section XI, 

Subsection IWE program, the staff determines that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. In addition, the staff 

reviewed the enhancements and confirmed that their implementation before the period of 

extended operation will make the AMP adequate to manage the applicable aging effects. The 
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staff concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

ASME Section XI, Subsection IWL

Summary of Technical Information in the Application. LRA Section B.2.1.30 describes the 

existing ASME Section XI, Subsection IWL program as consistent, with enhancements, with 

GALL Report AMP XI.S2, “ASME Section XI, Subsection IWL.” The LRA states that the AMP 

manages reinforced concrete and the unbonded post-tensioning system associated with the 

primary containment. The program uses general visual inspections to identify loss of material, 

cracking, and loss of bond of concrete. The LRA also notes that post-tensioning tendons are 

examined in accordance with the requirements of ASME Section XI, Subsection IWL.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.S2. The staff also reviewed the 

portions of the “acceptance criteria” program element associated with the enhancements to 

determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B.2.1.30 includes an enhancement to the “acceptance criteria” 

program element. In this enhancement, the applicant stated that areas of concrete deterioration 

and distress will be recorded in accordance with the guidance provided in American Concrete 

Institute (ACI) 349.3R, “Evaluation of Existing Nuclear Safety-Related Concrete Structures,” 

dated June 2002. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.S2 and finds it acceptable because, when it is implemented, it 

will align the applicant’s program with the guidance in the GALL Report, which recommends 

using the guidance in ACI 349.3R for identification of concrete degradation.

Enhancement 2. LRA Section B.2.1.30 includes an enhancement to the “acceptance criteria” 

program element. In this enhancement, the applicant stated that quantitative acceptance 

criteria based on the “Evaluation Criteria” in Chapter 5 of ACI 349.3R will be used to augment 

the qualitative assessment of the Responsible Engineer. The staff reviewed this enhancement 

against the corresponding program elements in GALL Report AMP XI.S2 and finds it acceptable 

because, when it is implemented, it will align the applicant’s program with the guidance in the 

GALL Report, which recommends augmenting the qualitative assessment with quantitative 

acceptance criteria based on the guidance in ACI 349.3R.

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.S2. In addition, the staff reviewed the enhancements 

associated with the “acceptance criteria” program element and finds that, when implemented, 

they will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.30 summarizes operating experience related to the 

ASME Section XI, Subsection IWL program. The LRA discusses a 2003 inspection that 

identified failed wires in an LSCS, Unit 1, vertical containment tendon. Additional inspections 

were done on LSCS, Units 1 and 2, to determine the extent of condition. A total of 12 additional 
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tendons were found do have broken wires or internal corrosion and were replaced. The 

associated root cause determined that a poor upper grease cap design was allowing water into 

the tendons. A revised design with improved gaskets was installed on all of the susceptible 

vertical tendons, and subsequent inspections have demonstrated that the corrective actions 

were effective. The LRA also summarized the results of the recent concrete surface 

examinations for both containments. Conditions consistent with the baseline inspections were 

observed and determined to be minor with no structural significance or impact. A horizontal 

crack width measurement was different than previously identified, and it was reviewed and 

determined to be acceptable. These examples demonstrate that the existing program is 

effectively detecting and managing aging of the concrete containments.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The Audit Report notes that the staff was considering issuing an RAI related to 

reactor cavity leakage; however, after further consideration, the staff determined an RAI was 

unnecessary. As discussed in LRA Section B.2.1.29, “ASME Section XI, Subsection IWE,” the 

cavity leakage is minor and only occurs during RFOs. Although the leakage does migrate 

through containment concrete, no degradation of the concrete has been detected to date, and 

the visual inspections in the applicant’s existing ASME Section XI, Subsection IWL program are 

adequate to monitor any future impacts of the leakage on the containment concrete. The 

impact of the leakage on the steel containment liner is addressed in the staff’s review of the 

ASME Section XI, Subsection IWE program (SER Section 3.0.3.2.15).

As noted above, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.S2 was evaluated.

UFSAR Supplement. LRA Section A.2.1.30 provides the UFSAR supplement for the ASME 

Section XI, Subsection IWL program. The staff reviewed this UFSAR supplement description of 

the program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff also noted that the applicant committed to implement the enhancements 

to the program before the period of extended operation. The staff finds that the information in 

the UFSAR supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s ASME Section XI, 

Subsection IWL program, the staff determines that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. In addition, the staff 

reviewed the enhancements and confirmed that their implementation before the period of 

extended operation will make the AMP adequate to manage the applicable aging effects. The 

staff concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 
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UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

ASME Section XI, Subsection IWF

Summary of Technical Information in the Application. LRA Section B.2.1.31 describes the

existing ASME Section XI, Subsection IWF program, with enhancements, as consistent with 

GALL Report AMP XI.S3, “ASME Section XI, Subsection IWF.” The LRA states that the AMP 

addresses ASME Class 1, 2, 3, and MC piping and component support members exposed to

air-indoor uncontrolled and treated water environments to manage the aging effects of loss of 

material, loss of mechanical function, and loss of preload. The LRA also states that the AMP 

proposes to manage these aging effects through periodic visual inspections to detect signs of 

degradation before loss of intended function. The LRA further states that bolting for supports is 

also included with these components and examined for loss of material and loss of preload by 

inspecting for missing, detached, or loosened bolts and nuts. Indications of degradation are 

entered in the corrective action program for evaluation or correction to ensure the intended 

function of the component support is maintained.

The LRA states that the program is based on the ASME Code Section XI, Subsection IWF, with 

edition and addenda and associated conditions determined for each inspection interval in 

accordance with 10 CFR 50.55a(g)(4); accordingly, the current program complies with the 2001 

edition with 2003 addenda of ASME Code Section XI.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.S3. For the “preventive actions” 

program element, the staff determined the need for additional information, which resulted in the 

issuance of an RAI, as discussed below.

The “preventive action” program element in GALL Report AMP XI.S3 recommends use of 

bolting material that has an actual measured yield strength less than 150 ksi or 1,034 MPa, 

intended as a preventive measure against the potential for SCC. The staff noted that the 

“preventive actions” program element of LRA AMP B.2.1.31 included Enhancement 1 

(Commitment No. 31, item 1) in order to become consistent with the corresponding 

GALL Report program element. However, during the audit, the staff found that Section 3.2,

“Preventive Actions,” in the LRA AMP program basis document states that high strength bolting 

(actual measured yield strength greater than or equal to 150 ksi or 1,034 MPa) in sizes greater 

than 1-inch nominal diameter are not used in LSCS IWF supports. The staff also noted that, on 

the basis of the previous statement, the “detection of aging effects” program element in 

Section 3.4 of the applicant’s program basis document does not include the supplemental 

volumetric examination recommended in the “detection of aging effects” program element of the 

GALL Report AMP to detect cracking due to SCC, specifically for high strength bolting (actual 

measured yield strength greater than or equal to 150 ksi or 1,034 MPa) in sizes greater than 

1-inch nominal diameter. From its wording, it was not clear to the staff whether Enhancement 1 

(Commitment No. 31, item 1) is consistent with the “preventive action” program element of the 

GALL Report AMP XI.S3 with regard to the recommendation related to the use of bolting 

material that has an actual measured yield strength less than 150 ksi or 1,034 MPa. 

Specifically, because the enhancement does not prevent future use of high strength bolting 

material (actual measured yield strength greater than or equal to 150 ksi or 1,034 MPa) in sizes 

greater than 1-inch nominal diameter that is susceptible to SCC and because the LRA AMP has 

no provisions for recommended supplemental volumetric examination of such bolting material, 
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this aspect of the “preventive action” program element of the LRA AMP did not appear to be

consistent with the GALL Report AMP.

By letter dated June 19, 2015, the staff issued RAI B.2.1.31-1, requesting that the applicant 

clarify how the proposed enhancement (Commitment No. 31, item 1) to the “preventive action” 

program element of LRA Section B.2.1.31, “ASME Section XI, Subsection IWF,” is consistent 

with the corresponding program element recommendation of the GALL Report AMP XI.S3, 

specifically with regard to the future use of high strength bolting (actual measured yield strength 

greater than or equal to 150 ksi or 1,034 MPa) in sizes greater than a 1-inch nominal diameter 

for IWF supports, considering that such bolting is susceptible to SCC and that the LRA AMP has 

no provisions for recommended supplemental volumetric examination to detect cracking if used 

in the future. Alternatively, the applicant was requested to provide the basis to justify the 

adequacy of the proposed exception to manage aging effects on high strength bolting (actual 

measured yield strength greater than or equal to 150 ksi) in sizes greater than a 1-inch nominal 

diameter for IWF supports if criteria other than that described in the GALL Report are being 

used.

In its response dated July 15, 2015, to RAI B.2.1.31-1, the applicant stated that LRA 

Enhancement 1 related to preventive actions for bolting associated with IWF supports is revised 

to preclude the potential for future use of high strength bolts due to consideration of SCC 

vulnerability by appending the enhancement with the following statement: “Bolting material with 

actual measured yield strength greater than or equal to 150 ksi or 1,034 MPa, in sizes greater 

than a 1-inch nominal diameter shall not be used in supports for ASME Code Class 1, 2, and 3 

piping and components or supports for MC components.” The applicant stated that this revision 

to the enhancement makes the “preventive actions” program element of the LRA AMP 

consistent with that of the GALL Report AMP XI.S3; therefore no exception is taken to the 

GALL Report AMP. Accordingly, the applicant revised LRA Sections A.2.1.31, B.2.1.31, and 

Commitment No. 31 in LRA Section A.5 to incorporate the above revised wording into the 

enhancement.

The staff finds the applicant’s response acceptable because the applicant’s revised 

enhancement prevents the future use of high strength bolts (actual measured yield strength 

greater than or equal to 150 ksi or 1,034 MPa) in sizes greater than a 1-inch nominal diameter 

for IWF supports, thereby precluding the vulnerability of IWF support bolts to SCC, consistent 

with the recommendations of the GALL Report. The staff’s concern described in RAI B.2.1.31-1 

is resolved.

The staff also reviewed the portions of the “preventive actions” and “monitoring and trending” 

program elements associated with enhancements to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

enhancements follow.

Enhancement 1. LRA Section B.2.1.31, as amended by the applicant’s letter dated 

July 15, 2015, in response to RAI B.2.1.31-1, includes an enhancement to the “preventive 

actions” program element. In this enhancement (Commitment No. 31, item 1), the applicant 

stated that before the period of extended operation, the program will be enhanced to “[p]rovide 

guidance for proper specification of bolting material, storage, lubricant and sealants, and 

installation torque or tension to prevent or mitigate degradation and failure of structural bolting. 

Requirements for high strength bolts shall include the preventive actions for storage, lubricants,

and SCC potential discussed in Section 2 of RCSC (Research Council on Structural 

Connections) publication, ‘Specification for Structural Joints Using ASTM A325 or A490 Bolts.’ 
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Lubricants that contain molybdenum disulfide (MoS2) shall not be applied to high strength bolts 

within the scope of license renewal. Bolting material with actual measured yield strength 

greater than or equal to 150 ksi or 1,034 MPa, in sizes greater than 1 inch nominal diameter 

shall not be used in supports for ASME Class 1, 2, and 3 piping and components or supports for 

[Class] MC components.” The staff reviewed this enhancement against the corresponding 

program element in the GALL Report AMP XI.S3 and finds it acceptable because, when it is 

implemented, it will make the LRA AMP program element consistent with the recommendations 

in the GALL Report AMP by ensuring that proper specifications for structural bolting are used

with regard to material, storage, lubricants, and installation to prevent or mitigate degradation 

and failure and to preclude susceptibility to SCC.

Enhancement 2. LRA Section B.2.1.31 includes an enhancement to the “monitoring and 

trending” program element. In this enhancement (Commitment No. 31, item 2), the applicant 

stated that before the period of extended operation it will “[p]rovide guidance, regarding the 

selection of supports to be inspected on subsequent inspections, when a support is repaired in 

accordance with the corrective action program. The enhanced guidance will ensure that the 

supports inspected on subsequent inspections are representative of the general population.” 

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.S3 and finds it acceptable because, when it is implemented, it will ensure 

that the inspection sample will adequately represent the age-related degradation of the IWF 

component population when components that are part of the sample are reworked or repaired 

and no longer represent the age-related degradation of the remaining population.

Based on its audit and review of the applicant’s response to RAI B.2.1.31-1, the staff finds that 

program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.S3. In addition, the staff reviewed the enhancements associated with the “preventive 

action” and “monitoring and trending” program elements and finds that, when implemented, they 

will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.31 summarizes operating experience related to the 

ASME Section XI, Subsection IWF program. A summary description of examples of operating 

experience that provide objective evidence that the ASME Section XI, Subsection IWF program 

will be effective in ensuring that intended functions are maintained consistent with the CLB for 

the period of extended operation is given below.

In 2013 during the ASME Section XI, Subsection IWF inservice inspection of an LSCS, Unit 2, 

ASME Code Class 1 rigid seismic restraint, a loose pipe clamp bolt was identified. A corrective 

action program issue report was initiated. The loose bolting was corrected, and required scope 

expansion examinations were performed on three additional supports in accordance with ASME 

Code Section XI, IWF-2430. During the ISI sample expansion examinations, a loose bolt was 

found on another pipe support. The loose bolting was corrected, and the examination scope 

was again expanded to include 11 additional supports in accordance with ASME Code 

Section XI, IWF-2430. During the ISI sample expansion examinations, another loose bolt was 

found on another pipe support. The loose bolting was corrected, and the examination scope 

was expanded in accordance with ASME Code Section XI, IWF-2430 (c), to the remaining 

supports on that pipe line, which are potentially subject to the same condition. The loose bolting 

identified would not have prevented the supports from performing their intended function. 

However, the scope of examinations was expanded to determine the extent of condition, and 

the loose bolting conditions identified were corrected. This example demonstrates that 
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conditions, such as loose bolting, are identified and corrected and that additional supports are 

examined as required for similar conditions.

In 2012 during the ASME Section XI, Subsection IWF inservice inspection of an LSCS, Unit 1, 

ASME Code Class 1 feedwater pipe restraint, a loose pipe clamp bolt was identified. A 

corrective action program issue report was initiated. The loose bolting was corrected, and the 

required scope expansion examinations were performed in accordance with ASME Code 

Section XI, IWF-2430. Additional recordable indications were identified, and additional sample 

expansions were conducted so that every Class 1 support on the A and B feedwater lines were 

examined. This example demonstrates that conditions, such as loose bolting, are identified and 

corrected and that additional supports are examined as required for similar conditions. The 

inspection methods that the program implements have been proven effective in detecting aging 

effects, including loss of material, loss of mechanical function, and loss of preload. Appropriate 

guidance for evaluation, repair, or replacement is provided for locations where degradation is 

found. Problems identified, such as loose fasteners or loose lock nuts, would not cause 

significant impact to the safe operation of the plant, and adequate corrective actions were taken 

to address these conditions. Periodic self-assessments of the ASME Section XI, 

Subsection IWF program are performed to identify the areas that need improvement to maintain 

the quality performance of the program. The program is informed and enhanced when 

necessary through the systematic and ongoing review of both plant-specific and industry 

operating experience. Therefore, there is confidence that implementation of the ASME 

Section XI, Subsection IWF program will effectively identify degradation before failure or loss of 

intended function during the period of extended operation.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.S3 was evaluated.

UFSAR Supplement. LRA Section A.2.1.31 provides the UFSAR supplement for the 

ASME Section XI, Subsection IWF program. The staff reviewed this UFSAR supplement

description of the program and noted that it is consistent with the recommended description in 

SRP-LR Table 3.0-1. The staff also noted that the applicant committed to implement the 

enhancements to the program before the period of extended operation. The staff finds that the 

information in the UFSAR supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s ASME Section XI, 

Subsection IWF program, as amended by the applicant’s letter dated July 15, 2015, the staff 

determined that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. In addition, the staff reviewed the enhancements and confirmed 

that their implementation before the period of extended operation will make the AMP adequate 

to manage the applicable aging effects. The staff concludes that the applicant has 
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demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Masonry Walls

Summary of Technical Information in the Application. LRA Section B.2.1.33 describes the 

existing Masonry Walls program as consistent, with enhancements, with GALL Report 

AMP XI.S5, “Masonry Walls.” The LRA states that the Masonry Walls program is a condition 

monitoring program implemented as part of the Structures Monitoring program and is based on 

the guidance provided in Inspection and Enforcement (IE) Bulletin 80-11, “Masonry Wall 

Design,” dated May 8, 1980, and NRC IN 87-67, “Lessons Learned from Regional Inspections 

of Licensee Actions in Response to IE Bulletin 80-11,” dated December 31, 1987. The LRA 

also states that the program relies on periodic visual inspections of masonry walls exposed to 

air-indoor (uncontrolled) and air-outdoor environments on an interval not to exceed 5 years to 

monitor and maintain the condition of the walls so that the established design basis remains 

valid. The program inspects for loss of material and cracking and will be enhanced to inspect 

for separation and for gaps between the supports and masonry walls that could impact the 

intended function of the walls. The LRA further states that conditions found to be acceptable 

with deficiencies or that are deemed unacceptable are evaluated and/or corrected by 

repair/replacement in the corrective action program. Masonry walls that are considered fire 

barriers are also managed by the Fire Protection program, which is evaluated in SER 

Section 3.0.3.2.9.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.S5. For the “parameters 

monitored or inspected” and “acceptance criteria” program elements, the staff determined the 

need for additional information, which resulted in the issuance of an RAI, as discussed below.

The “parameters monitored or inspected” and “acceptance criteria” program elements in 

GALL Report AMP XI.S5 recommends that the primary parameters monitored are potential 

shrinkage and/or separation and cracking of masonry walls and gaps between the supports and

masonry walls that could impact the intended function or potentially invalidate its evaluation 

basis. However, during its audit, the staff found that Enhancement 1 (Commitment No. 33, 

item 1) to the applicant’s Masonry Wall program states that, before the period of extended 

operation, the program will be revised to “provide guidance for inspection of masonry walls for 

separation, and for gaps between the supports for masonry walls.” In this regard, the critical 

parameter intended to be monitored, as evaluated in the GALL Report AMP, are gaps between 

the masonry walls and component supports (i.e., supports for safety-related systems or 

components that are located in close proximity to, or have attachments to, the walls, or edge 

supports that establish boundary conditions used in the design analysis of the walls) to ensure 

that intended function and/or evaluation basis of the masonry wall is not adversely impacted. 

This is different from the parameter described as “gaps between supports for masonry walls” in 

the LRA AMP enhancement.

By NRC letter dated June 19, 2015, the staff issued RAI B.2.1.33-1, requesting that the 

applicant clarify how the enhancement for the “parameters monitored or inspected” and 

“acceptance criteria” program elements is consistent with that described in the GALL Report 
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AMP XI.S5 with regard to monitoring for gaps between supports and masonry walls and, if 

parameters or criteria different than that described in the GALL Report are being used, provide 

the basis to justify the adequacy of the proposed exception to manage the aging effects to 

masonry walls.

In its response dated July 15, 2015, the applicant stated that Enhancement 1, associated with 

Commitment No. 33, is revised for the wording to be consistent with the GALL Report 

AMP XI.S5 “parameters monitored or inspected” and “acceptance criteria” program elements. 

The applicant also stated that the above revision is consistent with the GALL Report AMP XI.S5 

and that no exception to the GALL Report is required.

The staff finds the applicant’s response acceptable because the revised wording for the 

program enhancement is consistent with the GALL Report recommended parameters monitored 

or inspected and acceptance criteria for shrinkage and/or separation and cracking of masonry 

walls and gaps between the supports and masonry walls. The staff’s concern described in 

RAI B.2.1.33-1 is resolved.

The staff also reviewed the portions of the “parameters monitored or inspected,” “detection of 

aging effects,” and “acceptance criteria” program elements associated with enhancements to 

determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B.2.1.33, as amended by the response dated July 15, 2015, to 

RAI B.2.1.33-1, includes an enhancement to the “parameters monitored or inspected” and 

“acceptance criteria” program elements. In this enhancement (Commitment No. 33, item 1), the 

applicant stated that, before the period of extended operation, the program procedures will be 

revised to “provide guidance for inspection of masonry walls for separation and gaps between 

the supports and masonry walls.” The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.S5 and finds it acceptable because,

when it is implemented, it will make the program consistent with the GALL Report 

recommended parameters monitored or inspected and acceptance criteria for shrinkage and/or 

separation and cracking of masonry walls and gaps between the supports and masonry walls 

that could impact the intended function or potentially invalidate its evaluation basis.

Enhancement 2. LRA Section B.2.1.33 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement (Commitment No. 33, item 2), the applicant 

stated that, before the period of extended operation, the program procedures will be revised to 

“require that personnel performing inspections and evaluations meet the qualifications described 

in ACI 349.3R.” As observed in the Audit Report, the applicant’s program basis document for 

Structures Monitoring lists the 2002 version of ACI 349.3R. Because the Masonry Walls 

program is implemented as part of the Structures Monitoring program, this enhancement to the 

Masonry Walls program, related to personnel qualifications, will be based on the 2002 version of 

ACI 349.3R, which is consistent with the version of ACI 349.3R referenced in the GALL Report 

AMP XI.S6. The staff reviewed this enhancement against the corresponding program elements 

in GALL Report AMP XI.S5 and finds it acceptable because, when it is implemented, it will 

ensure personnel performing visual inspections of masonry walls meet the qualification 

requirements described in ACI 349.3R as recommended by the GALL Report.

Based on its audit and review of the applicant’s response to RAI B.2.1.33-1, the staff finds that 

program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 
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AMP XI.S5. In addition, the staff reviewed the enhancements associated with the “parameters 

monitored or inspected,” “detection of aging effects,” and “acceptance criteria” program 

elements and finds that, when implemented, they will make the AMP adequate to manage the 

applicable aging effects.

Operating Experience. LRA Section B.2.1.33 summarizes operating experience related to the 

Masonry Walls program. A summary description of relevant operating experience that 

demonstrates that inspections similar to those conducted under the program have been able to 

identify aging effects, which are entered and evaluated in the corrective action program to 

determine appropriate corrective actions, is provided below.

A 2004 walkdown of plant structures, including masonry walls, following a recorded seismic 

event, identified minor cracking and loose mortar on removable block walls in the turbine 

building. The walkdown results were documented and subjected to an engineering evaluation 

within the corrective action program. The mortar joints were repaired, and the engineering 

evaluation found the minor cracking along the joints of the removable block walls to be 

acceptable.

During a 2011 walkdown of fire barriers, a small localized area of missing mortar was identified 

on a joint between two concrete blocks located on the east masonry wall of the auxiliary 

equipment room. The condition was documented in the corrective action program, and an 

engineering evaluation of the condition determined that it did not affect the design function of 

the masonry wall nor the ability of the wall to maintain its function as a fire barrier; therefore, 

repair was not required.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.S5 was evaluated.

UFSAR Supplement. LRA Section A.2.1.33, as revised by the applicant’s letter dated 

July 15, 2015, provides the UFSAR supplement for the Masonry Walls program. The staff 

reviewed this UFSAR supplement description of the program and noted that it is consistent with 

the recommended description in SRP-LR Table 3.0-1. The staff also noted that the applicant 

committed to implement the enhancements to the Masonry Walls program before the period of 

extended operation. The staff finds that the information in the UFSAR supplement, as amended 

by letter dated July 15, 2015, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Masonry Walls program, as 

revised by its letter dated July 15, 2015, the staff determined that those program elements for 

which the applicant claimed consistency with the GALL Report are consistent. The staff 

reviewed the enhancements and confirmed that their implementation before the period of 
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extended operation will make the AMP adequate to manage the applicable aging effects. The 

staff concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concluded that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Structures Monitoring

Summary of Technical Information in the Application. LRA Section B.2.1.34 describes the 

existing Structures Monitoring program as consistent, with enhancements, with GALL Report 

AMP XI.S6, “Structures Monitoring.” The LRA states that the Structures Monitoring program 

was developed to implement the requirements of 10 CFR 50.65, “Requirements for Monitoring 

the Effectiveness of Maintenance at Nuclear Power Plants,” and is based on guidance in 

RG 1.160, “Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,” Revision 2, 

dated March 1997, and NUMARC 93-01, “Industry Guideline for Monitoring the Effectiveness of 

Maintenance at Nuclear Power Plants,” Revision 2, dated April 1996. The AMP includes

elements of the Masonry Wall program (LRA Section B.2.1.33) and the RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants program (LRA 

Section B.2.1.35). The staff’s evaluations of these AMPs are documented in SER 

Sections 3.0.3.2.18 and 3.0.3.2.20, respectively.

The LRA states that concrete structures are inspected for indications of deterioration and 

distress, including evidence of leaching, loss of material, cracking, and a loss of bond, and steel 

components are inspected for loss of material due to corrosion. Environments include 

air-outdoor, air-indoor uncontrolled, treated water, raw water, water-flowing, and groundwater 

and soil. The LRA also states that the AMP proposes to manage these aging effects through

periodic inspection and monitoring of the condition of structures and structural component 

supports to ensure that aging degradation leading to loss of intended functions will be detected 

and that the extent of degradation can be determined. The LRA further states that inspections 

are performed on a frequency not to exceed 5 years with provisions for more frequent 

inspections when conditions are observed to have a potential impact in its intended function. 

The AMP includes provisions for periodic sampling and testing of groundwater on a 5-year 

frequency to ensure the groundwater remains nonaggressive.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.S6. For the “parameters 

monitored or inspected,” “detection of aging effects,” and “acceptance criteria” program 

elements, the staff determined the need for additional information, which resulted in the 

issuance of RAIs, as discussed below.

The “detection of aging effects” program element in GALL Report AMP XI.S6 recommends that 

plants with nonaggressive groundwater/soil environment (a) evaluate the acceptability of 

inaccessible areas when conditions exist in accessible areas that could indicate the presence 

of, or result in, degradation to such inaccessible areas and (b) examine representative samples 

of the exposed portions of the below-grade concrete when excavated for any reason. However, 

during its audit, the staff found that Enhancement 7, applicable to the “detection of aging effects” 

program element, of the applicant’s Structures Monitoring program only addresses item b above

of the GALL Report recommendations. By letter dated June 19, 2015, the staff issued 

RAI B.2.1.34-1, requesting that the applicant clarify how the enhancement for the program 
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element is consistent with that described in the GALL Report AMP XI.S6 and, if criteria other 

than that described in the GALL Report are being used, provide the basis to justify the 

adequacy of the proposed exception to manage the aging effects in inaccessible areas.

In its response dated July 15, 2015, the applicant stated that LRA Enhancement 7, associated 

with Commitment No. 34, is revised to include the requirement that an evaluation needs to be 

performed for inaccessible concrete surfaces when accessible concrete areas show signs of 

aging degradation. The applicant also stated that the revision to this enhancement is consistent 

with the criteria for the “detection of aging effects” program element in GALL Report AMP XI.S6; 

therefore, no exception is required.

The staff finds the applicant’s response acceptable because the revised LRA Enhancement 7, 

associated with Commitment No. 34, is consistent with the GALL Report AMP XI.S6

recommendations for “detection of aging effects” in plants with a nonaggressive 

groundwater/soil environment. The staff’s concern described in RAI B.2.1.34-1 is resolved.

The “parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria” 

program elements in GALL Report AMP XI.S6 does not provide recommendations for managing 

the aging effects of plant-specific components. During its audit, the staff noted that the 

applicant’s Structures Monitoring program is enhanced to include “permanent drywell shielding” 

as a plant-specific component within the scope of the AMP. However, the staff found that no 

enhancement(s) to the applicable program elements was provided to ensure that the aging 

effects associated with “fiberglass blanket covers for permanent drywell shielding” is adequately 

managed during the period of extended operation. The staff also found an inconsistency 

between the aging effect described as being managed by the associated LRA Table 3.5.2-7 

AMR results item (LRA page 3.5-160) and the aging effect identified in the corresponding 

plant-specific note 3 (“change in material properties” versus “rips and tears”). By letter dated 

June 19, 2015, the staff issued RAI B.2.1.34-2, requesting that the applicant explain how the 

enhancement to the “scope of program” program element is adequate to manage aging effects 

for “permanent drywell shielding” without providing a corresponding enhancement(s) to other 

applicable program elements or provide the necessary enhancement, as needed, to adequately 

manage the applicable aging effects of the plant-specific component. The staff’s RAI also 

requested that the applicant describe the aging effect(s) and aging mechanism that will be 

managed by the AMP for the permanent drywell shielding fiberglass blanket covers and clarify 

the inconsistency between the aging effect described in the LRA Table 3.5.2-7 AMR results item 

and the corresponding plant-specific note 3.

In its response dated July 15, 2015, the applicant stated that LRA Enhancement 10, associated 

with Commitment No. 34, is added to the LRA to ensure that the fiberglass blanket covers 

associated with permanent drywell shielding are properly managed during the period of 

extended operation by the Structures Monitoring program. The applicant also stated that the 

aging effect identified in LRA Table 3.5.2-7, change in material properties due to irradiation and 

thermal exposure, was selected to align with an appropriate GALL Report aging effect and AMR 

results and that the plant-specific note was used to define “rips and tears” as the type of change 

in material properties that is associated with the fiberglass blankets that will be managed by the 

Structures Monitoring program. The applicant further stated that the Structures Monitoring 

program is enhanced to inspect for signs of rips and tears for these fiberglass blanket covers 

and that, if a rip or tear is found, the permanent drywell shielding will be repaired or replaced.

The staff finds the applicant’s response acceptable because the applicant added LRA 

Enhancement 10 that will provide the necessary parameters to the “parameters monitored or 
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inspected,” “detection of aging effects,” and “acceptance criteria” program elements of the LRA 

AMP to ensure that the aging effects for permanent drywell shielding are adequately managed 

during the period of extended operation. The applicant also clarified the inconsistency between 

the aging effect described in LRA Table 3.5.2-7 AMR results item and the corresponding 

plant-specific note 3. The staff’s concern described in RAI B.2.1.34-2 is resolved.

The staff also reviewed the portions of the “scope of program,” “preventive actions,” “parameters 

monitored or inspected,” “detection of aging effects,” and “acceptance criteria” program 

elements associated with enhancements to determine whether the program will be adequate to 

manage the aging effects for which it is credited. The staff’s evaluation of these enhancements 

follows.

Enhancement 1. LRA Section B.2.1.34 includes an enhancement to the “scope of program” 

program element. In this enhancement, the applicant stated that the AMP will be enhanced to 

include the monitoring of the following components and commodities:

• pipe, electrical, and equipment component support members

• pipe whip restraints and jet impingement shields

• panels, racks, cabinets, and other enclosures

• sliding surfaces

• sumps

• electrical cable trays and conduits

• electrical duct banks

• tube tracks

• transmission tower (including takeoff towers) and foundation (including cycled 

condensate storage tank foundations)

• penetration seals and sleeves

• blowout panels

• permanent drywell shielding

• transformer foundation

• bearing pads

• compressible joints

• hatches, plugs, handholes, and manholes

• metal components (decking, vent stack, and miscellaneous steel)

• building features – doors and seals, bird screens, louvers, windows, and siding

• concrete curbs and anchors

• Turbine Building smoke and heat vent housings

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.S6 and finds it acceptable because, when it is implemented, it will 

address additional site structures within the scope of license renewal that are not covered by 

other structural AMPs. This enhancement makes the applicant’s “scope of program” program 
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element consistent with the recommendations provided in GALL Report AMP XI.S6 in that it will 

help monitor and assess the impact of age-related degradation on these structures and will 

provide assurance that the aging degradation can be detected and quantified before there is a 

loss of intended functions.

Enhancement 2. LRA Section B.2.1.34 includes an enhancement to the “preventive actions” 

program element. In this enhancement, the applicant stated that the AMP will be enhanced to 

provide guidance for proper specification of bolting material, lubricant and sealants, and 

installation torque or tension to prevent or mitigate degradation and failure of structural bolting. 

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.S6 and finds it acceptable because, when it is implemented, it will provide 

preventive actions as delineated in NUREG-1339 and other industry standards as 

recommended by the GALL Report to ensure bolting integrity.

Enhancement 3. LRA Section B.2.1.34 includes an enhancement to the “preventive actions” 

program element. In this enhancement, the applicant stated that the AMP’s storage 

requirements for high strength bolts will be revised to include recommendations in Section 2 of 

Research Council on Structural Connections (RCSC), “Specification for Structural Joints Using 

American Society for Testing and Materials (ASTM) A325 or A490 Bolts.” The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP XI.S6 and 

finds it acceptable because, when it is implemented, it will include preventive actions from 

industry guidelines for storage of ASTM A325 and ASTM A490 structural bolts as recommended 

by the GALL Report to ensure bolting integrity.

Enhancement 4. LRA Section B.2.1.34 includes an enhancement to the “acceptance criteria” 

program element. In this enhancement, the applicant stated that the AMP will be enhanced to 

require acceptance and evaluation of structural concrete using quantitative criteria based on 

Chapter 5 of ACI 349.3R. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.S6 and finds it acceptable because, when it is 

implemented, it will provide quantitative acceptance criteria using industry standards that allow 

the determination for adequacy of observed aging effects and will specify further evaluation 

criteria to determine the need for corrective actions based on the industry guidelines as 

recommended by the GALL Report.

Enhancement 5. LRA Section B.2.1.34 includes an enhancement to the “parameters monitored 

or inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that the AMP will be enhanced to monitor raw water and groundwater chemistry 

on a frequency not to exceed 5 years for pH, chlorides, and sulfates and to verify that it remains

nonaggressive or to evaluate results exceeding criteria to assess impact, if any, on below-grade 

concrete. The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.S6 and finds it acceptable because, when it is implemented, it will allow 

the applicant to assess the impact of the groundwater on below-grade concrete structures by 

monitoring the groundwater chemistry. This enhancement makes the applicant’s “parameters 

monitored or inspected” and “detection of aging effects” program elements consistent with the 

recommendations provided in GALL Report AMP XI.S6.

Enhancement 6. LRA Section B.2.1.34 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “acceptance criteria” program elements. In this 

enhancement, the applicant stated that the AMP will be enhanced to monitor concrete for 

increase in porosity and permeability and to inspect accessible sliding surfaces for indication of 

significant loss of material due to wear or corrosion, debris, or dirt. The staff reviewed this 
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enhancement against the corresponding program elements in GALL Report AMP XI.S6 and 

finds it acceptable because, when it is implemented, it will allow detection of deterioration that 

could impact the intended function of the concrete structures and accessible sliding surfaces. 

This enhancement makes the applicant’s “parameters monitored or inspected,” “detection of 

aging effects,” and “acceptance criteria” program elements consistent with the 

recommendations provided in GALL Report AMP XI.S6.

Enhancement 7. LRA Section B.2.1.34, as amended by the applicant’s response letter dated 

July 15, 2015, to RAI B.2.1.34-1, includes an enhancement to the “detection of aging effects” 

program element. In this enhancement, the applicant stated that the program will be enhanced 

to “evaluate the acceptability of inaccessible areas when conditions exist in accessible areas 

that could indicate the presence of, or result in, degradation to such inaccessible areas, and 

examine representative samples of the exposed portions of the below-grade concrete, when 

excavated for any reason.” The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.S6 and finds it acceptable because, when it is 

implemented, it will be able to provide detection of aging effects for inaccessible concrete 

structural elements in a manner consistent with the GALL Report recommendations for plants 

with a nonaggressive groundwater/soil environment.

Enhancement 8. LRA Section B.2.1.34 includes an enhancement to the “acceptance criteria” 

program element. In this enhancement, the applicant stated that personnel performing 

inspections and evaluations will be required to meet the qualifications specified within 

ACI 349.3R with respect to knowledge of inservice inspection of concrete and visual acuity 

requirements. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.S6 and finds it acceptable because, when it is implemented, it 

will ensure that inspections and evaluations are performed by personnel that meet the 

qualification requirements of ACI 349.3R, as recommended by the GALL Report.

Enhancement 9. LRA Section B.2.1.34 includes an enhancement to the “acceptance criteria” 

program element. In this enhancement, the applicant stated that the AMP will be clarified to 

indicate that loose bolts and nuts and cracked high strength bolts are not acceptable unless 

accepted by engineering evaluations. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.S6 and finds it acceptable because, 

when it is implemented, it will require an engineering evaluation for the acceptance of loose 

bolts and nuts and cracked high strength bolts, as recommended by the GALL Report.

Enhancement 10. LRA Section B.2.1.34, as amended by the applicant’s response letter dated 

July 15, 2015, to RAI B.2.1.34-2, includes enhancements to the “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements. In this 

enhancement, the applicant stated that the AMP will be enhanced to do the following: “Inspect 

the fiberglass outer covering for the permanent drywell shielding for signs of rips and tears. If a 

rip or tear is found, repair or replace the permanent drywell shielding.” The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.S6 and 

notes that fiberglass blanket covers from shielding components are plant-specific components 

that are not addressed by the GALL Report recommendations. However, the staff finds this 

enhancement acceptable because, when it is implemented, it will ensure that the AMP has the 

necessary parameters to be inspected, a procedure for the detection of aging effects, and 

acceptance criteria associated with plant-specific components to ensure that their intended 

function is maintained during the period of extended operation.
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Based on its audit and review of the applicant’s response(s) to RAIs B.2.1.34-1 and B.2.1.34-2,

the staff finds that program elements 1 through 6 for which the applicant claimed consistency 

with the GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.S6. In addition, the staff reviewed the enhancements associated with the “scope of 

program,” “preventive actions,” “parameters monitored or inspected,” “detection of aging 

effects,” and “acceptance criteria” program elements and finds that, when implemented, they will 

make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.34 summarizes operating experience related to the 

Structures Monitoring program. A summary description of relevant operating experience that 

demonstrates that the inspections similar to those conducted under the program have been able 

to identify aging effects, which are entered and evaluated in the corrective action program to 

determine appropriate corrective actions, is provided below.

In 2010, inspection of the reactor building structural steel identified connections that were not in 

accordance with design requirements; a clip angle at one connection was separated from the 

column web, and another connection contained three loose bolts. The applicant entered both 

identified conditions into its corrective action program for evaluation and corrected the gap 

between the clip and beam on the column. The bolted connection was tightened in accordance 

with design requirements.

In 2010, a fire door was found with a loose bottom seal during a Structures Monitoring program 

walkdown. The applicant entered the identified condition into their corrective action program for 

evaluation and corrected the condition by retightening the loose door seal.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.S6 was evaluated.

UFSAR Supplement. LRA Section A.2.1.34, as amended by the applicant’s response letter 

dated July 15, 2015, to RAIs B.2.1.34-1 and B.2.1.34-2, provides the UFSAR supplement for the 

Structures Monitoring program. The staff reviewed this UFSAR supplement description of the 

program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff also noted that the applicant committed to implement the enhancements 

to the Structures Monitoring program before the period of extended operation. The staff finds 

that the information in the UFSAR supplement, as amended by letter dated July 15, 2015, is an 

adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Structures Monitoring 

program, as amended by the applicant’s letter dated July 15, 2015, the staff determined that 

those program elements for which the applicant claimed consistency with the GALL Report are 
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consistent. The staff reviewed the enhancements and confirmed that their implementation 

before the period of extended operation will make the AMP adequate to manage the applicable 

aging effects. The staff concludes that the applicant has demonstrated that the effects of aging 

will be adequately managed so that the intended function(s) will be maintained consistent with 

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d).

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants

Summary of Technical Information in the Application. LRA Section B.2.1.35 describes the 

existing RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power

Plants program, as consistent, with enhancements, with GALL Report AMP XI.S7, “RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants.” The LRA states 

that the AMP is implemented as part of the Structures Monitoring program (LRA 

Section B.2.1.34) and is consistent with the guidance provided in RG 1.127, “Inspection of 

Water-Control Structures Associated with Nuclear Power Plants,” Revision 1, dated 

March 1978.

The LRA also states that the AMP addresses age-related degradation, degradation due to 

extreme environmental conditions, and the effects of natural phenomena that may affect the 

safety function of the water-control structures. The LRA further states that aging effects are 

managed through periodic visual inspections and surveillance programs to detect degradation 

and to take corrective actions to prevent the loss of their intended function. The program 

monitors structural components and commodities like reinforced concrete, bolting and structural 

steel, steel components (hatches/plugs), trash bar racks, sheet piling, shad net components, 

and earthen sides structures of the intake flume canal to manage the aging effects loss of 

material, loss of preload, cracking, increase in porosity and permeability, loss of strength, loss of 

material (spalling and scaling), and loss of form. Environments include air-indoor uncontrolled, 

air-outdoor, raw water, water-standing, water-flowing, groundwater, and soil.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.S7. For the “scope of program” 

program element, the staff determined the need for additional information, which resulted in the 

issuance of an RAI, as discussed below.

The “scope of program” program element in GALL Report AMP XI.S7 recommends including in 

the scope of the program those concrete structures, structural steel, structural bolting, and other 

raw water-control structures associated with emergency cooling water systems or flood 

protection of nuclear power plants. However, during its audit, the staff found that the applicant’s 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

program enhances the scope of the AMP to include “shad net anchors” without clearly 

identifying the different materials and components associated with the structure (i.e., the steel 

anchor elements and the concrete piers) and the different aging effects and parameters that 

must be monitored or inspected to ensure that their intended function(s) is maintained during 

the period of extended operation. By NRC letter dated June 19, 2015, the staff issued 

RAI B.2.1.35-1, requesting that the applicant clarify how the enhancement to the “scope of 

program” program element is consistent with that described in the GALL Report AMP XI.S7 to 

ensure that the aging effects of in-scope components are being adequately managed, describe 
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the different materials and components associated with the “shad net anchors,” and describe

the differences in the parameters to be monitored or inspected considering the different 

materials (e.g., steel and concrete) or components associated with “shad net anchors.”

In its response dated July 15, 2015, the applicant stated that Enhancement 1 in LRA 

Section B.2.1.35, associated with Commitment No. 35, will ensure monitoring and inspection of 

the different materials because the galvanized steel “concrete embedment” are covered under 

item 1.c of the enhancement and because the “concrete shad net anchors” are addressed under 

item 1.d of the enhancement. The applicant also stated that the concrete shad net anchors will 

be managed by the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear 

Power Plants program and the Structures Monitoring Program and that the galvanized steel 

concrete embedments will be managed by the Structures Monitoring Program. The applicant 

further stated that the reinforced concrete walls used to secure the shad net across the cooling 

lake intake flume are identified as “shad net anchors” on LSCS documentation; therefore, the 

same nomenclature was used in the LRA. The applicant clarified that these reinforced concrete 

walls have galvanized steel embedments in the concrete used as attachment points to secure 

the shad net. The concrete shad net anchors are included in LRA Table 3.5.2-3 (LRA 

page 3.5-105) as component type “Concrete: Shad Net Anchors”; the galvanized steel concrete 

embedments are included in LRA Table 3.5.2-3 (LRA page 3.5–103) as component type 

“Concrete Embedments.”

The staff finds the applicant’s response acceptable because the applicant clarified that the 

concrete and steel components of the shad net anchors were already included in the 

enhancement and LRA Table 3.5.2-3 and that the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants program and the Structures Monitoring 

Program will adequately manage the aging effects for the galvanized steel and concrete 

materials associated with the “shad net anchors,” as recommended in the GALL Report. The 

staff’s concern described in RAI B.2.1.35-1 is resolved.

The staff also reviewed the portions of the “scope of program,” “preventive actions,” “parameters 

monitored or inspected,” “detection of aging effects,” and “acceptance criteria” program 

elements associated with enhancements to determine whether the program will be adequate to 

manage the aging effects for which it is credited. The staff’s evaluation of these enhancements 

follows.

Enhancement 1. LRA Section B.2.1.35 includes an enhancement to the “scope of program” 

program element. In this enhancement, the applicant stated that the AMP will be enhanced to 

include the monitoring of the following SCs:

• Submerged Core Standby Cooling System Pond and Intake Flume

• Core Standby Cooling System outfall structure

• Bar racks and miscellaneous steel

• Shad net anchors

• Lake Screen House (includes service water tunnel)

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.S7 and finds it acceptable because, when it is implemented, it will include 

additional structures, structural components, component supports, and structural commodities 

related to water-control structures associated with emergency cooling water systems or flood 

protection of nuclear power plants that are within the scope of license renewal. This 

enhancement makes the applicant’s “scope of program” program element consistent with the 
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recommendations provided in GALL Report AMP XI.S7 in that it will help monitor and assess 

the impact of age-related degradation on these water-control structures and structural 

components and will provide assurance that the aging degradation can be detected and 

quantified before there is a loss of intended functions.

Enhancement 2. LRA Section B.2.1.35 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that the AMP will be 

enhanced to monitor raw water and groundwater chemistry for pH, chlorides, and sulfates at 

least once every 5 years, and to verify that it remains nonaggressive or evaluate results 

exceeding criteria to assess impact, if any, on buried or submerged concrete. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.S7 and finds it acceptable because, when it is implemented, it will allow the applicant to 

assess the impact of the groundwater on below-grade concrete of water-control structures by 

monitoring the groundwater chemistry. This enhancement makes the applicant’s “detection of 

aging effects” program element consistent with the recommendations provided in GALL Report 

AMP XI.S7.

Enhancement 3. LRA Section B.2.1.35 includes an enhancement to the “preventive actions” 

program element. In this enhancement, the applicant stated that the AMP will be enhanced to 

provide guidance for proper specification of bolting material, lubricant and sealants, and 

installation torque or tension to prevent or mitigate degradation and failure of structural bolting 

and to provide preventative actions for storage of materials to prevent SCC. The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP XI.S7 and 

finds it acceptable because, when it is implemented, it will provide preventive actions as 

delineated in NUREG-1339 and other industry standards, as recommended by the GALL Report 

to ensure bolting integrity.

Enhancement 4. LRA Section B.2.1.35 includes an enhancement to the “parameters monitored 

or inspected” and “acceptance criteria” program elements. In this enhancement, the applicant 

stated that the AMP will be enhanced to require acceptance and evaluation of structural 

concrete using quantitative criteria based on Chapter 5 of ACI 349.3R. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.S7 and 

finds it acceptable because, when it is implemented, it will provide quantitative acceptance 

criteria using industry standards that allow the determination for adequacy of observed aging 

effects and will specify further evaluation criteria to determine the need for corrective actions 

based on the industry guidelines, as recommended by the GALL Report.

Enhancement 5. LRA Section B.2.1.35 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that the AMP will be 

enhanced to require the inspection of accessible in-scope portions of the cooling lake and lake 

screen house immediately following the occurrence of significant natural phenomena, which 

include intense local rainfalls and large floods. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.S7 and finds it acceptable because,

when it is implemented, it will be consistent with the GALL Report recommendation to address 

degradation due to extreme environmental conditions and the effects of natural phenomena that 

may affect water control structures.

Enhancement 6. LRA Section B.2.1.35 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that the AMP will be 

enhanced to require (a) the evaluation of the acceptability of inaccessible areas when conditions 

exist in the accessible areas that could indicate the presence of, or result in, degradation to 
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such inaccessible areas and (b) the examination of the exposed portions of the below-grade 

concrete when excavated for any reason. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.S7 and finds it acceptable because,

when it is implemented, it will be able to provide detection of aging effects for inaccessible 

concrete structural elements in a manner consistent with the GALL Report recommendations for 

plants with nonaggressive groundwater/soil.

Based on its audit and review of the applicant’s response to RAI B.2.1.35-1, the staff finds that 

program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.S7. In addition, the staff reviewed the enhancements associated with “scope of 

program,” “preventive actions,” “parameters monitored or inspected,” “detection of aging 

effects,” and “acceptance criteria” program elements and finds that, when implemented, they will 

make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.35 summarizes operating experience related to the 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

program. A summary description of relevant operating experience that demonstrates that the 

inspections, similar to those conducted under the program, have been able to identify aging 

effects, which are entered and evaluated in the corrective action program to determine 

appropriate corrective actions, is provided below.

In 2009, inspections of the service water tunnel in the lake screen house identified spalling 

concrete on the floor of the service water tunnel, which exposed reinforcing steel. This 

condition was entered into the applicant’s corrective action program for evaluation. The 

engineering evaluation concluded that immediate repairs were not necessary and that the 

degradation should be monitored during subsequent inspections until repaired. Subsequent 

inspections has not identified any further degradation of these components.

In 2009, chemical analysis of the lake water determined that pH levels of the lake water had 

dropped below the administrative water chemistry guidelines. This condition was corrected by 

readjusting the water chemistry to restore the pH to a level greater than 8.8.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.S7 was evaluated.

UFSAR Supplement. LRA Section A.2.1.35 provides the UFSAR supplement for the RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants program. The 

staff reviewed this UFSAR supplement description of the program and noted that it is consistent 

with the recommended description in SRP-LR Table 3.0-1. The staff also noted that the 
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applicant committed to implement the enhancements to the program before the period of 

extended operation. The staff finds that the information in the UFSAR supplement is an 

adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants program, the staff determines 

that those program elements for which the applicant claimed consistency with the GALL Report 

are consistent. The staff reviewed the enhancements and confirmed that their implementation 

before the period of extended operation will make the AMP adequate to manage the applicable 

aging effects. The staff concluded that the applicant has demonstrated that the effects of aging 

will be adequately managed so that the intended function(s) will be maintained consistent with 

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d).

Metal Enclosed Bus

Summary of Technical Information in the Application. LRA Section B.2.1.40 describes the 

existing Metal Enclosed Bus program as consistent, with enhancements, with GALL Report 

AMP XI.E4, “Metal Enclosed Bus.” The LRA states that the AMP is an existing condition 

monitoring program that will be enhanced to manage the identified aging effects of in-scope 

metal enclosed bus (MEB). The LRA will inspect MEB metallic components, including MEB 

bolted connections, insulators and supports, and the internal and external surfaces of the MEB 

enclosure assembly exposed to air-outdoor and air-indoor controlled or uncontrolled 

environments. The MEB aging effects identified by the applicant are stated to include 

hardening, loss of strength, increased resistance of connection, reduced insulation resistance, 

and loss of material. The LRA also states that the AMP proposes to manage these aging 

effects through the condition monitoring actions that include the following:

• External surfaces are visually inspected for loss of material due to general, pitting, and 

crevice corrosion.

• Accessible enclosure assembly elastomers are visually inspected for surface cracking, 

crazing, scuffing, dimensional change, shrinkage, discoloration, hardening, and loss of 

strength.

• Accessible internal bus insulating supports are visually inspected for structural integrity 

and signs of cracks.

• A sample of accessible bolted connections is inspected for increased resistance of 

connection by thermography imaging or by measuring the connection resistance using a 

micro-ohmmeter.

The LRA states that plant operating experience provides objective evidence that the program 

will be effective in ensuring that intended functions are maintained consistent with the CLB for 

the period of extended operation.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.E4.

The staff also reviewed the portions of the “parameters monitored or inspected,” “detection of 

aging effects,” and “acceptance criteria” program elements associated with enhancements to 
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determine whether the program will be adequate to manage the aging effects for which it is

credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B.2.1.40 includes an enhancement to the “parameters monitored 

or inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that internal inspections will be performed for accessible nonsegregated bus 

duct sections that are in scope for license renewal. The staff reviewed this enhancement 

against the corresponding program elements in GALL Report AMP XI.E4 and finds it acceptable 

because, when it is implemented, it will specify that in-scope MEB portions are covered under 

this AMP.

Enhancement 2. LRA Section B.2.1.40 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “acceptance criteria” program elements. In this 

enhancement, the applicant stated that the requirement for visual inspections of internal 

portions (bus enclosure assemblies), bus insulation, internal bus insulating supports, accessible 

gaskets, boots and sealants, and bus duct external surfaces will be clarified. The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP XI.E4 and 

finds it acceptable because, when it is implemented, it will include visual inspection guidance for 

various MEB elements consistent with the GALL Report.

Enhancement 3. LRA Section B.2.1.40 includes an enhancement to the “detection of aging 

effects” and “acceptance criteria” program elements. In this enhancement, the applicant stated 

that the existing program will be enhanced to specify that a sample size of 20 percent of the 

accessible bolted connection population, with a maximum sample size of 25, will be inspected 

for increased resistance of connection by either thermography or by measuring the connection

resistance using a micro-ohmmeter. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.E4 and finds it acceptable because,

when it is implemented, it will specify the sample size for testing of accessible bolted 

connections consistent with the GALL Report.

Enhancement 4. LRA Section B.2.1.40 includes an enhancement to the “detection of aging 

effects” and “acceptance criteria” program elements. In this enhancement, the applicant stated 

that an inspection frequency of at least every 10 years will be specified. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.E4 and 

finds it acceptable because, when it is implemented, it will specify the inspection frequency 

consistent with the GALL Report.

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.E4. In addition, the staff reviewed the enhancements

associated with the “parameters monitored or inspected,” “detection of aging effects,” and 

“acceptance criteria” program elements and finds that, when implemented, they will make the 

AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.40 summarizes operating experience related to the 

Metal Enclosed Bus program. The LRA cites that, in October 2008 during the inspection of an 

isophase bus duct, a damaged insulator was discovered. The broken insulator was repaired 

under the applicant’s corrective action program. Subsequent to this event, a similar failure was 

noted at another Exelon plant. As a result, the applicant implemented a hi-pot testing frequency 

of every 6 years for isophase and nonsegregated bus ducts. In another example, the LRA 

describes an event in November 2009 when Significant Event Report 5-09 was issued at 
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another plant for a failure of a 6.9-kV nonsegregated bus. Although the applicant had not 

experienced a similar failure with the MEB, additional hi-pot testing and torque checks were 

added to the program. The applicant stated that these examples demonstrate that the program 

has been able to identify aging effects and that corrective actions were taken under the program 

to prevent the recurrence of component failures.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.E4 was evaluated.

UFSAR Supplement. LRA Section A.2.1.40 provides the UFSAR supplement for the Metal 

Enclosed Bus program. The staff reviewed this UFSAR supplement description of the program 

and noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The 

staff also noted that the applicant committed (Commitment No. 40) to enhance the existing 

Metal Enclosed Bus program before the period of extended operation for managing the effects 

of aging for applicable components during the period of extended operation. The staff finds that 

the information in the UFSAR supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Metal Enclosed Bus program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. In addition, the staff reviewed the enhancements and 

confirmed that their implementation before the period of extended operation will make the AMP 

adequate to manage the applicable aging effects. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Fatigue Monitoring

Summary of Technical Information in the Application. LRA Section B.3.1.1 describes the 

existing Fatigue Monitoring program as consistent, with enhancements, with GALL Report 

AMP X.M1, “Fatigue Monitoring.” The LRA states that the AMP manages fatigue damage of 

reactor coolant pressure boundary and other components subject to the reactor coolant, treated 

water, steam, and air-indoor uncontrolled environments. The Fatigue Monitoring program 

monitors and tracks the number of critical thermal, pressure, and seismic transients to ensure 

that the cumulative usage factor for each analyzed component does not exceed the design limit 

of 1.0 through the period of extended operation. The program accomplishes this by 

(a) comparing the actual event parameters to the applicable design transient definitions to 

ensure the actual transients are bounded by the design transients, (b) counting the operational 
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transients to ensure that the cumulative number of occurrences of each transient type is 

maintained below the most limiting cycle limit, and (c) considering the effects of the reactor 

coolant environment on fatigue life of Class 1 components that contact reactor coolant.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP X.M1. The staff also reviewed the 

portions of the “scope of program,” “preventive actions,” “parameters monitored or inspected,” 

and “acceptance criteria” program elements associated with enhancements to determine 

whether the program will be adequate to manage the aging effects for which it is credited. The 

staff’s evaluation of these follows.

Enhancement 1. LRA Section B.3.1.1 includes an enhancement to the “scope of program,” 

“preventive actions,” “parameters monitored or inspected,” and “acceptance criteria” program 

elements. In this enhancement, the applicant stated that it will impose administrative transient 

cycle limits corresponding to the limiting numbers of cycles used in the environmental fatigue 

calculations.

The “scope of program” program element of GALL Report AMP X.M1 states that the program 

monitors and tracks the number of critical thermal and pressure transients and ensures that the 

fatigue usage will remain within the allowable limit. The “preventative actions” program element 

of GALL Report AMP X.M1 states that the program prevents the fatigue analyses from 

becoming invalid by ensuring that the fatigue usage resulting from actual operational transients 

does not exceed the Code design limit of 1.0, including environmental effects where applicable. 

The “parameters monitored or inspected” program element of GALL Report AMP X.M1 states 

that the program monitors all plant design transients that cause cyclic strains and that are 

significant contributors to the fatigue usage factor. The “acceptance criteria” program element 

of GALL Report AMP X.M1 states that the program maintains the cumulative fatigue usage 

below the design limit through the period of extended operation, with consideration of the 

reactor water environmental fatigue effects. As discussed in LRA Section 4.3.3, the applicant 

evaluated the effects of the reactor water environment on the fatigue life of Class 1 components 

that contact reactor coolant. The LRA states that if more limiting cycle limits are identified 

during its environmental fatigue analyses than the current cycle limits used in its 40-year design 

analyses, the enhanced program will apply the more limiting cycle limits for the applicable 

transients. The program will apply corrective actions to prevent the cumulative number of 

occurrences of each transient from exceeding the cycle limits.

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP X.M1 and finds it acceptable because, when implemented, the applicant will 

(a) conservatively apply the most limiting cycle limits for the thermal and pressure transients that 

significantly contribute to the fatigue usage factor and (b) ensure, through monitoring, tracking, 

and applying corrective actions, that the fatigue usage will remain within the allowable limit 

through the period of extended operation. When the enhancement is implemented, the 

applicant’s program will be consistent with the recommendations of the GALL Report, as 

described above.

Enhancement 2. LRA Section B.3.1.1 includes an enhancement to the “preventive actions,” 

“parameters monitored or inspected,” and “acceptance criteria” program elements. In this 

enhancement, the applicant stated that the impact of the reactor coolant environment will be 

evaluated on Class 1 components, including valves and pumps if they are more limiting than 
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those considered in NUREG/CR-6260, “Application of NUREG/CR-5999 Interim Fatigue Curves 

to Selected Nuclear Power Plant Components,” dated February 1995.

The “preventative actions” program element of GALL Report AMP X.M1 states that the program 

prevents the fatigue analyses from becoming invalid by ensuring that the fatigue usage resulting 

from actual operational transients does not exceed the Code design limit of 1.0, including 

environmental effects where applicable. The “parameters monitored or inspected” program 

element of GALL Report AMP X.M1 states that the program monitors all plant design transients 

that cause cyclic strains and that are significant contributors to the fatigue usage factor. The 

“acceptance criteria” program element of GALL Report AMP X.M1 states that the program 

maintains the cumulative fatigue usage below the design limit through the period of extended 

operation, with consideration of the reactor water environmental fatigue effects. LRA 

Section 4.3.3 provides the applicant’s TLAA for evaluating the effects of the reactor water 

environment on the fatigue life of Class 1 components that contact reactor coolant. As part of 

its evaluation, the applicant will identify any component locations that are determined to be more 

limiting than those listed in NUREG/CR-6260 for the plant type and vintage.

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP X.M1 and finds it acceptable because, when implemented, the program will 

consider the effects of the reactor coolant environment for the locations identified in 

NUREG/CR-6260 and any additional plant-specific locations that are determined to be more 

limiting. When the enhancement is implemented, the applicant’s program will be consistent with 

the recommendations of the GALL Report, as described above.

Operating Experience. LRA Section B.3.1.1 summarizes operating experience related to the 

Fatigue Monitoring program. The LRA includes examples of operating experience that provide 

objective evidence that the Fatigue Monitoring program will be effective in identifying 

degradation before loss of intended function through the period of extended operation. The 

applicant stated that these examples show that the Fatigue Monitoring program (a) effectively 

monitors and trends the conditions that impact the fatigue life of plant components and (b) is 

informed and enhanced when necessary through systematic and ongoing review of both 

plant-specific and industry operating experience.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP X.M1 was evaluated.

UFSAR Supplement. LRA Section A.3.1.1 provides the UFSAR supplement for the Fatigue 

Monitoring program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant committed to ongoing implementation of the existing Fatigue 
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Monitoring program for managing the effects of aging for applicable components during the 

period of extended operation. The staff finds that the information in the UFSAR supplement is 

an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Fatigue Monitoring program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. In addition, the staff reviewed the enhancements and 

confirmed that their implementation before the period of extended operation will make the AMP 

adequate to manage the applicable aging effects. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Concrete Containment Tendon Prestress

Summary of Technical Information in the Application. LRA Section B.3.1.2 describes the 

existing Concrete Containment Tendon Prestress program, with an enhancement, as consistent 

with GALL Report AMP X.S1, “Concrete Containment Tendon Prestress.” The LRA states that 

the AMP addresses carbon steel tendons of the containment prestressing system exposed to an 

air-indoor uncontrolled environment to manage the effects of loss of containment tendon 

prestressing forces. The LRA also states that the AMP proposes to manage this aging effect by 

conducting periodic measurements of prestressing forces on a control tendon and a randomly 

selected sample of tendons for each tendon group used (i.e., vertical and horizontal (hoop) 

tendon types) and by assessing them against acceptance criteria (predicted lower limit (PLL) 

value and minimum required value (MRV)) and evaluating trend lines of the measured forces; 

corrective actions are taken if unacceptable results or trends are identified.

The LRA states that the program is based on ASME Code Section XI, Subsection IWL, with 

edition and addenda and associated conditions determined for each inspection interval in 

accordance with the requirements in 10 CFR 50.55a(g)(4); the edition for the current program is

the 2001 edition with the 2003 addenda. The LRA states that the PLL for tendons is developed 

consistent with the guidance in RG 1.35.1, “Determining Prestressing Forces for Inspection of 

Prestressed Concrete Containments,” dated July 1990, and the trend lines are constructed by 

regression analysis of individual measured tendon forces consistent with NRC IN 99-10,

“Degradation of Prestressing Tendon Systems in Prestressed Concrete Containments,” dated 

October 7, 1999. The LRA states that if individual tendon forces remain above 95 percent of 

predicted values, the actual prestressing force loss is not significantly greater than that allowed 

for in the original design calculations for each tendon group. The LRA further states that as long 

as the trend lines do not fall below the MRV before the next scheduled surveillance, the tendon 

prestress force is acceptable; if not, an evaluation will be performed in accordance with 

10 CFR 50.55a(b)(2)(viii)(B). The LRA states that trend lines based on new regression 

analyses of actual measured tendon forces for each tendon group (vertical and hoop) show that 

the group forces will not fall below the respective MRVs before the end of the period of 

extended operation for LSCS; however, because tendon force trends may vary with time, the 

regression analyses will be periodically updated after each surveillance. The LRA states that 

loss of containment tendon prestressing forces is a TLAA evaluated in accordance with 

10 CFR 54.21(c)(1)(iii), and this program is credited for managing the aging effect during the 

period of extended operation.
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Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP X.S1. For the “acceptance criteria”

program element, the staff determined the need for additional information, which resulted in the 

issuance of an RAI, as discussed below.

The “acceptance criteria” program element of the GALL Report AMP includes a provision 

intended to address the case in which the trend line goes below the PLL when the comparison 

of the two lines is made. It was not clear whether the program enhancement (Commitment 

No. 44), that commits to a comparison of the trend line and the PLL and MRV, will also be 

applicable to, and implemented in, the “acceptance criteria” program element of the LRA AMP 

to establish consistency because (a) the LRA AMP and the program basis document state that 

enhancement to the LRA AMP is applicable only to the “monitoring and trending” program 

element and (b) during the audit, the staff noted that statements in the description of the 

“acceptance criteria” program element of the LRA program basis document appear to address 

the case in which the trend line goes below the PLL; however, the program element description 

also states that there is no enhancement to the program element. By letter dated 

June 19, 2015, the NRC staff issued RAI B.3.1.2-1, requesting that the applicant clarify whether 

the program enhancement (Commitment No. 44) in LRA Section B.3.1.2, which intended to 

establish consistency with the GALL Report AMP X.S1 and was described in the LRA AMP as 

applicable only to the “monitoring and trending” program element, will also be applicable to, and 

implemented in, the “acceptance criteria” program element to become consistent with the 

“acceptance criteria” program element of the GALL Report AMP. The applicant was also 

requested to provide conforming updates to the LRA and/or UFSAR supplement, as 

appropriate, based on the response.

In its response dated July 15, 2015, to RAI B.3.1.2-1, the applicant stated that the intent of the 

enhancement described in Commitment No. 44 is to establish consistency with the

GALL Report AMP X.S1, and LRA Section B.3.1.2 is revised to indicate that the applicant has 

applied the enhancement and has implemented the “acceptance criteria” and “monitoring and 

trending” program elements to address the case in which the trend line goes below the PLL or 

MRV. The applicant also stated that the “monitoring and trending” program element enhanced 

by Commitment No. 44 requires the comparison of the trend line to the PLL and MRV for which 

acceptance criteria are implemented in the enhanced “acceptance criteria” program element,

thereby making the “acceptance criteria” program element consistent with that in the 

GALL Report AMP. Accordingly, the applicant revised LRA Section B.3.1.2 and will revise 

appropriate section(s) of the program basis document to indicate that Commitment No. 44 is 

applicable and has been implemented in both the “monitoring and trending” and “acceptance 

criteria” program elements. The applicant also revised LRA Section A.3.1.2 to make the 

wording of Commitment No. 44 consistent with that in LRA Section B.3.1.2.

The staff noted that the “acceptance criteria” program element of the applicant’s program basis 

document included acceptance criteria to address the case in which the trend line goes below 

the PLL or MRV. The staff finds the applicant’s response acceptable because the applicant 

clarified that Commitment No. 44 is applicable and is also implemented in the “acceptance 

criteria” program element of the LRA AMP and that LRA Sections B.3.1.2 and A.3.1.2 are 

revised, thereby making the LRA AMP consistent with the GALL Report AMP. The staff’s 

concern described in RAI B.3.1.2-1 is resolved.

The staff also reviewed the portions of the “monitoring and trending” and “acceptance criteria” 

program elements associated with the enhancement to determine whether the program will be 
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adequate to manage the aging effects for which it is credited. The staff’s evaluation of this 

enhancement follows.

Enhancement 1. LRA Section B.3.1.2, as revised by the applicant’s response letter dated 

July 15, 2015, to RAI B.3.1.2-1, includes an enhancement to the “monitoring and trending” and 

“acceptance criteria” program element. In this enhancement (Commitment No. 44), the 

applicant committed to update the program before the period of extended operation to include 

the following activities: “For each surveillance interval, trending lines will be updated through 

the period of extended operation as part of the regression analysis and compared to the 

predicted lower limit and minimum required values for each tendon group.” The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP X.S1 and 

finds it acceptable because, when it is implemented, updated trend lines accounting for the 

latest set of measured forces will be compared to PLLs and MRVs following each surveillance, 

thus ensuring that appropriate corrective actions are taken if adverse trends are identified, 

including if the trend line crosses the PLL, which makes the LRA program elements consistent

with the recommendations of the GALL Report AMP.

Based on its audit and review of the applicant’s Concrete Containment Tendon Prestress 

program, as amended by letter dated July 15, 2015, in response to RAI B.3.1.2, the staff finds 

that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP X.S1. In addition, the staff reviewed the enhancement associated with the “monitoring and 

trending” and “acceptance criteria” program elements and finds that, when implemented, it will 

make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.3.1.2 summarizes operating experience related to the 

Concrete Containment Tendon Prestress program. The LRA states that review of the operating 

experience did not identify any adverse trend in program performance and that the inspection 

methods implemented by the program have been proven effective in detecting loss of 

containment tendon prestress. According to the LRA operating experience program element, 

the program provides appropriate guidance for evaluation, repair, or replacement for locations 

where degradation is found. Furthermore, the LRA states that assessments of the program are 

performed to identify the areas that need improvement to maintain the quality performance of 

the program, and the program is informed and enhanced, as necessary, through the systematic 

and ongoing review of both plant-specific and industry operating experience.

A summary description of examples of operating experience is provided below, indicating 

objective evidence that the Concrete Containment Tendon Prestress program will be effective in 

ensuring that intended functions will be maintained during the period of extended operation.

The LRA states that, in 2003 and 2008, LSCS performed the 25th-year interval ASME Code 

Section XI, Subsection IWL, examinations of the concrete containment tendons for LSCS, 

Units 1 and 2, respectively, which included testing to assess the loss of prestressing forces in 

select containment tendons for one unit in accordance with the IWL-2421 examination 

requirements for sites with multiple plants, consistent with ASME Code Section XI, 

Subsection IWL requirements. The LRA states that trend lines developed by regression 

analyses, in accordance with NRC IN 99-10, document the results of tendon prestress 

surveillance data through the 25th-year interval. The LRA further states that, in 2013, these 

analyses were revised to extend the trend lines for more than 60 years, the results of which 

demonstrated that the predicted prestress for tendons at LSCS, Units 1 and 2, will remain above 

the respective MRVs for the period of extended operation; therefore, monitoring of the 
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containment tendon prestress forces to date indicates that the prestressing systems will 

continue to maintain their intended function through the period of extended operation without the 

need for tendon retensioning. The LRA states that, if subsequent continued updates to the 

regression analyses, proposed to be performed after each future surveillance, indicate that the 

predicted prestress forces for a tendon group are falling below the respective MRV, the 

condition would be entered into the corrective action program for evaluation and determination 

of appropriate corrective action. Therefore, the LRA concludes “there is sufficient confidence 

that implementation of the Concrete Containment Tendon Prestress [P]rogram will effectively 

identify degradation prior to failure or loss of intended function during the period of extended 

operation.”

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP X.S1 was evaluated.

UFSAR Supplement. LRA Section A.3.1.2 provides the UFSAR supplement for the Concrete 

Containment Tendon Prestress program. The staff reviewed this UFSAR supplement

description of the program, as amended by the applicant’s letter dated July 15, 2015, and noted 

that it is consistent with the recommended description in SRP-LR Table 4.5-1. The staff also 

noted that the applicant committed (Commitment No. 44) to implement the enhancement to the 

program before the period of extended operation. The staff finds that the information in the 

UFSAR supplement, as amended by letter dated July 15, 2015, is an adequate summary 

description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Concrete Containment 

Tendon Prestress program, as amended by the applicant’s letter dated July 15, 2015, the staff 

determined that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. In addition, the staff reviewed the enhancement and confirmed 

that its implementation before the period of extended operation will make the AMP adequate to 

manage the applicable aging effects. The staff concludes that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

3.0.3.3 AMPs Not Consistent with or Not Addressed in the GALL Report

In LRA Appendix B, the applicant identified the following AMPs as plant-specific:
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• Service Level III and Service Level III Augmented Coatings Monitoring and Maintenance 

Program

• Unit 2 Inspection of ASME Code Class 1 Small-Bore Piping program

For these AMPs not addressed in the GALL Report, the staff performed a complete review to 

determine their adequacy to monitor or manage aging. The staff’s review of these plant-specific 

AMPs is documented in the following section.

Service Level III and Service Level III Augmented Coatings Monitoring and 

Maintenance Program

Summary of Technical Information in the Application. LRA Section B.2.2.1 describes the new 

Service Level III and Service Level III Augmented Coatings Monitoring and Maintenance 

Program as a new plant-specific condition monitoring program that will manage the aging effect 

of loss of coating integrity in internally coated heat exchangers, piping, piping components, and 

tanks exposed to raw water, wastewater, and lubricating oil environments. The LRA states that 

the AMP manages this aging effect through periodic visual inspections. The LRA also states 

that the Service Level III and Service Level III Augmented Coatings Monitoring and 

Maintenance Program will be consistent with draft LR-ISG-2013-01, “Aging Management of 

Loss of Coating Integrity for Internal Service Level III (augmented) Coatings,” issued for public 

comment on January 10, 2014, which included draft GALL Report AMP XI.M42, “Service 

Level III (augmented) Coatings Monitoring and Maintenance Program.”

Staff Evaluation. The staff issued the final LR-ISG-2013-01, “Aging Management of Loss of 

Coating or Lining Integrity for Internal Coatings/Linings on In-Scope Piping, Piping Components, 

Heat Exchangers, and Tanks,” on November 14, 2014, which included the new GALL Report 

AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat 

Exchangers, and Tanks.” The staff reviewed program elements 1 through 7 of the applicant’s 

program against the acceptance criteria for the corresponding elements as stated in SRP-LR

Section A.1.2.3 and the final LR-ISG-2013-01 GALL Report AMP XI.M42. The staff’s review 

focused on how the applicant’s program manages aging effects through the effective 

incorporation of these program elements. The staff’s evaluation of each of these program 

elements follows.

Scope of Program. LRA Section B.2.2.1 states that all components within the scope of license 

renewal that are internally coated with Service Level III or Service Level III augmented coatings 

are within the scope of this program. This includes components in the essential service water, 

fire protection, nonessential service water, plant drainage, and RCIC systems that are exposed 

to raw water, wastewater, and lubricating oil.

The staff reviewed the applicant’s “scope of program” program element against the criteria in 

SRP-LR Section A.1.2.3.1, which state that the scope of the program should include the specific 

SCs for which loss of coating integrity will be managed.

The staff noted that LRA Table 3.3.2-7, “Demineralized Water Makeup System,” states that 

internally coated (i.e., galvanized steel) piping and piping components exposed to treated water 

will be managed for loss of coating integrity by the Service Level III and Service Level III 

Augmented Coatings Monitoring and Maintenance Program. However, the “scope of program” 

program element does not include the demineralized water makeup system. Therefore, the 

staff did not have sufficient information to determine whether the “scope of program” element or 

LRA Table 3.3.2-7 is correct. By letter dated May 29, 2015, the staff issued RAI B.2.2.1-1,
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requesting that the applicant reconcile the “scope of program” program element and LRA 

Table 3.3.2-7.

In its response dated June 25, 2015, the applicant stated that LRA Table 3.3.2-7 is correct and 

that LRA Section B.2.2.1 was revised to include the demineralized water makeup system within 

the scope of the Service Level III and Service Level III Augmented Coatings Monitoring and 

Maintenance Program. The applicant also revised the titles of the essential service water 

system and the nonessential service water system to essential cooling water system and 

nonessential cooling water system, respectively. Treated water was added as an applicable 

environment.

The staff finds the applicant’s response acceptable because the “scope of program” program 

element of the Service Level III and Service Level III Augmented Coatings Monitoring and 

Maintenance Program is consistent with the AMR items in the LRA Table 2’s. The staff’s 

concern described in RAI B.2.2.1-1 is resolved.

The staff finds the “scope of program” program element to be adequate because the applicant 

stated the specific components that will be managed by the program.

Based on its review of the application and review of the applicant’s response to RAI B.2.2.1-1, 

the staff confirmed that the “scope of program” program element satisfies the criterion defined in 

SRP-LR Section A.1.2.3.1; therefore, the staff finds it acceptable.

Preventive Actions. LRA Section B.2.2.1 states that the program is a condition monitoring 

program. The staff reviewed the applicant’s “preventive actions” program element against the 

criteria in SRP-LR Section A.1.2.3.2, which state that some condition monitoring programs do 

not rely on preventive actions; therefore, this information does not need to be presented.

The staff finds the applicant’s “preventive actions” program element to be adequate because it 

is consistent with GALL Report AMP XI.M42, which does not recommend any preventive 

actions.

Based on its review of the application, the staff confirmed that the “preventive actions” program 

element satisfies the criterion defined in SRP-LR Section A.1.2.3.2; therefore, the staff finds it 

acceptable.

Parameters Monitored or Inspected. LRA Section B.2.2.1 states that visual inspections are 

conducted to detect internal coatings that do not meet acceptance criteria and that physical 

testing is conducted to detect potential delamination. The visual inspections are used to detect 

peeling, delamination, blistering, cracking, flaking, chipping, rusting, and mechanical damage.

The staff reviewed the applicant’s “parameters monitored or inspected” program element 

against the criteria in SRP-LR Section A.1.2.3.3, which state that (a) the program should identify 

the aging effects that the program manages and should provide a link to the parameters that will 

be monitored and (b) the parameters monitored or inspected should be capable of detecting the 

presence and extent of aging effects.

The staff finds the “parameters monitored or inspected” program element to be adequate 

because the applicant has identified the aging effect (i.e., loss of coating integrity) and linked

this to the specific inspection parameters that can be visually detected (e.g., delamination, 

cracking, and blistering).
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Based on its review of the application, the staff confirmed that the “parameters monitored or 

inspected” program element satisfies the criteria defined in SRP-LR Section A.1.2.3.3;

therefore, the staff finds it acceptable.

Detection of Aging Effects. LRA Section B.2.2.1 states that (a) baseline visual coating 

inspections will occur before the period of extended operation, (b) subsequent visual inspections 

will be based on an evaluation conducted by a coating specialist qualified by standards 

endorsed in RG 1.54, “Service Level I, II, and III Protective Coatings Applied to Nuclear Power 

Plants,” Revision 2, dated October 2010, of the effect of an internal coating failure on the 

in-scope component’s intended function, potential problems identified during prior inspections, 

and known service life history, (c) inspection intervals will not exceed those recommended in 

draft GALL Report AMP XI.M42, Table 4a, “Inspection Intervals for Service Level III 

(Augmented) Coatings for Tanks, Piping, and Heat Exchangers,” (d) the extent of inspections 

will be based on an evaluation of the effect of an internal coating failure on the in-scope 

component’s intended function(s), potential problems identified during prior inspections, and 

known service life history, but not be less than all accessible surfaces for heat exchangers, 

strainers, and tanks and 73 1-ft axial length circumferential segments of piping or 50 percent of 

the length of each coating material and environment combination, (e) where inspection surfaces 

are limited due to geometry, the number of inspection segments of piping will be increased to 

cover an equivalent surface area, (f) a coating’s environment consists of the environment inside 

the component and the material of the component, (g) inspection locations are based on 

susceptibility to degradation and consequences of failure, (h) coating surfaces between 

interlocking surfaces are not required to be inspected unless the joint has been disassembled to 

allow access for an internal coating inspection or other reasons, and (i) consideration will be 

given to the use of remote or robotic inspection tools when surfaces are not readily accessible 

for inspection. LRA Section B.2.2.1 also states that internal coating inspections may be omitted 

if the degradation of coatings cannot result in downstream effects; however, inspections are 

conducted if corrosion rates or inspection intervals have been based on the integrity of the 

coatings. In this case, as an alternative to direct internal visual inspection of the coatings, 

external wall thickness measurements can be performed to confirm the acceptability of the 

corrosion rate of the base metal. LRA Section B.2.2.1 further states that the training and 

qualification of individuals involved in coating inspections and evaluation of degraded conditions 

are conducted in accordance with standards endorsed in RG 1.54, including staff guidance.

The staff reviewed the applicant’s “detection of aging effects” program element against the 

criteria in SRP-LR Section A.1.2.3.4, which state that the program should describe (a) how the 

program element will be capable of detecting the occurrence of age-related degradation before

the loss of the CLB intended function(s) of in-scope components, (b) the when, where, and how

data are collected, and (c) the basis of the sample size and location selection.

The staff noted that the final LR-ISG-2013-01 GALL Report AMP XI.M42 recommends a 

periodicity and size of inspection for alternative wall thickness measurements, which was not 

included in the draft LR-ISG-2013-01 GALL Report AMP XI.M42. Specifically, the AMP 

recommends that wall thickness measurements be conducted every 10 years, commencing 

10 years before the period of extended operation. A representative sample size is 25 percent of 

accessible external surfaces for heat exchangers, strainers, and tanks; and 73 1-ft axial length 

circumferential segments for piping. In addition, the final GALL Report AMP XI.M42

recommends that the inspection grid size should be the same as that for flow-accelerated 

corrosion inspections. By letter dated May 29, 2015, the staff issued RAI B.2.2.1-2, requesting 

that the applicant state the periodicity and size of inspection for alternative wall thickness 

measurements.
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In its response dated June 25, 2015, the applicant revised LRA Section B.2.2.1 to include the 

size and periodicity recommendations associated with external wall thickness measurements 

included in the final LR-ISG-2013-01. The applicant also revised LRA Section B.2.2.1 to include 

the following alternative recommendations included in the final LR-ISG-2013-01:

• incorporation of a reduced alternative inspection scope for piping when “documentation 

exists that manufacturer recommendations and industry consensus documents 

(i.e., those recommended in RG 1.54, or earlier versions of those standards) were 

complied with during installation”

• incorporation of a recommendation that “the lesser of 73 1-ft axial length circumferential 

segments of piping or 50 percent of the total length of each coating material and 

environment combination may be inspected”

• incorporation of a provision to conduct external wall thickness measurements in lieu of 

internal coating inspections if specific conditions are met related to the absence of 

downstream effects of coating failure, intended function(s) of the system, internal 

environment, potential for microbiologically-induced corrosion, potential for galvanic 

couples, and design credit for the coating

The staff finds the applicant’s response and alternative recommendations acceptable because 

the changes are consistent with the final GALL Report AMP XI.M42. The staff’s concern 

described in RAI B.2.2.1-2 is resolved.

The staff finds the applicant’s “detection of aging effects” program element to be adequate 

because the program element describes the periodicity of inspections; explains how inspections 

will be conducted; and includes inspection location selection criteria, the sample size for 

inspections, and qualifications of individuals involved in coating inspections, consistent with the 

final GALL Report AMP XI.M42.

Based on its review of the application and review of the applicant’s response to RAI B.2.2.1-2, 

the staff confirmed that the “detection of aging effects” program element satisfies the criteria

defined in SRP-LR Section A.1.2.3.4; therefore, the staff finds it acceptable.

Monitoring and Trending. LRA Section B.2.2.1 states that (a) a pre-inspection review of the 

previous two inspections and any repair activities of the component will be conducted, 

(b) trending of coating degradation results will be used to determine the next inspection interval, 

not to exceed the intervals in draft LR-ISG-2013-01 GALL Report AMP XI.M42, (c) a coatings 

specialist will prepare or review the inspection report, and (d) the report will include “a list and 

location of all areas evidencing deterioration, a prioritization of the repair areas into areas that 

must be repaired before returning the system to service, and areas where repair can be 

postponed to the next inspection.” During the audit, the staff noted that a plant-specific 

procedure associated with coatings inspections requires that coating defects be photographed. 

LRA Section B.2.2.1 also states that, when base metal corrosion is the only issue related to loss 

of coating integrity and when wall thickness measurements are used in lieu of direct visual 

examination of the coating, the corrosion rate is trended. Coating defects are entered into the 

corrective action program.

The staff reviewed the applicant’s “monitoring and trending” program element against the 

criteria in SRP-LR Section A.1.2.3.5, which state that monitoring and trending activities should 

be described and that the results should be evaluated against the acceptance criteria to effect 

timely corrective or mitigative actions.
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The staff finds the applicant’s “monitoring and trending” program element to be adequate 

because (1) the applicant stated how it would conduct monitoring and trending (e.g., reviewing 

past inspection reports, involving coatings specialist in the post-inspection report, and providing 

details in the report), (2) coating defects are entered into the corrective action program where 

they will be evaluated against the acceptance criteria, and (3) they are consistent with the final 

GALL Report AMP XI.M42.

Based on its review of the application, the staff confirmed that the “monitoring and trending” 

program element satisfies the criteria defined in SRP-LR Section A.1.2.3.5; therefore, the staff 

finds it acceptable.

Acceptance Criteria. LRA Section B.2.2.1 states that coating defects are documented and 

evaluated in the corrective action program; the evaluation is conducted to ensure that the 

component’s intended function(s) is met for all CLB design conditions; and “[a]s necessary, 

visual inspection may be supplemented by additional testing, such as adhesion testing or other 

inspection technique as determined by the inspector to accurately assess coating condition.” 

LRA Section B.2.2.1 states that the acceptance criteria are as follows:

• Peeling and delamination is evaluated by a coatings specialist. Coating specialists are 

qualified in accordance with standards endorsed in RG 1.54. Physical testing is 

performed, where possible (i.e., sufficient room to perform the test), if it is required to 

assess the condition of the coating. Physical testing consists of measuring a minimum 

of three sample points adjacent to the defective area by destructive or nondestructive 

adhesion testing using ASTM International standards.

• Blisters are evaluated by a coatings specialist. If the blister is not repaired, the cause of 

the blister needs to be determined. “Physical testing is conducted if required to assess 

the condition of the coating.” When coatings are credited for corrosion prevention, the 

base material in the vicinity of the blister is inspected to determine whether unanticipated 

corrosion has occurred.

• Cracking, flaking, and rusting are evaluated by a coatings specialist.

• Wall thickness measurements meet design minimum wall requirements.

• Engineering documents specific to the coating and substrate are used to determine 

whether adhesion testing results meet or exceed the acceptance criteria.

The staff reviewed the applicant’s “acceptance criteria” program element against the criteria in 

SRP-LR Section A.1.2.3.6, which state that the acceptance criteria of the program and its basis 

should be described and the acceptance criteria should ensure that the component’s intended 

function(s) is met.

The staff noted the following:

• GALL Report AMP XI.M42 recommends that indications of peeling and delamination are 

not acceptable, whereas the applicant stated that a coatings specialist will evaluate the 

condition. The applicant did not state what criteria will be used to find peeling or 

delamination acceptable or what actions will be taken before returning the degraded 

component to service. The “corrective actions” program element of the final 

GALL Report AMP XI.M42 provides recommendations for evaluations and actions that 

will be taken before returning a component with peeling or delaminated coatings to 

service.
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• The “corrective actions” program element in GALL Report AMP XI.M42 recommends 

that, for indications of peeling and delamination on components that will be returned to 

service without repair and for indications of blisters, adhesion testing be conducted. For 

blisters, alternatives to adhesion testing are permitted where adhesion testing is not 

possible due to physical constraints. The applicant stated that physical testing will be 

conducted, “if required.” The applicant did not state what criteria will be used to 

conclude that physical testing will not be required. Absent physical testing, it is not clear 

to the staff how the applicant will determine the extent of peeling, delamination, or 

blistering.

By letter dated May 29, 2015, the staff issued RAI B.2.2.1-3, requesting that the applicant state: 

(a) what criteria will be used to find peeling or delamination acceptable and what actions will be 

taken before returning the component with peeling or delaminated coatings to service and 

(b) what criteria will be used to conclude that physical testing will not be required when peeling, 

delamination, or blistering is detected and explain how it will determine the extent of the 

degraded coatings.

In its response dated June 25, 2015, the applicant revised the acceptance criteria in LRA 

Section B.2.2.1 to state that (a) peeling and delamination is not acceptable, (b) blisters are 

limited to “a few intact small blisters that are completely surrounded by sound coating bonded to 

the substrate,” and (c) the blister size and frequency is not increasing between inspections.

The staff finds the applicant’s response associated with the “acceptance criteria” program 

element acceptable because the revised acceptance criteria are consistent with those in the 

final GALL Report AMP XI.M42. The staff’s concern associated with the “acceptance criteria” 

program element described in RAI B.2.2.1-3 is resolved.

The staff finds the “acceptance criteria” program element to be adequate because the 

acceptance criteria related to observed parameters have been described and because they are 

consistent with the final GALL Report AMP XI.M42.

Based on its review of the application and review of the applicant’s response to RAI B.2.2.1-3,

the staff confirmed that the “acceptance criteria” program element satisfies the criteria defined in 

SRP-LR Section A.1.2.3.6; therefore, the staff finds it acceptable.

Corrective Actions. LRA Section B.2.2.1 states that inspection results that detect coatings that 

do not meet acceptance criteria will be entered in the corrective action program. LRA 

Section B.2.2.1 also states that “[i]f appropriate, corrective actions may include repair or 

replacement of the internal coating prior to the component being returned to service.”

The staff reviewed the applicant’s “corrective actions” program element against the criteria in 

SRP-LR Section A.1.2.3.7, which state that (a) if corrective actions permit analysis without 

repair or replacement, the analysis should ensure that the component’s intended function(s) is

maintained consistent with the CLB and (b) actions to be taken when the acceptance criteria are 

not met should be described in appropriate detail or referenced to source documents.

The staff noted that the “corrective actions” program element of GALL Report AMP XI.M42 

states that coatings that do not meet acceptance criteria are repaired, replaced, or removed. 

The staff concludes that the applicant’s statement, “if appropriate,” implies that coatings that do 

not meet acceptance criteria could be returned to service without repair, replacement, or 

removal. The applicant did not state what criteria will be used to return coatings that do not 
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meet acceptance criteria to service without repair. By letter dated May 29, 2015, the staff 

issued RAI B.2.2.1-3, requesting that the applicant state what criteria will be used to return 

components with coatings that do not meet acceptance criteria to service without repair, 

replacement, or removal of the coatings.

In its response dated June 25, 2015, the applicant revised LRA Section B.2.2.1 to state that 

“[c]oatings that do not meet acceptance criteria are repaired, replaced, or removed. Testing or 

examination is conducted to ensure that the extent of repaired or replaced coatings 

encompasses sound coating material.” The applicant also revised the program to include 

corrective actions associated with (a) returning components with coatings exhibiting peeling or 

delamination to service, (b) conducting confirmatory wall thickness measurements when the 

base metal has been exposed or when the base metal is located below a blister, and (c) testing 

for blisters that are not repaired.

The staff noted that the applicant’s changes to its program included all of the recommendations 

associated with the additional corrective action provisions in GALL Report AMP XI.M42. The 

staff finds the applicant’s response and additional corrective actions associated with the 

“corrective actions” program element acceptable because they are consistent with the final 

GALL Report AMP XI.M42. The staff’s concern associated with the “corrective actions” program 

element described in RAI B.2.2.1-3 is resolved.

Based on its review of the application and review of the applicant’s response to RAI B.2.2.1-3, 

the staff confirmed that the “corrective action” program element satisfies the criteria defined in 

SRP-LR Section A.1.2.3.7; therefore, the staff finds it acceptable.

Operating Experience. LRA Section B.2.2.1 summarizes operating experience related to the 

Service Level III and Service Level III Augmented Coatings Monitoring and Maintenance 

Program. The applicant stated that in March 2007, during the inspection of internal coatings on 

diesel generator cooling water heat exchanger end bells, the CeramAlloyTM coating came loose 

from the base material in some of the end bells. Tube blockage had occurred in one instance. 

The applicant determined that the likely cause was inappropriate surface preparation during 

installation of the coating. Corrective measures were implemented and delamination of this 

coating has not subsequently occurred on these heat exchangers. In January 2014 peeling, 

flaking and erosion were detected in the CeramAlloyTM coating on a reactor building closed 

cooling water heat exchanger. The areas exhibiting flaking and peeling were repaired, the 

thinning area was evaluated, and repair was deferred until 2017. In September 2012 the 

CeramAlloyTM coatings on the primary containment chiller condensers exhibited erosion and 

thinning. This degradation was typically found in the middle of the dollar plate of the heat 

exchanger. Spare end covers were procured and were coated before the conduct of

maintenance activities on these heat exchangers.

The staff reviewed this information against the acceptance criteria in SRP-LR 

Section A.1.2.3.10, which state that the applicant should review relevant plant-specific or 

generic industry operating experience applicable to the new program.

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its review of the application, the staff finds that the applicant has appropriately 

evaluated plant-specific and industry operating experience and that the program, when 
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implemented, can adequately manage the effects of aging on SSCs within the scope of the 

program.

UFSAR Supplement. As amended by letter dated June 25, 2015, LRA Section A.2.2.1 provides 

the UFSAR supplement for the Service Level III and Service Level III Augmented Coatings 

Monitoring and Maintenance Program. The staff reviewed this UFSAR supplement description 

of the program and noted that it is consistent with the recommended description in SRP-LR

Table 3.0-1. The staff also noted that the applicant committed to implement the new Service 

Level III and Service Level III Augmented Coatings Monitoring and Maintenance Program 

before the period of extended operation with baseline inspections commencing in the 10-year 

period before the period of extended operation for managing the effects of aging for applicable 

components. The staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program.

Conclusion. On the basis of its technical review of the applicant’s Service Level III and Service 

Level III Augmented Coatings Monitoring and Maintenance Program, the staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

Unit 2 Inspection of ASME Code Class 1 Small-Bore Piping Program

Summary of Technical Information in the Application. By letter dated August 6, 2015, the 

applicant revised the LRA and provided LRA Section B.2.2.2, which describes the applicant’s 

Unit 2 Inspection of ASME Code Class 1 Small-Bore Piping Program, as a new plant-specific 

condition monitoring program that will manage the aging effects of cracking in ASME Code 

Class 1 small-bore piping. The applicant stated that the program will perform inspections of a 

sample of ASME Code Class 1 small-bore piping less than NPS 4-inches and greater than or 

equal to NPS 1-inch. The applicant also stated that the program will perform inspections before 

and during the period of extended operation, which will augment the requirements of ASME 

Code, Section XI, Inservice Inspections. The applicant further stated that the scope of the 

program will include pipes, fittings, branch connections, and full penetration (butt) welds and 

partial penetration (socket) welds. LSCS, Unit 1, will implement a Unit 1 One-time Inspection of 

ASME Code Class 1 Small-Bore Piping program. The staff’s review of the applicant’s Unit 1 

One-time Inspection of ASME Code Class 1 Small-Bore Piping program is discussed in SER 

Section 3.0.3.1.11.

Staff Evaluation. The staff reviewed program elements 1 through 6 of the applicant’s program 

against the acceptance criteria for the corresponding elements as stated in SRP-LR 

Section A.1.2.3. The staff’s review focused on how the applicant’s program manages aging 

effects through the effective incorporation of these program elements. The staff’s evaluation of 

each of these program elements is discussed below. The staff’s review of the “corrective 

actions,” “confirmation process,” and “administrative controls” programs elements are 

documented in SER Section 3.0.4.

Scope of Program. LRA Section B.2.2.2 states that the scope of the program includes ASME 

Code Class 1 piping less than NPS 4-inches and greater than or equal to NPS 1-inch. The 

scope includes reactor pressure boundary pipes, fittings, branch connections, and full 

penetration (butt) and partial penetration (socket) welds.
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The staff reviewed the applicant’s “scope of program” program element against the criterion in 

SRP-LR Section A.1.2.3.1, which states that the scope of the program should include the 

specific structures and components that will be managed.

The staff finds the applicant’s “scope of program” program element to be adequate because the 

scope of the ASME Code Class 1 small-bore in-scope piping has been identified.

Based on its review of the application, as amended by letter dated August 6, 2015, the staff 

confirmed that the “scope of program” program element satisfies the criterion defined in SRP-LR 

Section A.1.2.3.1; therefore, the staff finds it acceptable.

Preventive Actions. LRA Section B.2.2.2 states that the Unit 2 Inspection of ASME Code 

Class 1 Small-Bore Piping program is a condition monitoring program and uses inspections to 

detect degradation of components before loss of intended function. The applicant stated that 

the program does not include preventive actions; however, it validates the effectiveness of the 

Water Chemistry AMP to mitigate SCC and the adequacy of the design of the ASME Code 

Class 1 small-bore piping.

The staff reviewed the applicant’s “preventive actions” program element against the criteria in 

SRP-LR Section A.1.2.3.2, which state that some condition monitoring programs do not rely on 

preventive actions; therefore, this information does not need to be presented.

The staff finds the applicant’s “preventive actions” program element to be adequate because 

this program is a condition monitoring program that does not rely on preventive actions.

Based on its review of the application, as amended by letter dated August 6, 2015, the staff 

confirmed that the “preventive actions” program element satisfies the criteria defined in SRP-LR 

Section A.1.2.3.2 for condition monitoring programs; therefore, the staff finds it acceptable.

Parameters Monitored or Inspected. LRA Section B.2.2.2 states that the Unit 2 Inspection of 

ASME Code Class 1 Small-Bore Piping Program includes inspection activities that can detect 

cracking that may be caused by SCC, cyclical thermal and mechanical fatigue, and thermal 

stratification or thermal turbulence. The LRA also states that inspections will be performed by 

examinations, which have been demonstrated capable of detecting cracking.

The staff reviewed the applicant’s “parameters monitored or inspected” program element 

against the criteria in SRP-LR Section A.1.2.3.3, which state that, for a condition monitoring 

program, the parameters monitored or inspected should be capable of detecting the presence 

and extent of the aging effect, such as detection of cracks.

The staff finds the applicant’s “parameters monitored or inspected” program element to be

adequate because this program is a condition monitoring program that will use volumetric

examination techniques that have been demonstrated to be capable of detecting cracking, or 

destructive examination.

Based on its review of the application, as amended by letter dated August 6, 2015, the staff 

confirmed that the “parameters monitored or inspected” program element satisfies the criteria

defined in SRP-LR Section A.1.2.3.3 for condition monitoring programs; therefore, the staff finds 

it acceptable.
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Detection of Aging Effects. LRA Section B.2.2.2 states that the Unit 2 Inspection of ASME Code 

Class 1 Small-Bore Piping Program will augment ASME Section XI, Inservice Inspection 

requirements and will detect cracking through the use of volumetric or destructive examinations. 

The applicant stated that the inspection of butt welds associated with this program will be 

performed using volumetric examinations as specified by ASME Code, Section XI. The 

applicant also stated that socket welds will be inspected using demonstrated volumetric 

examination techniques that can detect cracking, or by means of destructive examinations. The 

applicant further stated that, because destructive examinations are capable of detecting 

cracking and have the potential to yield more information than volumetric examinations, such as 

identifying the root cause, each destructive examination can be credited as having 

volumetrically examined two socket welds.

The program states that LSCS, Unit 2, which has operated for 31 years, experienced a failure of 

a socket weld in 2005 that was determined to be the result of age-related degradation. An 

evaluation was performed to identify similar small-bore piping that may be susceptible to the 

same causal factors that contributed to the failure. The applicant stated that, as a result of 

these evaluations, it identified a population of 10 socket welds in the Unit 2 small-bore 

population that can be associated with the same causal factors that contributed to the failure 

identified in 2005. The applicant also stated that the identified population of socket welds will be 

subjected to periodic inspections. These inspections would be completed during the 6 years 

before the period of extended operation and would be repeated every 10 years during the 

period of extended operation. The sample size for these inspections would be 50 percent of the 

susceptible population (five welds).

The program also includes a one-time inspection using volumetric or destructive examinations 

for ASME Code Class 1 small-bore piping welds determined not to be susceptible to the causal 

factors associated with the failure identified in 2005. The applicant stated that the one-time 

inspection would be completed during the 6 years before the period of extended operation and 

will include at least 3 percent of the weld population or a maximum of 10 welds for each weld 

type. Based on the total population of in-scope small-bore piping welds, the one-time inspection 

would consist of 10 socket welds and 3 butt welds. The applicant also stated that, if additional 

ASME Class 1 small-bore welds fail, or degradation, or age-related cracking is identified by the 

these examinations (one-time or periodic), additional evaluations would be performed as part of 

the corrective action program to determine the need for further periodic inspections.

The staff reviewed the applicant’s “detection of aging effects” program element against the 

criteria in SRP-LR Section A.1.2.3.4, which state that detection of aging effects should occur 

before there is a loss of structure or loss of component intended function(s). Therefore, the 

“detection of aging effects” program element should describe (a) how the program element will 

be capable of detecting the occurrence of age-related degradation before the loss of the CLB

intended function(s) of in-scope components, (b) when, where, and how data are collected,

(c) the basis for sample size and location selection based on susceptibility or previous failure 

history, and (d) bias toward locations most susceptible to the specific aging effect.

The staff noted that the applicant’s plant-specific program incorporates two specific inspection

programs, a periodic program for socket welds that may be susceptible to the 2005 failure and a 

one-time program for the balance of the ASME Code Class 1 small-bore piping, which includes 

butt welds and socket welds. As part of the periodic program, five socket welds will be 

examined before the period of extended operation. These examinations will be repeated for

each subsequent 10-year interval during the period of extended operation. In addition, 

10 socket and 3 butt welds will be examined before the period of extended operation as part of 
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the one-time inspection. Based on the total number of proposed inspections (periodic and 

one-time inspections), and because the inspections would be biased toward selection of the 

most susceptible locations, it is believed that potential aging degradation of ASME Code Class 1 

small-bore piping will be detected before loss of intended function(s).

The staff finds the applicant’s “detection of aging effects” program element to be adequate 

because the applicant will be performing a combination of one-time and periodic inspections to 

identify age-related degradation before and during the period of extended operation. In 

addition, the type of inspections, inspection intervals, extent of inspections, and sample size are 

considered adequate for managing cracking of ASME Code Class 1 small-bore piping welds 

during the period of extended operation.

Based on its review of the application, as amended by letter dated August 6, 2015, the staff 

confirmed that the “detection of aging” program element satisfies the criteria defined in SRP-LR 

Section A.1.2.3.4; therefore, the staff finds it acceptable.

Monitoring and Trending. LRA Section B.2.2.2 states that the Unit 2 Inspection of ASME Code 

Class 1 Small-Bore Piping Program will include inspection activities to detect cracking due to 

SCC, cyclical thermal and mechanical fatigue, and thermal stratification or thermal turbulence. 

The applicant stated that the program does not have specific actions that would be applied to 

monitoring and trending the rate of age-related degradation. The program will use the 

applicable requirements of ASME Code, Section XI, when age-related degradation or cracking 

is identified, to determine acceptability of the condition and the required corrective actions. The 

applicant also stated that it will use plant-specific operating experience relative to the condition 

of the small-bore piping resulting from the periodic inspections to determine whether the sample 

population of the periodic inspection should be increased. The applicant further stated that the 

results of the one-time inspection will also be used to determine whether additional welds 

should be periodically examined.

The staff reviewed the applicant’s “monitoring and trending” program element against the 

criteria in SRP-LR Section A.1.2.3.5, which state that monitoring and trending activities should 

be described and the results should be evaluated against the acceptance criteria to effect timely 

corrective or mitigative actions. Plant-specific and/or industry-wide operating experience may 

be considered in evaluating the appropriateness of the technique and frequency.

The staff finds the applicant’s “monitoring and trending” program element to be adequate 

because the program will use the acceptance criteria of ASME Code, Section XI, and when 

indications of degradation or cracking are identified, the adverse conditions would be entered in 

the corrective action program. In addition, the program’s inspection results, along with industry 

and plant-specific operating experience, will be used to evaluate the frequency of inspections.

Based on its review of the application, as amended by letter dated August 6, 2015, the staff 

confirmed that the “monitoring and trending” program element satisfies the criteria defined in 

SRP-LR Section A.1.2.3.5; therefore, the staff finds it acceptable.

Acceptance Criteria. LRA Section B.2.2.2 states that the Unit 2 Inspection of ASME Code 

Class 1 Small-Bore Piping Program will use the acceptance criteria of ASME Code Section XI, 

Subsection IWA-3000, which is applicable to ASME Code Class 1 components.

The staff reviewed the applicant’s “acceptance criteria” program element against the criteria in 

SRP-LR Section A.1.2.3.6, which state, in part, that it is not necessary to justify any acceptance 
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criteria that are taken from codes and standards incorporated by reference into NRC regulations 

because these have been subject to prior NRC review process and have been approved or 

endorsed for use. The staff noted that the small-bore piping referenced in the program consists 

of ASME Code Class 1 piping; therefore, the use of the acceptance criteria of ASME Code, 

Section XI, Subsection IWA-3000, is applicable and appropriate.

Based on its review of the application, as amended by letter dated August 6, 2015, the staff 

confirmed that the “acceptance criteria” program element satisfies the criteria defined in 

SRP-LR Section A.1.2.3.6; therefore, the staff finds it acceptable.

Operating Experience. LRA Section B.2.2.2 summarizes operating experience related to the 

applicant’s program. The LRA states that the applicant performed an extensive review of plant 

operating experience to determine whether LSCS, Unit 2, experienced any cracking of ASME 

Code Class 1 small-bore piping due to fatigue or SCC. The applicant stated that this included 

review of the corrective action program database going back to January 2001, as well as review 

of correspondence to the NRC going back to 1982, and included interviews with the LSCS 

ASME Inservice Inspection program owner. The applicant also stated that these reviews 

identified a leak detected by VT-2 inspection of the reactor coolant pressure boundary in 2005. 

The applicant further stated that the leak was located on a socket weld on a 2-inch main steam 

drain line. The cause of the failure was attributed to a defective weld repair performed in 1995. 

The applicant stated that the root cause evaluation performed in 2005 concluded that the failure 

was the result of a defective weld repair performed in 1995; however, it is now considered that 

age-related degradation also contributed to the failure.

The applicant stated that since 2003, it has performed periodic volumetric examinations of 

ASME Code Class 1 small-bore piping butt welds and visual examinations of socket welds. The 

applicant also stated that, before 2002, ASME Code Class 1 small-bore piping butt and socket

welds were periodically examined by visual examinations and that, with the exception of the 

failure of the socket weld in 2005, there were no other examples of unacceptable conditions. 

The applicant further stated that the program will be informed and enhanced as needed through 

the ongoing review of plant-specific and industry operating experience.

The staff reviewed this information against the acceptance criteria in SRP-LR 

Section A.1.2.3.10, which state, in part, that currently available operating experience applicable 

to the new program, as well as consideration of future plant-specific and industry operating 

experience related to AMPs, should be discussed. SRP-LR Section A.1.2.3.10 also states that 

the information on the operating experience should provide objective evidence to support that 

the program adequately manages the effects of aging during the period of extended operation.

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program.

Based on its review of the application, as amended by letter dated August 6, 2015, the staff 

finds that the applicant has appropriately evaluated plant-specific and industry operating 

experience. The staff confirmed that the “operating experience” program element satisfies the

criteria in SRP-LR Section A.1.2.3.10; therefore, the staff finds it acceptable.

UFSAR Supplement. LRA Section A.2.2.2, dated August 6, 2015, provides the UFSAR 

supplement for the Unit 2 Inspection of ASME Code Class 1 Small-Bore Piping Program at 

LSCS, Unit 2. The staff reviewed this UFSAR supplement description of the program and noted 

that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff also 
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noted that the applicant committed to implement the new Unit 2 Inspection of ASME Code 

Class 1 Small-Bore Piping Program before the period of extended operation for managing the 

effects of aging of applicable components. The staff finds that the information in the UFSAR 

supplement is an adequate summary description of the program.

Conclusion. On the basis of its technical review of the applicant’s Unit 2 Inspection of ASME 

Code Class 1 Small-Bore Piping Program at LSCS, Unit 2, the staff concludes that the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs

3.0.4.1 Summary of Technical Information in the Application

In LRA Appendix A, “Updated Final Safety Analysis Report Supplement,” Section A.1.5, “Quality 

Assurance Program and Administrative Controls,” and Appendix B, “Aging Management 

Programs,” Section B.1.3, “Quality Assurance Program and Administrative Controls,” the 

applicant described the elements of corrective action, confirmation process, and administrative 

controls that are applied to the AMPs for both safety-related and nonsafety-related components.

LRA Appendix A, Section A.1.5, states the following:

The Quality Assurance Program implements the requirements of 10 CFR 50,

Appendix B, and is consistent with the summary in Appendix A.2, “Quality

Assurance For Aging Management Programs (Branch Technical Position

IQMB-1),” of NUREG–1800. The Quality Assurance Program includes the

elements of corrective action, confirmation process, and administrative controls, 

and is applicable to the safety-related and nonsafety-related systems, structures, 

and components (SSCs) that are subject to Aging Management Review (AMR).

LRA Appendix B, Section B.1.3, states the following:

The Quality Assurance Program implements the requirements of 10 CFR 50,

Appendix B, and is consistent with the summary in Appendix A.2, “Quality

Assurance for Aging Management Programs (Branch Technical Position 

IQMB-1),” of NUREG–1800. The Quality Assurance Program includes the 

elements of corrective action, confirmation process, and administrative controls, 

and is applicable to the safety-related and nonsafety-related systems, structures, 

components (SSCs), and commodity groups that are subject to AMR.

3.0.4.2 Staff Evaluation

In accordance with 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects 

of aging on SCs subject to an AMR will be adequately managed so that their intended functions 

will be maintained consistent with the CLB for the period of extended operation. The SRP-LR, 

Branch Technical Position RLSB-1, “Aging Management Review – Generic,” (SRP-LR BTP 

RLSB-1) describes 10 attributes of an acceptable AMP. Three of these 10 attributes are 

associated with the QA activities of corrective action, confirmation process, and administrative 
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controls. SRP-LR BTP RLSB-1 Table A.1-1 provides the following description of these quality 

assurance attributes:

• Element No. 7 - Corrective Actions, including root cause determination and prevention of 

recurrence, should be timely;

• Element No. 8 - Confirmation Process, which should ensure that preventive actions are 

adequate and that appropriate corrective actions have been completed and are 

effective; and,

• Element No. 9 - Administrative Controls, which should provide a formal review and 

approval process.

SRP-LR, Branch Technical Position IQMB-1, “Quality Assurance for Aging Management 

Programs,” (SRP-LR BTP IQMB-1) states that those aspects of the AMP that affect the quality 

of safety-related SSCs are subject to the QA requirements of 10 CFR Part 50 Appendix B. 

Additionally, for nonsafety-related SCs subject to an AMR, the applicant’s existing

10 CFR Part 50, Appendix B, QA program may be used to address the elements of corrective 

action, confirmation process, and administrative control. SRP-LR BTP IQMB-1 provides the 

following guidance with regard to the QA attributes of AMPs:

Safety-related SCs are subject to Appendix B to 10 CFR Part 50 requirements 

which are adequate to address all quality related aspects of an AMP consistent 

with the CLB of the facility for the period of extended operation. For 

nonsafety-related SCs that are subject to an AMR for license renewal, an 

applicant has an option to expand the scope of its Appendix B to 10 CFR Part 50 

program to include these SCs to address corrective action, confirmation process, 

and administrative control for aging management during the period of extended 

operation. In this case, the applicant should document such a commitment in the 

Final Safety Analysis Report supplement in accordance with 10 CFR 54.21(d).

The staff reviewed LRA Appendix A, Section A.1.5, and Appendix B, Section B.1.3, which 

describe how the applicant’s existing quality assurance program includes the QA-related 

elements (corrective action, confirmation process, and administrative controls) for AMPs 

consistent with the staff’s guidance described in SRP-LR BTP IQMB-1. The staff also reviewed 

a sample of AMP program basis documents and verified that the AMPs implement the 

corrective action program, confirmation processes, and administrative controls as described in 

the LRA. Based on its review, the staff determined that the quality assurance attributes 

presented in the AMP program basis documents and the associated AMPs are consistent with 

the staff’s position regarding QA for aging management.

3.0.4.3 Conclusion

On the basis of the staff’s evaluation, the descriptions and applicability of the applicant’s AMPs 

and their associated quality assurance attributes provided in LRA Appendix A, Section A.1.5, 

and Appendix B, Section B.1.3, are consistent with the staff’s position regarding QA for aging 

management. The staff concludes that the QA attributes (corrective action, confirmation 

process, and administrative control) of the applicant’s AMPs are consistent with 

10 CFR 54.21(a)(3).
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3.0.5 Operating Experience for Aging Management Programs

3.0.5.1 Summary of Technical Information

LRA Section B.1.4, “Operating Experience,” describes the consideration of operating experience 

for AMPs. The LRA states that operating experience for the programs credited with managing 

the effects of aging are reviewed and also included a review of corrective actions that resulted in 

program enhancements.

In accordance with the Exelon fleet Exelon Operating Experience (OPEX) program, which 

conforms to the recommendations of LR-ISG-2011-05, “Ongoing Review of Operating 

Experience,” dated March 16, 2012, the applicant states that it performs a systematic review of 

plant-specific and industry operating experience concerning aging management and age-related 

degradation to ensure that the license renewal AMPs will be effective in managing the aging 

effects for which they are credited.

3.0.5.2 Staff Evaluation

Overview

In accordance with 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects 

of aging on SCs subject to an AMR will be adequately managed so that their intended functions 

will be maintained in a way consistent with the CLB for the period of extended operation. 

SRP-LR Appendix A describes 10 elements of an acceptable AMP. SRP-LR Section A.1.2.3.10 

describes program element 10, “operating experience.” On March 16, 2012, the staff issued 

final LR-ISG-2011-05, “Ongoing Review of Operating Experience,” which includes interim 

revisions to the SRP-LR to clarify criteria for the operating experience program element.

The following evaluation covers the staff’s review of the first criterion, which concerns the 

consideration of future operating experience.

Consideration of Future Operating Experience

The staff reviewed LRA Sections B.1.4, “Operating Experience,” and B.2, “Aging Management 

Programs,” to determine how the applicant will use future operating experience to ensure that 

the AMPs are effective. The staff evaluated the applicant’s operating experience review 

activities, as described in the LRA. The staff’s evaluations with respect to these SRP-LR 

sections follow in SER Sections 3.0.5.2.3 and 3.0.5.2.4, respectively.

Acceptability of Existing Programs

SRP-LR Section A.4.2 describes existing programs generally acceptable to the staff for the 

capture, processing, and evaluation of operating experience concerning age-related 

degradation and aging management during the term of a renewed operating license. The 

acceptable programs are those relied on to meet the requirements of 10 CFR Part 50 

Appendix B and item I.C.5, “Procedures for Feedback of Operating Experience to Plant Staff,” in 

NUREG-0737, “Clarification of TMI Action Plan Requirements,” dated November 1980. 

SRP-LR Section A.4.2 also states that, as part of meeting the requirements of NUREG–0737, 

item I.C.5, the applicant’s operating experience program should rely on active participation in 

the INPO operating experience program (formerly the INPO Significant Event Evaluation and 
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Information Network (SEE-IN) program endorsed in NRC GL 82-04, “Use of INPO SEE-IN 

Program,” dated March 9, 1982).

LRA Section B.1.4 states that the applicant uses its Operating Experience program to 

systematically capture and review operating experience from plant-specific and industry 

sources. The applicant stated that the Operating Experience program meets the requirements 

of NUREG-0737. The applicant further states that the Operating Experience program interfaces 

and relies on active participation in the INPO operating experience program.

Based on this information, the staff determined that the applicant’s Operating Experience 

program is consistent with the programs described in SRP-LR Section A.4.2.

Areas of Further Review

Application of Existing Programs and Procedures to the Processing of Operating Experience 

Related to Aging. SRP-LR Section A.4.2 states that the programs and procedures relied on to 

meet the requirements of 10 CFR Part 50 Appendix B and NUREG-0737, item I.C.5, should not 

preclude the consideration of operating experience on age-related degradation and aging 

management. The applicant stated that operating experience from plant-specific and industry 

sources are systematically captured and reviewed on an ongoing basis in accordance with the 

Quality Assurance program, which is consistent with 10 CFR Part 50 Appendix B, and the INPO 

operating experience program, which is consistent with NUREG-0737, item I.C.5.

LRA Section B.1.4 states that the ongoing evaluation of operating experience included a review 

of corrective actions resulting in plant program enhancements helping to prevent events that 

have occurred at other plants. The LRA states that the operating experience in each AMP 

summary identifies past corrective actions that have resulted in program enhancements and 

provides objective evidence that the effects of aging have been, and will continue to be, 

adequately managed so that the intended functions of the SCs within the scope of each 

program will be maintained during the period of extended operation.

Based on this information, the staff determined that the processes implemented under the 

Quality Assurance program, the corrective action program, and the enhanced Operating 

Experience program would not preclude consideration of age-related operating experience, 

which is consistent with the guidance in SRP-LR Section A.4.2. In addition, SRP-LR 

Section A.4.2 states that the applicant should use the option described in SRP-LR Appendix A.2 

to expand the scope of the 10 CFR Part 50 Appendix B program to include nonsafety-related 

SCs. In addition, LRA Section B.1.3 states that the applicant’s Quality Assurance Program 

includes nonsafety-related SCs, which the staff finds consistent with the guidance in SRP-LR 

Section A.2, and is, therefore, consistent with SRP-LR Section A.4.2 as well. SER Section 3.0.4 

documents the staff’s evaluation of LRA Section B.1.3.

Consideration of Guidance Documents as Industry Operating Experience. SRP-LR

Section A.4.2 states that NRC and industry guidance documents and standards applicable to 

aging management, including revisions to the GALL Report, should be considered as sources of 

industry operating experience and evaluated accordingly.

LRA Section B.1.4 states that the sources of external operating experience include INPO 

documents; NRC documents and other documents, such as licensee event reports and 

10 CFR Part 21, “Reporting of Defects and Noncompliance,” reports; and the OPEX process, 

which interfaces with, and relies on, active participation in the INPO operating experience 
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program. The applicant also listed additional external sources that include LR-ISGs and 

GALL Report revisions.

The staff finds the sources of industry operating experience acceptable because the applicant 

will consider an appropriate breadth of industry operating experience for impacts to its aging 

management activities, which includes sources that the staff considers to be the primary 

sources of external operating experience information. The applicant’s consideration of industry 

guidance documents as operating experience is, therefore, consistent with the guidance in 

SRP-LR Section A.4.2.

Screening of Incoming Operating Experience. SRP-LR Section A.4.2 states that all incoming 

plant-specific and industry operating experience should be screened to determine whether it 

involves age-related degradation or impacts to aging management activities. LRA Section B.1.4 

states that the LSCS personnel receive and review operating experience (internal and external 

to Exelon) on a daily basis. The applicant has an OPEX process that interfaces with, and relies 

on, active participation in the INPO operating experience program. The applicant states that the 

OPEX process includes screening, evaluation, and acting on operating experience documents 

and information to prevent or mitigate the consequences of similar events. The applicant also 

states that the OPEX process includes review of operating experience from external and 

internal sources.

LRA Section A.1.6, “Operating Experience,” states that the Operating Experience program 

conforms to the recommendations of LR-ISG-2011-05, “Ongoing Review of Operating 

Experience.” In accordance with this program, all incoming operating experience items are 

screened to determine whether they may involve age-related degradation or aging management 

impacts. Items so identified are further evaluated, and the AMPs are either enhanced or new 

AMPs are developed, as appropriate, when it is determined through these evaluations that the 

effects of aging may not be adequately managed.

The staff finds the applicant’s operating experience review processes acceptable because these 

processes include screening of all new operating experience to identify and evaluate items that 

have the potential to impact the aging management activities. The applicant’s screening of 

plant-specific and industry operating experience is, therefore, consistent with the guidance in 

SRP-LR Section A.4.2.

Identification of Operating Experience Related to Aging. SRP-LR Section A.4.2 states that 

coding should be used within the plant corrective action program to identify operating 

experience involving age-related degradation applicable to the plant. The SRP-LR also states 

that the associated entries should be periodically reviewed and that any adverse trends should 

receive further evaluation.

The applicant’s screening and evaluation of a potential aging issues procedure provides

guidance to perform an ongoing review of internal and external operating experience to identify 

areas where AMPs credited during license renewal process should be informed, updated, and 

enhanced when necessary or where new AMPs should be developed so that the intended 

functions of the structures and passive components are maintained. The applicant also states 

that NRC ISG and the new GALL Report recommendations are evaluated and incorporated if 

applicable, and, as part of the periodic UFSAR update in accordance with 10 CFR 54.37(b), 

their site engineering will determine whether there are any newly identified SSCs that require 

aging management.
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The staff finds the applicant’s identification of operating experience related to aging acceptable 

because the applicant has a means at a programmatic level to identify, trend, and evaluate 

operating experience that involves age-related degradation. The applicant’s identification of 

age-related operating experience applicable to the plants is, therefore, consistent with the 

guidance in SRP-LR Section A.4.2.

Information Considered in Operating Experience Evaluations. SRP-LR Section A.4.2 states that 

operating experience identified as involving aging should receive further evaluation based on 

consideration of information, such as the affected SSCs, materials, environments, aging effects, 

aging mechanisms, and AMPs. The SRP-LR also states that actions should be initiated within 

the corrective action program to either enhance the AMPs or develop and implement new AMPs 

if it is found through an operating experience evaluation that the effects of aging may not be 

adequately managed.

LRA Section B.1.4 states that operating experience is used at LSCS to enhance plant 

programs, prevent repeat events, and prevent events that have occurred at other plants. In 

addition, as part of the Exelon fleet, LSCS personnel receive operating experience (internal and 

external to Exelon) daily. The LRA also states that the OPEX process includes screening, 

evaluation, and acting on operating experience documents and information to prevent or 

mitigate the consequences of similar events, including review of operating experience from 

external and internal sources and external operating experience from INPO and the NRC. 

Internal operating experience includes event investigations, trending reports, and lessons 

learned from in-house events as captured in program health reports, program assessments, and 

the corrective action program.

The staff determined that the applicant’s evaluations of age-related operating experience will 

include the assessment of appropriate information to determine potential impacts to the aging 

management activities. The staff also determined that the applicant’s Operating Experience 

program, in conjunction with the corrective action program, will implement any changes 

necessary to manage the effects of aging, as determined through its operating experience 

evaluations. Therefore, the staff finds that the information considered in the applicant’s 

operating experience evaluations and use of the Operating Experience program and corrective 

action program to ensure that the effects of aging are adequately managed is consistent with 

the guidance in SRP-LR Section A.4.2.

Evaluation of AMP Implementation Results. SRP-LR Section A.4.2 states that the results of 

implementing the AMPs, such as data from inspections, tests, and analyses, should be 

evaluated regardless of whether the acceptance criteria of the particular AMP have been met. 

SRP-LR Section A.4.2 states that this information should be used to determine whether it is 

necessary to adjust the inspection activities for aging management. In addition, 

SRP-LR Section A.4.2 states that actions should be initiated within the plant corrective action 

program to either enhance the AMPs or develop and implement new AMPs if these evaluations 

indicate that the effects of aging may not be adequately managed.

LRA Section A.1.6 states that the Exelon fleet OPEX program that is implemented at LSCS 

conforms to the recommendations of LR-ISG-2011-05, “Ongoing Review of Operating 

Experience.” In accordance with this program, all incoming operating experience items are 

screened to determine whether they may involve age-related degradation or aging management 

impacts. Items so identified are further evaluated, and the AMPs are either enhanced or new 

AMPs are developed, as appropriate, when it is determined through these evaluations that the 

effects of aging may not be adequately managed.
3-163

The staff reviewed the LRA and finds the applicant’s treatment of AMP implementation results 

as operating experience acceptable because the applicant will evaluate these results and use 

the information to determine whether to adjust the aging management activities. The applicant’s 

activities for the evaluation of AMP implementation results are, therefore, consistent with the 

guidance in SRP-LR Section A.4.2.

Training. SRP-LR Section A.4.2 states that training on age-related degradation and aging 

management should be provided to those personnel responsible for implementing the AMPs 

and those personnel that may submit, screen, assign, evaluate, or otherwise process 

plant-specific and industry operating experience. SRP-LR Section A.4.2 also states that the 

training should be periodic and include provisions to accommodate the turnover of plant 

personnel.

LRA Section A.1.6 states that the Operating Experience program procedures include training for

personnel responsible for submitting, screening, assigning, evaluating, or otherwise processing 

plant-specific and industry operating experience concerning age-related degradation and aging 

management and training for personnel responsible for implementing AMPs based on the 

complexity of the job performance requirements and assigned responsibilities.

The staff reviewed the LRA and operating experience procedure showing that periodic training 

is provided to personnel who have direct responsibility for AMP effectiveness or who provide a

supporting role in the process, and it determined that the scope of personnel included in the 

applicant’s training program are consistent with the guidelines in SRP-LR Section A.4.2. The 

staff also determined that the applicant has demonstrated that its training program covers

age-related degradation and aging management topics and that its ongoing actions of training 

and ongoing review of OPEX are in place. The staff finds the applicant’s OPEX training 

activities are, therefore, consistent with the guidance in SRP-LR Section A.4.2.

Reporting Operating Experience to the Industry. SRP-LR Section A.4.2 states that guidelines 

should be established for reporting plant-specific operating experience on age-related 

degradation and aging management to the industry. The staff finds the applicant’s reporting of 

its plant-specific operating experience, associated with aging management and age-related 

degradation, to the industry in accordance with the guidelines established in its program to be 

acceptable because the applicant has established appropriate expectations and guidelines for 

identifying plant-specific operating experience concerning aging management and age-related 

degradation to the industry. The applicant’s establishment of these guidelines is, therefore, 

consistent with the guidance in SRP-LR Section A.4.2.

Schedule for Implementing the Operating Experience Review Activities. SRP-LR Section A.4.2 

states that the operating experience review activities should be implemented no later than the 

date on which the renewed license is issued; these activities should then be implemented on an 

ongoing basis throughout the term of a renewed license.

LRA Section B.1.4 states that the Operating Experience program will be implemented on an 

ongoing basis throughout the terms of the renewed licenses. In addition, LRA Section A.1.6

provides the UFSAR supplement summary description of the applicant’s programmatic activities 

for ongoing review of the operating experience. On issuance of the renewed licenses, this 

summary description will be incorporated into each plant’s CLB. At that time, the applicant will 

be obligated to conduct its operating experience review activities accordingly.
3-164

The staff finds the implementation schedule acceptable because the applicant will implement 

the operating experience review activities on an ongoing basis throughout the term of the 

renewed operating licenses.

Summary

Based on its review of the LRA, the staff determined that the applicant’s programmatic activities 

for the ongoing review of operating experience are acceptable for (a) the systematic review of 

plant-specific and industry operating experience to ensure that the license renewal AMPs are,

and will continue to be, effective in managing the aging effects for which they are credited and 

(b) the enhancement of AMPs or development of new AMPs when it is determined through the 

evaluation of operating experience that the effects of aging may not be adequately managed. 

Based on the completion of the staff’s review and the consistency of the applicant’s operating 

experience review activities with the guidance in LR-ISG-2011-05, the staff finds the applicant’s 

programmatic activities for the ongoing review of operating experience acceptable.

3.0.5.3 UFSAR Supplement

In accordance with 10 CFR 54.21(d), the UFSAR supplement must contain a summary 

description of the programs and activities for managing the effects of aging. LRA Section A.1.6

provides the UFSAR supplement summary description of the applicant’s programmatic activities 

for the ongoing review of operating experience.

The staff reviewed LRA Section A.1.6 and found that the summary description of the ongoing 

evaluation of operating experience related to aging management states that LSCS will consider 

age-related degradation or aging management impacts.

SRP-LR Section A.4.2, as established in LR-ISG-2011-05, states that the programmatic 

activities for the ongoing review of plant-specific and industry operating experience concerning 

age-related degradation and aging management should be described in the UFSAR 

supplement. LR-ISG-2011-05 also revises SRP-LR Table 3.0-1 to include example summary 

description language for the UFSAR supplement. The staff reviewed the content of LRA 

Section A.1.6 against the example language in SRP-LR Table 3.0-1. Based on its review, the 

staff determined that the content of the applicant’s summary description is consistent with the 

example and also sufficiently comprehensive to describe the applicant’s programmatic activities 

for evaluating operating experience to maintain the effectiveness of the AMPs. Therefore, the 

staff finds the applicant’s UFSAR supplement summary description acceptable.

3.0.5.4 Conclusion

Based on its review of the applicant’s programmatic activities for the ongoing review of 

operating experience, the staff concludes that the applicant has demonstrated that operating 

experience will be reviewed to ensure that the effects of aging will be adequately managed so 

that the intended function(s) will remain consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for these activities and concludes that it provides an adequate summary description, as required 

by 10 CFR 54.21(d).
3-165

3.1 Aging Management of Reactor Vessel, Internals and Reactor Coolant System

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

Reactor Vessel, Internals, and Reactor Coolant System components and component groups of

the following:

• Reactor Coolant Pressure Boundary System

• Reactor Vessel

• Reactor Vessel Internals

3.1.1 Summary of Technical Information in the Application

LRA Section 3.1 provides AMR results for the Reactor Vessel, Internals, and Reactor Coolant 

System components and component groups. LRA Table 3.1.1, “Summary of Aging 

Management Evaluations for the Reactor Vessel, Internals, and Reactor Coolant System,” is a 

summary comparison of the applicant’s AMRs with those evaluated in the GALL Report for the 

Reactor Vessel, Internals, and Reactor Coolant System components and component groups.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report.

3.1.2 Staff Evaluation

The staff reviewed LRA Section 3.1 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the Reactor Vessel, Internals, and 

Reactor Coolant System components, within the scope of license renewal and subject to an 

AMR, will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

The staff conducted a review of the applicant’s AMRs to verify its claim that certain AMRs are 

consistent with the GALL Report or are not applicable. The staff did not repeat its review of the 

matters described in the GALL Report; however, the staff did verify that the material presented 

in the LRA is applicable and that the applicant identified the appropriate GALL Report AMRs. 

AMRs that the staff confirmed are consistent with the GALL Report are noted as such in 

Table 3.1-1; therefore, no further discussion is required. AMRs that the staff confirmed are not 

applicable to LSCS or that require no aging management are noted in Table 3.1-1 and 

discussed in SER Section 3.1.2.1.1. Details of the staff’s evaluation of AMRs that the applicant 

claimed are consistent with the GALL Report, but for which a different AMP from the program 

recommended in the GALL Report is used to manage aging, and AMRs for which the staff 

requested additional information, are documented in SER Sections 3.1.2.1.2 through 3.1.2.1.4.

During its review, the staff also reviewed AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

are consistent with the SRP-LR Section 3.1.2.2 acceptance criteria. The staff’s evaluations of 

AMRs for which the GALL Report recommends further evaluation are documented in SER 

Section 3.1.2.2.
3-166

The staff also conducted a technical review of the remaining AMRs that are not consistent with 

or are not addressed in the GALL Report. The technical review evaluated whether all plausible 

aging effects have been identified and whether the aging effects listed are appropriate for the 

material-environment combinations specified. The staff’s evaluations of AMRs that are not 

consistent with or are not addressed in the GALL Report are documented in SER 

Section 3.1.2.3.

Table 3.1-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.1 and addressed in the GALL Report.

Staff Evaluation for Reactor Vessel, Internals and Reactor Coolant System 

Components in the GALL Report

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

High strength, 

low-alloy steel top 

head closure stud 

assembly exposed 

to air with potential 

for reactor coolant 

leakage (3.1.1-1)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.1)

Nickel alloy tubes 

and sleeves 

exposed to reactor 

coolant and 

secondary 

feedwater/steam 

(3.1.1-2)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.2.1)

Stainless steel or 

nickel alloy reactor 

vessel internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-3)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.1)

Steel pressure 

vessel support skirt 

and attachment 

welds (3.1.1-4)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.1)
3-167

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel, stainless 

steel, or steel (with 

stainless steel or 

nickel alloy cladding) 

steam generator 

components, 

pressurizer relief 

tank components or 

piping components 

or bolting (3.1.1-5)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.2.1)

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), or 

stainless steel; or 

nickel alloy reactor 

coolant pressure 

boundary 

components: piping, 

piping components, 

and piping elements 

exposed to reactor 

coolant (3.1.1-6)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(see SRP, Section 

4.3 “Metal Fatigue,”

for acceptable 

methods to comply 

with 

10 CFR 54.21(c)(1))

Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.1.2.2.1)

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), or 

stainless steel; or 

nickel alloy reactor 

vessel components: 

flanges; nozzles; 

penetrations; safe 

ends; thermal 

sleeves; vessel 

shells, heads and 

welds exposed to 

reactor coolant 

(3.1.1-7)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(see SRP, Section

4.3 “Metal Fatigue,”

for acceptable 

methods to comply 

with 

10 CFR 54.21(c)(1))

Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.1.2.2.1)

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), or 

stainless steel; or 

nickel alloy steam 

generator 

components 

exposed to reactor 

coolant (3.1.1-8)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(see SRP, Section

4.3 “Metal Fatigue,”

for acceptable 

methods to comply 

with 

10 CFR 54.21(c)(1))

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.2.1)
3-168

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), stainless 

steel; nickel alloy 

RCPB piping; 

flanges; nozzles & 

safe ends; 

pressurizer shell 

heads & welds; 

heater sheaths & 

sleeves; 

penetrations; 

thermal sleeves 

exposed to reactor 

coolant (3.1.1-9)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(see SRP, Section

4.3 “Metal Fatigue,”

for acceptable 

methods to comply 

with 

10 CFR 54.21(c)(1))

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.2.1)

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), stainless 

steel; nickel alloy 

reactor vessel 

flanges; nozzles; 

penetrations; 

pressure housings; 

safe ends; thermal 

sleeves; vessel 

shells, heads and 

welds exposed to 

reactor coolant 

(3.1.1-10)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(see SRP, Section

4.3 “Metal Fatigue,”

for acceptable 

methods to comply 

with 

10 CFR 54.21(c)(1))

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.2.1)

Steel or stainless 

steel pump and 

valve closure bolting 

exposed to high 

temperatures and 

thermal cycles 

(3.1.1-11)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation; check 

ASME Code limits 

for allowable cycles 

(less than 7,000 

cycles) of thermal 

stress range (see 

SRP Section 4.3 

“Metal Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.1.2.2.1)
3-169

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel steam 

generator 

components: upper 

and lower shells, 

transition cone; new 

transition cone 

closure weld 

exposed to 

secondary feedwater 

or steam (3.1.1-12)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry,”

and, for 

Westinghouse Model 

44 and 51 S/G, if 

corrosion of the shell 

is found, additional 

inspection 

procedures are 

developed

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.2.2)

Steel (with or without 

stainless steel 

cladding) reactor 

vessel beltline shell, 

nozzles, and welds 

exposed to reactor 

coolant and neutron 

flux (3.1.1-13)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement

TLAA is to be 

evaluated in 

accordance with 

Appendix G of 

10 CFR Part 50 and 

RG 1.99. The 

applicant may 

choose to 

demonstrate that the 

materials of the 

nozzles are not 

controlling for the 

TLAA evaluations

Yes TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.3)

Steel (with or without 

cladding) reactor 

vessel beltline shell, 

nozzles, and welds; 

safety injection 

nozzles (3.1.1-14)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement

Chapter XI.M31, 

“Reactor Vessel 

Surveillance”

Yes Reactor Vessel 

Surveillance

An exception 

applies to the 

Reactor Vessel 

Surveillance 

program

Consistent with the 

GALL Report

(see SER 

Section 3.1.2.2.3)

Stainless steel 

Babcock & Wilcox 

(including CASS, 

martensitic SS, and 

PH SS) and nickel 

alloy reactor vessel 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-15)

Reduction of

ductility and 

fracture 

toughness due 

to neutron 

irradiation

embrittlement, 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement

Ductility - Reduction 

in fracture toughness 

is a TLAA to be 

evaluated for the 

period of extended 

operation, see the 

SRP, Section 4.7, 

“Other Plant-Specific 

TLAAs,” for 

acceptable methods 

of meeting the 

requirements of 

10 CFR 54.21(c).

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.2.3)
3-170

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel and 

nickel alloy top head 

enclosure vessel 

flange leak detection 

line (3.1.1-16)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

A plant-specific 

aging management 

program is to be 

evaluated because 

existing programs 

may not be capable 

of mitigating or 

detecting crack 

initiation and growth 

due to SCC in the 

vessel flange leak 

detection line

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.1.2.2.4)

Stainless steel 

isolation condenser 

components 

exposed to reactor 

coolant (3.1.1-17)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry”

for BWR water, and 

a plant-specific 

verification program

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.1.2.2.4)

Reactor vessel shell 

fabricated of 

SA508-Cl 2 forgings 

clad with stainless 

steel using a 

high-heat-input 

welding process 

exposed to reactor 

coolant (3.1.1-18)

Crack growth 

due to cyclic 

loading

Growth of 

intergranular 

separations is a 

TLAA evaluated for 

the period of 

extended operation.

The Standard 

Review Plan, 

Section 4.7, “Other 

Plant-Specific 

Time-Limited Aging 

Analysis,” provides 

guidance for meeting 

the requirements of 

10 CFR 54.21(c))

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.2.5)

Stainless steel 

reactor vessel 

closure head flange 

leak-detection line 

and bottom-mounted 

instrument guide 

tubes (external to 

reactor vessel) 

(3.1.1-19)

Cracking due to 

stress corrosion 

cracking

A plant-specific 

aging management 

program is to be 

evaluated

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.2.6)

Cast austenitic 

stainless steel 

Class 1 piping, 

piping components, 

and piping elements 

exposed to reactor 

coolant (3.1.1-20)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry”

and, for CASS 

components that do 

not meet the 

NUREG-0313 

guidelines, a 

plant-specific aging 

management 

program

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.2.6)
3-171

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel and stainless 

steel isolation 

condenser 

components 

exposed to reactor 

coolant (3.1.1-21)

Cracking due to 

cyclic loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components. 

The ISI program is to 

be augmented by a 

plant-specific 

verification program

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.1.2.2.7)

Steel steam 

generator feedwater 

impingement plate 

and support exposed 

to secondary 

feedwater (3.1.1-22)

Loss of material 

due to erosion

A plant-specific 

aging management 

program is to be 

evaluated

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.2.8)

SRP-LR Item No.

(3.1.1-23) Deleted 

by LR-ISG-2011-04

N/A N/A N/A N/A N/A

SRP-LR Item No.

(3.1.1-24) Deleted 

by LR-ISG-2011-04

N/A N/A N/A N/A N/A

Steel (with nickelalloy cladding) or 

nickel alloy steam 

generator primary 

side components: 

divider plate and 

tube-to-tube sheet 

welds exposed to 

reactor coolant 

(3.1.1-25)

Cracking due to 

primary water 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry”

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.2.11)

SRP-LR Item No.

(3.1.1-26) Deleted 

by LR-ISG-2011-04

N/A N/A N/A N/A N/A

SRP-LR Item No.

(3.1.1-27) Deleted 

by LR-ISG-2011-04

N/A N/A N/A N/A N/A

Stainless steel 

Combustion 

Engineering 

“Existing Programs” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-28)

Loss of material 

due to wear; 

cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only)

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-172

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Nickel alloy core 

shroud and core 

plate access hole 

cover (welded 

covers) exposed to 

reactor coolant 

(3.1.1-29)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry,”

and for BWRs with a 

crevice in the access 

hole covers, 

augmented 

inspection using UT 

or other acceptable 

techniques

No BWR Vessel 

Internals and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.1.2)

Stainless steel or 

nickel alloy 

penetration: drain 

line exposed to 

reactor coolant 

(3.1.1-30)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, cyclic 

loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry”

No ASME Section XI 

Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD 

and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Steel and stainless 

steel isolation 

condenser 

components 

exposed to reactor 

coolant (3.1.1-31)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection,

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry”

No One-Time 

Inspection and

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Stainless steel, 

nickel alloy, or CASS 

reactor vessel 

internals, core 

support structure

(not already 

referenced in ASME 

Section XI 

Examination 

Category B-N-3 core 

support structure 

components in MRP227-A), exposed to 

reactor coolant and 

neutron flux

(3.1.1-32)

Cracking, or 

loss of material 

due to wear

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” or 

Chapter XI.M16A, 

“PWR Vessel 

Internals,” invoking 

applicable 10 CFR 

50.55a and ASME 

Section XI inservice 

inspection 

requirements for 

these components

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel, steel 

with stainless steel 

cladding Class 1 

reactor coolant 

pressure boundary 

components 

exposed to reactor 

coolant (3.1.1-33)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

ASME components, 

and Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-173

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel, steel 

with stainless steel 

cladding pressurizer 

relief tank (tank shell 

and heads, flanges, 

nozzles) exposed to 

treated borated 

water >60°C 

(>140°F) (3.1.1-34)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

ASME components, 

and Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel, steel 

with stainless steel 

cladding reactor 

coolant system cold 

leg, hot leg, surge 

line, and spray line 

piping and fittings 

exposed to reactor 

coolant (3.1.1-35)

Cracking due to 

cyclic loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel, stainless steel 

pressurizer integral 

support exposed to 

air with metal 

temperature up to 

288°C (550°F) 

(3.1.1-36)

Cracking due to 

cyclic loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel reactor vessel 

flange (3.1.1-37)

Loss of material 

due to wear

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Cast austenitic 

stainless steel 

Class 1 pump 

casings, and valve 

bodies and bonnets 

exposed to reactor 

coolant >250 deg-C 

(>482 deg-F) 

(3.1.1-38)

Loss of fracture 

toughness due 

to thermal aging 

embrittlement

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components.

For pump casings 

and valve bodies, 

screening for 

susceptibility to 

thermal aging is not 

necessary.

No ASME Section XI 

Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD,

Consistent with the 

GALL Report
3-174

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel, stainless 

steel, or steel with 

stainless steel 

cladding Class 1 

piping, fittings and 

branch connections 

< NPS 4 exposed to 

reactor coolant 

(3.1.1-39)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking (for 

stainless steel 

only), and 

thermal, 

mechanical, and 

vibratory loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components,

Chapter XI.M2, 

“Water Chemistry,”

and XI.M35, “Onetime Inspection of 

ASME Code Class 1

Small-bore Piping”

No ASME Section XI 

Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD,

Water Chemistry, 

and either

Unit 1 One-time 

Inspection of 

ASME Code 

Class 1 SmallBore Piping, or

Unit 2 Inspection 

of ASME Code 

Class 1 SmallBore Piping

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Steel with stainless 

steel or nickel alloy 

cladding; or stainless 

steel pressurizer 

components 

exposed to reactor 

coolant (3.1.1-40)

Cracking due to 

cyclic loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Nickel alloy core 

support pads; core 

guide lugs exposed 

to reactor coolant 

(3.1.1-40x)

Cracking due to 

primary water 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Nickel alloy core 

shroud and core 

plate access hole 

cover (mechanical 

covers) exposed to 

reactor coolant 

(3.1.1-41)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.1.2.1.1)
3-175

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel with stainless 

steel or nickel alloy 

cladding or stainless 

steel primary side 

components; steam 

generator upper and 

lower heads, and 

tube sheet weld; or 

pressurizer 

components 

exposed to reactor 

coolant (3.1.1-42)

Cracking due to 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and 

Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel and 

nickel-alloy reactor 

vessel internals 

exposed to reactor 

coolant (3.1.1-43)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry”

No BWR Vessel 

Internals and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.1.3)

Steel steam 

generator secondary 

manways and 

handholds (cover 

only) exposed to air 

with leaking 

secondary-side 

water and/or steam 

(3.1.1-44)

Loss of material 

due to erosion

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 2 components

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Nickel alloy and 

steel with nickelalloy cladding 

reactor coolant 

pressure boundary 

components 

exposed to reactor 

coolant (3.1.1-45)

Cracking due to 

primary water 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

ISI, IWB, IWC & 

IWD,” and 

Chapter XI.M2, 

“Water Chemistry,”

and, for nickel-alloy, 

Chapter XI.M11B, 

“Cracking of NickelAlloy Components 

and Loss of Material 

Due to Boric Acidinduced Corrosion in 

RCPB Components 

(PWRs Only)”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-176

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel, 

nickel-alloy, nickelalloy welds and/or 

buttering control rod 

drive head 

penetration pressure 

housing or nozzles 

safe ends and welds 

(inlet, outlet, safety 

injection) exposed to 

reactor coolant 

(3.1.1-46)

Cracking due to 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

ISI, IWB, IWC & 

IWD,” and Chapter 

XI.M2, “Water 

Chemistry,”

and, for nickel-alloy, 

Chapter XI.M11B, 

“Cracking of NickelAlloy Components 

and Loss of Material 

Due to Boric Acidinduced corrosion in 

RCPB Components 

(PWRs Only)”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel, 

nickel-alloy control 

rod drive head 

penetration pressure 

housing exposed to 

reactor coolant 

(3.1.1-47)

Cracking due to 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

ISI, IWB, IWC & 

IWD,” and 

Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel external 

surfaces: reactor 

vessel top head, 

reactor vessel 

bottom head, reactor 

coolant pressure 

boundary piping or 

components 

adjacent to dissimilar 

metal (Alloy 82/182) 

welds exposed to air 

with borated water 

leakage (3.1.1-48)

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion,” and 

Chapter XI.M11B, 

“Cracking of NickelAlloy Components 

and Loss of Material 

Due to Boric AcidInduced Corrosion in 

RCPB Components 

(PWRs Only)”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel reactor coolant 

pressure boundary 

external surfaces or 

closure bolting 

exposed to air with 

borated water 

leakage (3.1.1-49)

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Cast austenitic 

stainless steel 

Class 1 piping, 

piping component, 

and piping elements 

and control rod drive 

pressure housings 

exposed to reactor 

coolant >250 deg-C 

(>482 deg-F)

(3.1.1-50)

Loss of fracture 

toughness due 

to thermal aging 

embrittlement

Chapter XI.M12, 

“Thermal Aging 

Embrittlement of 

Cast Austenitic 

Stainless Steel 

(CASS)”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.1.2.1.1)
3-177

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel or 

nickel alloy Babcock 

& Wilcox reactor 

internal “Primary” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-51a)

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only)

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy Babcock 

& Wilcox reactor 

internal “Expansion” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-51b)

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, 

fatigue, or 

overload

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only)

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy 

Combustion 

Engineering reactor 

internal “Primary” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-52a)

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only)

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy 

Combustion 

Engineering reactor 

internal “Expansion” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-52b)

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only)

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy 

Combustion 

Engineering reactor 

internal “Existing 

Programs” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-52c)

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only)

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy 

Westinghouse 

reactor internal 

“Primary” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-53a)

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only)

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-178

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel 

Westinghouse 

reactor internal 

“Expansion” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-53b)

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only)

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy 

Westinghouse 

reactor internal 

“Existing Programs” 

components

exposed to reactor 

coolant and neutron 

flux (3.1.1-53c)

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only)

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel 

bottom mounted 

instrument system 

flux thimble tubes 

(with or without 

chrome plating) 

exposed to reactor 

coolant and neutron 

flux (Westinghouse 

“Existing Programs”

components) 

(3.1.1-54)

Loss of material 

due to wear

Chapter XI.M16A, 

“PWR Vessel 

Internals,” or

Chapter XI.M37, 

“Flux Thimble Tube 

Inspection”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy Babcock 

& Wilcox reactor 

internal “No 

Additional 

Measures” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-55a)

No additional 

aging 

management for 

reactor internal 

“No Additional 

Measures” 

components 

unless required 

by ASME 

Section XI, 

Examination 

Category B-N-3 

or relevant 

operating 

experience 

exists

Chapter XI.M16a, 

“PWR Vessel 

Internals”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-179

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel or 

nickel alloy 

Combustion 

Engineering reactor 

internal “No 

Additional 

Measures” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-55b)

No additional 

aging 

management for 

reactor internal 

“No Additional 

Measures” 

components 

unless required 

by ASME 

Section XI, 

Examination 

Category B-N-3 

or relevant 

operating 

experience 

exists

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy 

Westinghouse 

reactor internal “No 

Additional 

Measures” 

components

exposed to reactor 

coolant and neutron 

flux (3.1.1-55c)

No additional 

aging 

management for 

reactor internal 

“No Additional 

Measures” 

components 

unless required 

by ASME 

Section XI, 

Examination 

Category B-N-3 

or relevant 

operating 

experience 

exists

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) or nickel alloy 

Combustion 

Engineering reactor 

internal “Primary” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-56a)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation or 

creep; or loss of 

material due to 

wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-180

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) Combustion 

Engineering 

“Expansion” reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-56b)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation or 

creep; or loss of 

material due to 

wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) or nickel alloy 

Combustion 

Engineering reactor 

internal “Existing 

Programs” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-56c)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation or 

creep; or loss of 

material due to 

wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

The SRP-LR, as 

amended by ISGs, 

does not list an Item 

No. (3.1.1-57)

N/A N/A N/A N/A N/A
3-181

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) or nickel alloy 

Babcock & Wilcox 

reactor internal 

“Primary” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-58a)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to wear; or 

loss of material 

due to wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) or nickel alloy 

Babcock & Wilcox 

reactor internal 

“Expansion” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-58b)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation or 

creep; or loss of 

material due to 

wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-182

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) or nickel alloy 

Westinghouse 

reactor internal 

“Primary” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-59a)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation or 

creep; or loss of 

material due to 

wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) Westinghouse 

reactor internal 

“Expansion” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-59b)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation or 

creep; or loss of 

material due to 

wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-183

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) or nickel alloy 

Westinghouse 

reactor internal 

“Existing Programs” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-59c)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation or 

creep; or loss of 

material due to 

wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to reactor 

coolant (3.1.1-60)

Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Flow-Accelerated 

Corrosion

An exception 

applies to the 

Flow-Accelerated 

Corrosion 

program

Consistent with the 

GALL Report

Steel steam 

generator steam 

nozzle and safe end, 

feedwater nozzle 

and safe end, AFW 

nozzles and safe 

ends exposed to 

secondary 

feedwater/steam 

(3.1.1-61)

Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

High-strength, low 

alloy steel, or 

stainless steel 

closure bolting; 

stainless steel 

control rod drive 

head penetration 

flange bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-62)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M18, 

“Bolting Integrity”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-184

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel or stainless 

steel closure bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-63)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion or 

wear

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Steel closure bolting 

exposed to air –

indoor uncontrolled 

(3.1.1-64)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel 

control rod drive 

head penetration 

flange bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-65)

Loss of material 

due to wear

Chapter XI.M18, 

“Bolting Integrity”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

High-strength, low 

alloy steel, or 

stainless steel 

closure bolting; 

stainless steel 

control rod drive 

head penetration 

flange bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-66)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, 

“Bolting Integrity”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel or stainless 

steel closure bolting 

exposed to air –

indoor with potential 

for reactor coolant 

leakage (3.1.1-67)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Nickel alloy steam 

generator tubes 

exposed to 

secondary feedwater 

or steam (3.1.1-68)

Changes in 

dimension 

(“denting”) due 

to corrosion of 

carbon steel 

tube support 

plate

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Nickel alloy steam 

generator tubes and 

sleeves exposed to 

secondary feedwater 

or steam (3.1.1-69)

Cracking due to 

outer diameter 

stress corrosion 

cracking and 

intergranular 

attack

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Nickel alloy steam 

generator tubes, 

repair sleeves, and 

tube plugs exposed 

to reactor coolant 

(3.1.1-70)

Cracking due to 

primary water 

stress corrosion 

cracking

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-185

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel, chrome plated 

steel, stainless steel, 

nickel alloy steam 

generator U-bend 

supports including 

anti-vibration bars 

exposed to 

secondary feedwater 

or steam (3.1.1-71)

Cracking due to 

stress corrosion 

cracking or 

other 

mechanism(s); 

loss of material 

due general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel steam 

generator tube 

support plate, tube 

bundle wrapper, 

supports, and 

mounting hardware 

exposed to 

secondary feedwater 

or steam (3.1.1-72)

Loss of material 

due to erosion, 

general, pitting, 

and crevice 

corrosion, 

ligament 

cracking due to 

corrosion

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Nickel alloy steam 

generator tubes and 

sleeves exposed to 

phosphate chemistry 

in secondary 

feedwater or steam 

(3.1.1-73)

Loss of material 

due to wastage 

and pitting 

corrosion

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel steam 

generator upper 

assembly and 

separators including 

feedwater inlet ring 

and support exposed 

to secondary 

feedwater or steam 

(3.1.1-74)

Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel steam 

generator tube 

support lattice bars 

exposed to 

secondary feedwater 

or steam (3.1.1-75)

Wall thinning 

due to flowaccelerated 

corrosion and 

general 

corrosion

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel, chrome plated 

steel, stainless steel, 

nickel alloy steam 

generator U-bend 

supports including 

anti-vibration bars 

exposed to 

secondary feedwater 

or steam (3.1.1-76)

Loss of material 

due to fretting

Chapter XI.M19, 

“Steam Generators”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Nickel alloy steam 

generator tubes and 

sleeves exposed to 

secondary feedwater 

or steam (3.1.1-77)

Loss of material 

due to wear and 

fretting

Chapter XI.M19, 

“Steam Generators”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-186

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Nickel alloy steam 

generator 

components such as 

secondary side 

nozzles (vent, drain, 

and instrumentation) 

exposed to 

secondary feedwater 

or steam (3.1.1-78)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection,” or 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD.”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel; steel 

with nickel-alloy or 

stainless steel 

cladding; and nickelalloy reactor coolant 

pressure boundary 

components 

exposed to reactor 

coolant (3.1.1-79)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection and

Water Chemistry

An exception 

applies to the 

Water Chemistry

program

Consistent with the 

GALL Report

Stainless steel or 

steel with stainless 

steel cladding 

pressurizer relief 

tank: tank shell and 

heads, flanges, 

nozzles (noneASME Section XI 

components) 

exposed to treated 

borated water >60°C 

(>140°F) (3.1.1-80)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel 

pressurizer spray 

head exposed to 

reactor coolant 

(3.1.1-81)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Nickel alloy 

pressurizer spray 

head exposed to 

reactor coolant 

(3.1.1-82)

Cracking due to 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel steam 

generator shell 

assembly exposed 

to secondary 

feedwater or steam 

(3.1.1-83)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel top head 

enclosure (without 

cladding) top head 

nozzles (vent, top 

head spray or RCIC, 

and spare) exposed 

to reactor coolant 

(3.1.1-84)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report
3-187

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel, 

nickel-alloy, and 

steel with nickelalloy or stainless 

steel cladding 

reactor vessel 

flanges, nozzles, 

penetrations, safe 

ends, vessel shells, 

heads and welds 

exposed to reactor 

coolant (3.1.1-85)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Stainless steel 

steam generator 

primary side divider 

plate exposed to 

reactor coolant 

(3.1.1-86)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel-alloy PWR 

reactor internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-87)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel; steel 

with nickel-alloy or 

stainless steel 

cladding; and nickelalloy reactor coolant 

pressure boundary 

components 

exposed to reactor 

coolant (3.1.1-88)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to closed 

cycle cooling water 

(3.1.1-89)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Copper alloy piping, 

piping components, 

and piping elements 

exposed to closed 

cycle cooling water 

(3.1.1-90)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

High-strength low 

alloy steel closure 

head stud assembly 

exposed to air with 

potential for reactor 

coolant leakage 

(3.1.1-91)

Cracking due to 

stress corrosion 

cracking; loss of 

material due to 

general, pitting, 

and crevice 

corrosion, or 

wear (BWR)

Chapter XI.M3, 

“Reactor Head 

Closure Stud 

Bolting”

No Reactor Head 

Closure Stud 

Bolting

Exceptions apply 

to the Reactor 

Head Closure 

Stud Bolting 

program

Consistent with the 

GALL Report
3-188

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

High-strength low 

alloy steel closure 

head stud assembly 

exposed to air with 

potential for reactor 

coolant leakage 

(3.1.1-92)

Cracking due to 

stress corrosion 

cracking; loss of 

material due to 

general, pitting, 

and crevice 

corrosion, or 

wear (PWR)

Chapter XI.M3, 

“Reactor Head 

Closure Stud 

Bolting”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Copper alloy >15% 

Zn or > 8% Al piping, 

piping components, 

and piping elements 

exposed to closed 

cycle cooling water 

(3.1.1-93)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching “

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel and 

nickel alloy vessel 

shell attachment 

welds exposed to 

reactor coolant 

(3.1.1-94)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M4, 

“BWR Vessel ID 

Attachment Welds,”

and Chapter XI.M2, 

“Water Chemistry”

No BWR Vessel ID 

Attachment Welds 

and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Steel (with or without 

stainless steel 

cladding) feedwater 

nozzles exposed to 

reactor coolant 

(3.1.1-95)

Cracking due to 

cyclic loading

Chapter XI.M5, 

“BWR Feedwater 

Nozzle”

No BWR Feedwater 

Nozzle

Consistent with the 

GALL Report

Steel (with or without 

stainless steel 

cladding) control rod 

drive return line 

nozzles exposed to 

reactor coolant 

(3.1.1-96)

Cracking due to 

cyclic loading

Chapter XI.M6, 

“BWR Control Rod 

Drive Return Line 

Nozzle”

No BWR Control Rod 

Drive Return Line 

Nozzle

Consistent with the 

GALL Report

Stainless steel and 

nickel alloy piping, 

piping components, 

and piping elements 

greater than or equal 

to 4 NPS; nozzle 

safe ends and 

associated welds 

(3.1.1-97)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M7, 

“BWR Stress 

Corrosion Cracking,”

and Chapter XI.M2, 

“Water Chemistry”

No BWR Stress 

Corrosion 

Cracking,

Water Chemistry, 

and 

ASME Section XI 

Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD 

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.1.4)
3-189

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel or 

nickel alloy 

penetrations: 

instrumentation and 

standby liquid 

control exposed to 

reactor coolant 

(3.1.1-98)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, cyclic 

loading

Chapter XI.M8, 

“BWR Penetrations,”

and Chapter XI.M2, 

“Water Chemistry”

No BWR Penetrations

and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Cast austenitic 

stainless steel; PH 

martensitic stainless 

steel; martensitic 

stainless steel; 

X-750 alloy reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-99)

Loss of fracture 

toughness due 

to thermal aging 

and neutron 

irradiation 

embrittlement

Chapter XI.M9, 

“BWR Vessel 

Internals”

No BWR Vessel 

Internals

Consistent with the 

GALL Report

Stainless steel 

reactor vessel 

internals 

components (jet 

pump wedge 

surface) exposed to 

reactor coolant 

(3.1.1-100)

Loss of material 

due to wear

Chapter XI.M9, 

“BWR Vessel 

Internals”

No BWR Vessel 

Internals

Consistent with the 

GALL Report

Stainless steel 

steam dryers 

exposed to reactor 

coolant (3.1.1-101)

Cracking due to 

flow-induced 

vibration

Chapter XI.M9, 

“BWR Vessel 

Internals” for steam 

dryer

No BWR Vessel 

Internals

Consistent with the 

GALL Report

Stainless steel fuel 

supports and control 

rod drive assemblies 

control rod drive 

housing exposed to 

reactor coolant 

(3.1.1-102)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M9, 

“BWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No BWR Vessel 

Internals and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Stainless steel and 

nickel alloy reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-103)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking

Chapter XI.M9, 

“BWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No BWR Vessel 

Internals and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

X-750 alloy reactor 

vessel internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-104)

Cracking due to 

intergranular 

stress corrosion 

cracking

Chapter XI.M9, 

“BWR Vessel 

Internals” for core 

plate, and Chapter 

XI.M2, “Water 

Chemistry”

No BWR Vessel 

Internals and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report
3-190

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping element 

exposed to concrete 

(3.1.1-105)

None None, provided 

1) attributes of the 

concrete are 

consistent with 

ACI 318 or ACI 349 

(low water-to-cement 

ratio, low 

permeability, and 

adequate air 

entrainment) as cited 

in NUREG-1557, 

and 2) plant OE 

indicates no 

degradation of the 

concrete

No, if 

conditions 

are met.

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.1.2.1.1)

Nickel alloy piping, 

piping components, 

and piping element 

exposed to air –

indoor, uncontrolled, 

or air with borated 

water leakage 

(3.1.1-106)

None None N/A – No 

AEM or 

AMP

Consistent with 

NUREG-1801 (the 

GALL Report)

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping element 

exposed to gas, 

concrete, air with 

borated water 

leakage, air –

indoors, uncontrolled 

(3.1.1-107)

None None N/A – No 

AEM or 

AMP

Consistent with 

NUREG-1801 (the 

GALL Report)

Consistent with the 

GALL Report

The SRP-LR, as 

amended by ISGs, 

does not list an Item 

No. (3.1.1-108)

N/A N/A N/A N/A N/A

The SRP-LR, as 

amended by ISGs, 

does not list an Item 

No. (3.1.1-109)

N/A N/A N/A N/A N/A

Any material, piping, 

piping components, 

and piping elements 

exposed to reactor 

coolant (3.1.1-110)

Wall thinning 

due to erosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.1.2.1.1)

3.1.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.1.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the Reactor Vessel, Internals, and Reactor Coolant System

components:
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• ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

• BWR Control Rod Drive Return Line Nozzle

• BWR Feedwater Nozzle

• BWR Penetrations

• BWR Stress Corrosion Cracking

• BWR Vessel ID Attachment Welds

• BWR Vessel Internals

• Bolting Integrity

• Closed Treated Water Systems

• External Surfaces Monitoring of Mechanical Components

• Flow-Accelerated Corrosion

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

• Lubricating Oil Analysis

• One-Time Inspection

• Selective Leaching

• Unit 1 One-time Inspection of ASME Code Class 1 Small-Bore Piping

• Unit 2 Inspection of ASME Code Class 1 Small-Bore Piping

• Reactor Head Closure Stud Bolting

• Reactor Vessel Surveillance

• TLAA

• Water Chemistry

LRA Tables 3.1.2-1 through 3.1.2-3 summarize the AMR results for the Reactor Vessel, 

Internals, and Reactor Coolant System components and indicate AMRs that were claimed to be 

consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components in these 

GALL Report component groups were bounded by the GALL Report evaluation. The applicant 

provided a note for each AMR item. The notes describe how the information in the tables aligns 

with the information in the GALL Report. The staff audited those AMRs with notes A through E, 

which indicate how the AMR was consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these AMR items to confirm consistency with the GALL Report and the validity 

of the AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff audited these AMR items to confirm consistency with 

the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to 

the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant 

was consistent with the AMP identified in the GALL Report and whether the AMR was valid for 

the site-specific conditions.

Note C indicates that the component for the AMR item, although different from that in the 

GALL Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP is consistent with the AMP identified by the GALL Report. Note C indicates 
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that the applicant was unable to find a listing of some system components in the GALL Report; 

however, the applicant identified a different component in the GALL Report that had the same 

material, environment, aging effect, and AMP as those of the component under review. The 

staff audited these AMR items to confirm consistency with the GALL Report. The staff also 

determined whether the AMR item of the different component applied to the component under 

review and whether the AMR was valid for the site-specific conditions.

Note D indicates that the component for the AMR item, although different from that in the 

GALL Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff 

audited these AMR items to confirm consistency with the GALL Report and confirmed whether 

the AMR item of the different component was applicable to the component under review. The 

staff confirmed whether it had reviewed and accepted the exceptions to the GALL Report AMPs. 

The staff also determined whether the AMP identified by the applicant was consistent with the 

AMP identified in the GALL Report and whether the AMR was valid for the site-specific 

conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect; however, a different AMP is credited. The staff audited these 

AMR items to confirm consistency with the GALL Report and determined whether the identified 

AMP would manage the aging effect consistent with the AMP identified in the GALL Report and 

whether the AMR was valid for the site-specific conditions.

The staff did not repeat its review of the matters described in the GALL Report for those items 

that the staff determined were bounded by the GALL Report evaluation. However, it did confirm 

that the material presented in the LRA was applicable and that the applicant identified the 

appropriate GALL Report AMRs. The staff’s evaluation is discussed below.

AMR Results Identified as Not Applicable or Not Used

For LRA Table 3.1.1, items 3.1.1-2, 3.1.1-5, 3.1.1-8 through 3.1.1-10, 3.1.1-12, 3.1.1-15, 

3.1.1-18 through 3.1.1-20, 3.1.1-22, 3.1.1-25, 3.1.1-28, 3.1.1-32 through 3.1.1-37, 3.1.1-40, 

3.1.1-40x, 3.1.1-42, 3.1.1-44 through 3.1.1-49, 3.1.1-51a through 3.1.1-56c, 3.1.1-58a 

through 3.1.1-59c, 3.1.1-61, 3.1.1-62, 3.1.1-64 through 3.1.1-66, 3.1.1-68 through 3.1.1-78, 

3.1.1-80 through 3.1.1-83, 3.1.1-86 through 3.1.1-90, 3.1.1-92, and 3.1.1-93, the applicant 

claimed that the corresponding AMR items in the GALL Report are not applicable because the 

associated items are only applicable to pressurized water reactors (PWRs). The staff reviewed 

the SRP-LR; confirmed that these items only apply to PWRs; and finds that these items are not 

applicable to LSCS, which is a BWR.

For LRA Table 3.1.1, items 3.1.1-16, 3.1.1-17, 3.1.1-21, 3.1.1-41, 3.1.1-50, and 3.1.1-105, the 

applicant claimed that the corresponding items in the GALL Report are not applicable because 

the component, material, and environment combination described in the SRP-LR does not exist 

for in-scope SCs at LSCS. The staff reviewed the LRA and UFSAR and confirmed that the 

applicant’s LRA does not have any AMR results applicable for these items.

LRA Table 3.1.1, item 3.1.1-110 addresses any material, piping, piping components, and piping 

elements exposed to reactor coolant. The GALL Report recommends GALL Report 

AMP XI.M17, “Flow-Accelerated Corrosion,” to manage wall thinning due to erosion for this 

component group. The applicant stated that this item is not applicable because there are no 

piping, piping components, and piping elements exposed to reactor coolant that have been 
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identified as susceptible to wall thinning due to erosion in the Reactor Vessel, Internals, and 

Reactor Coolant System. The staff evaluated the applicant’s claim and finds it acceptable 

because, during its audit, the staff searched the applicant’s operating experience database and 

did not identify any components in the Reactor Vessel, Internals, and Reactor Coolant System

that were experiencing wall thinning due to erosion.

Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion 

Cracking, and Irradiation-Assisted Stress Corrosion Cracking

LRA Table 3.1.1, item 3.1.1-29 addresses the nickel alloy core shroud and core plate access 

hole cover (welded covers) exposed to reactor coolant, which will be managed for cracking due 

to SCC, IGSCC, and IASCC. For the AMR item that cites generic note E, the LRA credits the 

BWR Vessel Internals program and the Water Chemistry program to manage the aging effects 

for the nickel alloy access hole cover. The GALL Report recommends GALL Report 

AMP XI.M1, “ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD,” and 

GALL Report AMP XI.M2, “Water Chemistry,” to ensure that these aging effects are adequately 

managed.

GALL Report AMP XI.M1 recommends using periodic visual, surface, and/or volumetric 

examination along with GALL Report AMP XI.M2, which recommends monitoring and controlling 

known detrimental contaminants in accordance with the recommendations of BWRVIP-190 to 

manage the aging of this item.

For those AMR items associated with item 3.1.1-29 for which the applicant cited generic note E, 

the applicant substituted GALL Report AMP XI.M1 with the BWR Vessel Internals program. The 

applicant proposes to manage the aging of the nickel alloy core shroud and core plate access 

hole cover (welded covers) exposed to reactor coolant through inspections in accordance with 

component-specific BWRVIP reports that include industry-approved inspection procedures and 

flaw evaluations. The staff noted that the applicant will examine the core shroud access hole 

cover (welded covers) in accordance with BWRVIP-180, which requires the use of EVT-1 or UT. 

The staff also noted that the applicant’s use of its Water Chemistry program is consistent with 

the recommendations of the GALL Report.

The staff’s evaluations of the applicant’s BWR Vessel Internals program and Water Chemistry 

program are documented in SER Sections 3.0.3.2.3 and 3.0.3.2.1, respectively.

Based on its review of components associated with item 3.1.1-29 for which the applicant cited 

generic note E, the staff finds the applicant’s proposal to manage the effects of aging using the 

BWR Vessel Internals program and Water Chemistry program acceptable because the BWR 

Vessel Internals program follows the inspection procedures, flaw evaluations, and repair 

guidelines of BWRVIP guidance and because the Water Chemistry program creates an 

environment that is not conducive for the occurrence of loss of material. These aging 

management activities are consistent with the recommendations of the GALL Report.

The staff concludes that for LRA item 3.1.1-29, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).
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Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.1.1, item 3.1.1-43 addresses stainless steel and nickel alloy reactor vessel 

internals exposed to reactor coolant, which will be managed for loss of material due to pitting 

and crevice corrosion. For the AMR items that cite generic note E, the LRA credits the BWR 

Vessel Internals program and the Water Chemistry program to manage the aging effect for 

stainless steel and nickel alloy reactor vessel internals components. The GALL Report 

recommends GALL Report AMP XI.M1, “ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD,” and GALL Report AMP XI.M2, “Water Chemistry,” to ensure 

that this aging effect is adequately managed.

GALL Report AMP XI.M1 recommends using periodic visual, surface, and/or volumetric 

examination, along with GALL Report AMP XI.M2, which recommends monitoring and 

controlling known detrimental contaminants in accordance with the recommendations of 

BWRVIP-190 to manage the aging of this item. For those AMR items associated with 

item 3.1.1-43, for which the applicant cited generic note E, the applicant substituted 

GALL Report AMP XI.M1 with the BWR Vessel Internals program. The applicant proposes to 

manage the aging of stainless steel and nickel alloy reactor vessel internal components through 

inspections in accordance with component-specific BWRVIP reports that include 

industry-approved inspection procedures and flaw evaluations. The staff noted that the 

BWRVIP guidance requires the use of enhanced inspection methods, such as EVT-1 or UT, in 

lieu of the VT-1 or VT-3 required by inservice inspections. The staff also noted that the 

applicant’s use of its Water Chemistry program is consistent with the recommendations of the 

GALL Report.

The staff’s evaluations of the applicant’s BWR Vessel Internals program and Water Chemistry 

program are documented in SER Sections 3.0.3.2.3 and 3.0.3.2.1, respectively.

Based on its review of components associated with item 3.1.1-43 for which the applicant cited 

generic note E, the staff finds the applicant’s proposal to manage the effects of aging using the 

BWR Vessel Internals program and Water Chemistry program acceptable because the BWR 

Vessel Internals program follows the inspection procedures, flaw evaluations, and repair 

guidelines of BWRVIP guidance and because the Water Chemistry program creates an 

environment not conducive for the occurrence of loss of material. These aging management 

activities are consistent with the recommendations of the GALL Report.

The staff concludes that, for LRA item 3.1.1-43, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion 

Cracking

LRA Table 3.1.1, item 3.1.1-97 addresses stainless steel and nickel alloy piping, piping 

components, and piping elements greater than or equal to NPS 4-inches and reactor vessel 

nozzle safe ends and associated welds exposed to reactor coolant, which will be managed for 

cracking due to SCC (including IGSCC). For AMR items that cite generic note E, the LRA 

credits the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD and the 

Water Chemistry programs to manage the aging effects for pump casings and valve bodies 

made of cast austenitic stainless steel or non-cast stainless steel. The GALL Report
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recommends GALL Report AMP XI.M7, “BWR Stress Corrosion Cracking,” and AMP XI.M2, 

“Water Chemistry,” to ensure that the aging effect is adequately managed for these 

components. GALL Report AMP XI.M7 recommends conducting volumetric examinations on 

BWR piping and piping welds to detect and manage cracking due to SCC. GALL Report 

AMP XI.M2 recommends water chemistry controls to manage aging by limiting the 

concentrations of chemical species known to cause cracking due to SCC.

The staff’s evaluations of the applicant’s ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD program and Water Chemistry program are documented in 

SER Sections 3.0.3.1.1 and 3.0.3.2.1, respectively. The staff noted that the ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD program includes visual, surface, and 

volumetric examinations to manage the effects of aging for the pump casings and valve bodies. 

The staff also noted that the Water Chemistry program manages the effects of aging through 

the use of water chemistry control. Based on its review of the pump casings and valve bodies 

associated with item 3.1.1-97 for which the applicant cited generic note E, the staff finds the 

applicant’s proposal to manage aging using these proposed programs acceptable because the 

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program performs

periodic inspections, which can detect and manage SCC, and because the Water Chemistry 

program limits the concentrations of chemical species (e.g., chloride and sulfate) known to 

cause SCC to minimize the environmental effect on SCC.

The staff concludes that, for LRA item 3.1.1-97, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.1.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation Is 

Recommended

In LRA Section 3.1.2.2, the applicant further evaluated aging management, as recommended by 

the GALL Report, for the Reactor Vessel, Internals, and Reactor Coolant System components 

and provided information on how it will manage the following aging effects:

• cumulative fatigue damage

• loss of material due to general, pitting, and crevice corrosion

• loss of fracture toughness due to neutron irradiation embrittlement

• cracking due to SCC and IGSCC

• crack growth due to cyclic loading

• cracking due to SCC

• cracking due to cyclic loading

• loss of material due to erosion

• cracking due to primary water stress corrosion cracking (PWSCC)

• QA for aging management of nonsafety-related components

• ongoing review of operating experience

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

reviewed the applicant’s evaluation to determine whether it adequately addressed the issues 

further evaluated. In addition, the staff reviewed the applicant’s further evaluations against the 
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criteria contained in SRP-LR Section 3.1.2.2. The staff’s review of the applicant’s further 

evaluation follows.

Cumulative Fatigue Damage

LRA Section 3.1.2.2.1, associated with LRA Table 3.1.1 items 3.1.1-1, 3.1.1-4, 3.1.1-6, 3.1.1-7, 

and 3.1.1-11, addresses cumulative fatigue damage in Reactor Vessel, Internals, and Reactor 

Coolant System components. The applicant addressed the further evaluation criteria of the 

SRP-LR by stating that fatigue is a TLAA, as defined in 10 CFR 54.3, “Definitions,” and is 

required to be evaluated in accordance with 10 CFR 54.21(c). The applicant stated that its 

evaluation of the TLAA is addressed in LRA Section 4.3.

The staff reviewed LRA Section 3.1.2.2.1 against the criteria in SRP-LR Section 3.1.2.2.1, which 

state that cumulative fatigue damage of Reactor Vessel, Internals, and Reactor Coolant System

components is a TLAA and that these TLAAs are to be evaluated in accordance with the TLAA 

acceptance criteria requirements of 10 CFR 54.21(c). The staff reviewed the applicant’s AMR 

items and determined that the AMR results are consistent with the recommendations of the 

GALL Report and SRP-LR for managing cumulative fatigue damage.

LRA Section 3.1.2.2.1 states that TLAAs are evaluated in accordance with 10 CFR 54.21(c) and 

that the evaluation of this TLAA is addressed in LRA Section 4.3. This is consistent with 

SRP-LR Section 3.1.2.2.1 and, therefore, is acceptable. The staff’s evaluation of the TLAA for 

Reactor Vessel, Internals, and Reactor Coolant System components that are being managed for 

cumulative fatigue damage is documented in SER Section 4.3.

LRA Table 3.1.1, item 3.1.1-3, addresses stainless steel or nickel alloy reactor vessel internal 

components exposed to reactor coolant and neutron flux, which will be managed for cumulative 

fatigue damage due to fatigue. The GALL Report recommends that fatigue be evaluated as a 

TLAA to ensure that this aging effect is adequately managed.

LRA Table 3.1.2-3 provides the applicant’s summary of the AMR for the Reactor Vessel 

Internals System. LRA Table 4.3.4-1 provides the bounding cumulative usage factor values for 

the reactor vessel internal components that have been analyzed for fatigue, including the values 

for the access hole cover and the core differential pressure and liquid control line. During its 

review of components associated with item 3.1.1-3, the staff noted that these two components 

are included in LRA Table 3.1.2-3. However, LRA Table 3.1.2-3 does not include cumulative 

fatigue damage as an AERM for either of these components.

By letter dated July 7, 2015, the staff issued RAI 3.1.2.2.1-1, requesting that the applicant justify 

why cumulative fatigue damage is not included as an AERM in LRA Table 3.1.2-3 for the access 

hole cover and the core differential pressure and liquid control line components or revise LRA 

Table 3.1.2-3 to include this effect for these components.

By letter dated August 6, 2015, the applicant responded to RAI 3.1.2.2.1-1. In its response, the 

applicant revised LRA Table 3.1.2-3 to include cumulative fatigue damage as an AERM for the 

access hole cover and the core differential pressure and liquid control line components. The 

applicant also reviewed its reactor internal components listed in LRA Table 4.3.4-1, and noted 

an additional inconsistency. The applicant also revised LRA Table 3.1.2-3 to include cumulative 

fatigue damage as an AERM for the control rod guide tube. For these AMR items, the applicant 

credited generic note A, which the staff noted is consistent with the recommendations in the 

GALL Report. The staff finds the applicant’s response acceptable because LRA Table 3.1.2-3 
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was revised to include cumulative fatigue damage for all of the reactor internal components that 

were analyzed for fatigue, as provided in LRA Table 4.3.4-1. The staff’s concerns in 

RAI 3.1.2.2.1-1 are resolved.

The staff concludes that, for LRA item 3.1.1-3, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

LRA Section 3.1.2.2.1, associated with LRA Table 3.1.1, items 3.1.1-2, 3.1.1-5, 3.1.1-8, 3.1.1-9, 

and 3.1.1-10, addresses cumulative fatigue damage in Reactor Vessel, Internals, and Reactor 

Coolant System components. The criteria in SRP-LR Section 3.1.2.2.1 state that cumulative 

fatigue damage of Reactor Vessel, Internals, and Reactor Coolant System components is a 

TLAA and that these TLAAs are to be evaluated in accordance with the TLAA acceptance 

criteria requirements of 10 CFR 54.21(c). The applicant stated that these items are not 

applicable because they are associated only for PWR components. The staff evaluated the 

applicant’s claim and finds it acceptable because the reactor design at LSCS is a BWR.

Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.1.2.2.2 against the following criteria in SRP-LR 

Section 3.1.2.2.2:

Item 1. LRA Section 3.1.2.2.2, item 1, associated with LRA Table 3.1.1, item 3.1.1-12, 

addresses loss of material caused by general, pitting, and crevice corrosion in steel PWR steam 

generator upper and lower shells and transition cone exposed to secondary feedwater and 

steam. The applicant stated that this item is not applicable because the associated item in LRA 

Table 3.1.1 is applicable to PWRs only. The staff evaluated the applicant’s claim and finds it 

acceptable because the item is applicable only to PWRs and because the applicant’s reactors 

are BWRs that do not have steam generators.

Item 2. LRA Section 3.1.2.2.2, item 2, associated with LRA Table 3.1.1, item 3.1.1-12, 

addresses loss of material caused by general, pitting, and crevice corrosion in the steel PWR 

steam generator shell assembly exposed to secondary feedwater and steam. The applicant 

stated that this item is not applicable because the associated item in LRA Table 3.1.1 is 

applicable to PWRs only. The staff evaluated the applicant’s claim and finds it acceptable 

because the item is applicable only to PWRs and because the applicant’s reactors are BWRs 

that do not have steam generators.

Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement

The staff reviewed LRA Section 3.1.2.2.3 against the following criteria in SRP-LR 

Section 3.1.2.2.3:

Item 1. LRA Section 3.1.2.2.3, item 1, associated with LRA Table 3.1.1, item 3.1.1-13, 

addresses steel reactor vessel beltline shell, nozzles, and welds exposed to reactor coolant and 

neutron flux, which will be managed for loss of fracture toughness due to neutron irradiation 

embrittlement by the neutron embrittlement TLAA. SRP-LR Section 3.1.2.2.3, item 1, states 

that neutron irradiation embrittlement could occur for all ferric materials exposed to a neutron 

fluence greater than 1x1017 n/cm2 (E > 1 MeV) at the end of the license renewal term. The 

SRP-LR also states that the TLAA for neutron irradiation embrittlement is required to be 
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evaluated in accordance with 10 CFR 54.21(c)(1). The SRP-LR further states that this TLAA is 

addressed separately in SRP-LR Section 4.2, “Reactor Vessel Neutron Embrittlement Analysis.”

The applicant addressed the further evaluation criteria of the SRP-LR by stating that the 

evaluation of neutron irradiation embrittlement for all ferritic reactor vessel components that 

have a neutron fluence greater than 1x1017 n/cm2 (E > 1 MeV) at the end of the license renewal 

term is performed as a TLAA as discussed in LRA Section 4.2.

It its review, the staff noted that LRA Table 3.1.2-2, “Reactor Vessel Summary of Aging 

Management Evaluation,” adequately addresses AMR items to manage loss of fracture 

toughness due to neutron irradiation embrittlement for Reactor Vessel components by using the 

neutron embrittlement TLAA, consistent with GALL Report items IV.A1.R-62 and V.A1.R-67. 

The staff’s evaluation of the applicant’s neutron irradiation embrittlement TLAA for Reactor 

Vessel components is documented in SER Section 4.2 and its subsections.

In its review of Reactor Vessel components associated with LRA Table 3.1.1, item 3.1.1-13, the 

staff finds that the applicant has met the further evaluation criteria and that the applicant’s 

proposal to manage the effects of aging using the neutron irradiation embrittlement TLAA is 

acceptable because the applicant’s proposal is consistent with GALL Report items IV.A1.R-62 

and V.A1.R-67 and the guidance in SRP-LR Section 3.1.2.2.3, item 1.

Item 2. LRA Section 3.1.2.2.3, item 2, associated with LRA Table 3.1.1, item 3.1.1-14, 

addresses the steel (with or without cladding) reactor vessel beltline shell and welds exposed to 

reactor coolant and neutron flux environment. The applicant stated that for the components 

associated with LRA Table 3.1.1, item 3.1.1-14, loss of fracture toughness caused by neutron 

irradiation embrittlement will be managed by the Reactor Vessel Surveillance program. The 

applicant also stated that the program meets the requirements of Appendix H, “Reactor Vessel 

Material Surveillance Program Requirements,” to 10 CFR Part 50, “Domestic Licensing of 

Production and Utilization Facilities,” and that the embrittlement evaluations are performed in 

accordance with RG 1.99, Revision 2.

The applicable “acceptance criteria” provided in SRP-LR Section 3.1.2.2.3, item 2, states that 

loss of fracture toughness due to neutron irradiation embrittlement could occur in BWR reactor 

vessel beltline shell, nozzles, and welds exposed to reactor coolant and neutron flux. The 

SRP-LR states that the reviewer verifies that the applicant has proposed an adequate reactor 

vessel material surveillance program for the period of extended operation.

The staff verified that the applicant included the applicable AMR items for the RV beltline 

components in LRA Table 3.1-1 and is crediting its Reactor Vessel Surveillance program to 

manage for loss of fracture toughness due to neutron irradiation embrittlement, consistent with 

the guidance provided in the GALL Report. In its review of components associated with LRA 

Table 3.1.1, item 3.1.1-14, the staff finds the applicant has met the further evaluation criteria of 

SRP-LR Section 3.1.2.2.3, item 2. The staff also noted that the applicant’s AMP is based on 

compliance with the reactor vessel surveillance program and surveillance capsule withdrawal 

schedule requirements of Appendix H to 10 CFR Part 50. The staff’s evaluation of the 

applicant’s Reactor Vessel Surveillance program is documented in SER Section 3.0.3.1.8.

Based on the program identified, the staff concludes that the applicant meets the SRP-LR 

Section 3.1.2.2.3, item 2, criteria. For those items that apply to LRA Section 3.1.2.2.3, item 2, 

the staff determines that the LRA is consistent with the GALL Report and that the applicant 

demonstrated that the effects of aging will be adequately managed so that the intended 
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function(s) will remain consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 3. LRA Section 3.1.2.2.3, item 3, associated with LRA Table 3.1.1, item 3.1.1-15, 

addresses reduction in fracture toughness for Babcock and Wilcox reactor internals. The 

applicant stated that this item is not applicable because the associated item in LRA Table 3.1.1 

is applicable to PWRs only. The staff evaluated the applicant’s claim and finds it acceptable 

because the item is applicable only to PWRs and because the applicant’s reactors are BWRs.

Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion 

Cracking

The staff reviewed LRA Section 3.1.2.2.4 against the following criteria in SRP-LR 

Section 3.1.2.2.4:

Item 1. LRA Section 3.1.2.2.4, item 1, associated with LRA Table 3.1.1, item 3.1.1-16, 

addresses cracking due to SCC and IGSCC in stainless steel and nickel alloy top head 

enclosure vessel flange leak detection line exposed to air with reactor coolant leakage or 

reactor coolant. The criteria in SRP-LR Section 3.1.2.2.4, item 1, state that the GALL Report

recommends that a plant-specific program be evaluated because existing programs may not be 

capable of mitigating or detecting cracking due to SCC and IGSCC.

LRA Section 3.1.2.2.4, item 1, states that, because the leak detection line is fabricated with 

carbon steel, it is not susceptible to SCC or IGSCC. The staff evaluated the applicant’s claim 

and finds it acceptable because LRA Table 3.1.1, item 3.1.1-16, and LRA Section 3.1.2.2.4, 

item 1, are not applicable to carbon steel.

Item 2. LRA Section 3.1.2.2.4, item 2, which is associated with LRA Table 3.1.1, item 3.1.1-17, 

addresses SCC and IGSCC for stainless steel BWR isolation condenser components exposed 

to reactor coolant. The applicant stated that this item is not used because the LSCS design 

does not have an isolation condenser. The staff reviewed the applicant’s UFSAR and confirmed 

that the design of the applicant’s unit does not include an isolation condenser; therefore, the 

staff finds the applicant’s statement acceptable.

Crack Growth Due to Cyclic Loading

LRA Section 3.1.2.2.5, associated with LRA Table 3.1.1, item 3.1.1-18, addresses loss of 

material caused by general, pitting, and crevice corrosion in the steel PWR steam generator 

upper and lower shells and transition cone exposed to secondary feedwater and steam. The 

applicant stated that this item is not applicable because the associated item in LRA Table 3.1.1 

is applicable to PWRs only. The staff evaluated the applicant’s claim and finds it acceptable 

because the item is applicable only to PWRs and because the applicant’s reactors are BWRs 

that do not have steam generators.

Cracking Due to Stress Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.6 against the criteria in SRP-LR Section 3.1.2.2.6.

Item 1. LRA Section 3.1.2.2.6, item 1, associated with LRA Table 3.1.1, item 3.1.1-19, 

addresses cracking caused by SCC in PWR stainless steel reactor vessel flange leak detection 

lines and bottom-mounted instrument guide tubes exposed to reactor coolant. The applicant 
3-200

stated that this item is not applicable because the associated item in LRA Table 3.1.1 is 

applicable to PWRs only. The staff evaluated the applicant’s claim and finds it acceptable 

because this item is associated only with PWRs.

Item 2. SRP-LR Section 3.1.2.2.6, item 2, associated with LRA Table 3.1.1, item 3.1.1-20, 

addresses cracking due to SCC that could occur in Class 1 PWR CASS reactor coolant system 

piping and piping components. The applicant stated that this item is not applicable because the 

associated item in LRA Table 3.1.1 is applicable to PWRs only. In its review, the staff finds that 

this item is not applicable because the applicant’s reactor type is a BWR.

Cracking Due to Cyclic Loading

LRA Section 3.1.2.2.7, which is associated with LRA Table 3.1.1, item 3.1.1-21, addresses 

cracking due to cyclic loading for steel and stainless steel BWR isolation condenser 

components exposed to reactor coolant. The applicant stated that this item is not used because 

the LSCS design does not have an isolation condenser. The staff reviewed the applicant’s 

UFSAR and confirmed that the design of the applicant’s units does not include an isolation 

condenser; therefore, the staff finds the applicant’s statement acceptable.

Loss of Material Due to Erosion

LRA Section 3.1.2.2.8, associated with LRA Table 3.1.1, item 3.1.1-22, addresses loss of 

material due to erosion in steel steam generator feedwater impingement plates and supports 

exposed to secondary feedwater. The applicant stated that this item is not applicable because 

the associated item in LRA Table 3.1.1 is applicable to PWRs only. The staff evaluated the 

applicant’s claim and finds it acceptable because the item is applicable only to PWRs and

because the applicant’s reactors are BWRs that do not have steam generators.

This paragraph for further evaluation from the SRP-LR was removed by 

LR-ISG-2011-04.

This paragraph for further evaluation from the SRP-LR was removed by

LR-ISG-2011-04.

Cracking Due to Primary Water Stress Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.11 against the criteria in SRP-LR Section 3.1.2.2.11.

Item 1. LRA Section 3.1.2.2.11, item 1, associated with LRA Table 3.1.1, item 3.1.1-25, 

addresses cracking due to PWSCC that could occur in steam generator divider plates and 

associated welds fabricated of nickel alloys. The LRA states that this item is not applicable 

because it applies to PWRs only. In its review, the staff finds the applicant’s determination 

acceptable because the applicant’s reactor type is a BWR.

Item 2. LRA Section 3.1.2.2.11, item 2, associated with Table 3.1.1 Item 3.1.1-20, addresses 

cracking due to PWSCC that could occur in steam generator tube-to-tube sheet welds 

fabricated of nickel alloys. The LRA states that this item is not applicable because it applies to 

PWRs only. In its review, the staff finds the applicant’s determination acceptable because the 

applicant’s reactor type is a BWR.
3-201

This paragraph for further evaluation from the SRP-LR was removed by 

LR-ISG-2011-04.

This paragraph for further evaluation from the SRP-LR was removed by 

LR-ISG-2011-04.

This paragraph for further evaluation from the SRP-LR was removed by

LR-ISG-2011-04.

Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program.

Ongoing Review of Operating Experience

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience of AMPs.

3.1.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.1.2-1 through 3.1.2-3, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations that are not consistent with or are not 

addressed in the GALL Report.

In LRA Tables 3.1.2-1 through 3.1.2-3, the applicant indicated, through notes F through J, that 

the combination of component type, material, environment, and AERM does not correspond to 

any item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, note F indicates that the material for the AMR item

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR item component and material is not evaluated in the GALL Report. Note H indicates that 

the aging effect for the AMR item component, material, and environment combination is not 

evaluated in the GALL Report. Note I indicates that the aging effect identified in the 

GALL Report for the item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the item is evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the 

GALL Report, the staff reviewed the applicant’s evaluation to determine whether the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections.

Reactor Coolant Pressure Boundary System – Summary of Aging Management 

Review – LRA Table 3.1.2-1

The staff reviewed LRA Table 3.1.2-1, which summarizes the results of AMR evaluations for the 

Reactor Coolant Pressure Boundary System component groups.

Cast Austenitic Stainless Steel Flow Devices (Flow Restrictors) Exposed to Steam. In LRA 

Table 3.1.2-1, the applicant stated that the main steam line flow restrictors, which are fabricated 

of cast austenitic stainless steel (CASS), will be managed for loss of material due to erosion by 
3-202

a plant-specific TLAA for the components. The AMR item cites generic note H, indicating that 

the loss of material aging effect is not described for this component, material, and environment 

combination in the GALL Report. The AMR item cites plant specific note 5, which indicates that 

the plant-specific TLAA for the components is included in Section 4.7 of the LRA.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant addressed cracking in 

the main steam line flow restrictors and other mechanisms that could potentially induce loss of 

material in the flow restrictors in other AMR items in LRA Table 3.1.2 1. The staff finds that the 

applicant has identified all other credible aging effects and mechanisms for this component, 

material, and environment combination consistent with the GALL Report.

For the management of loss of material due to erosion, the staff confirmed that the applicant is 

managing the aging effect using a plant-specific TLAA, as defined and discussed in 

Section 4.7.2 of the LRA. The staff finds the applicant’s proposal to manage loss of material 

due to erosion using the TLAA acceptable because the applicant has projected the amount of 

erosion that will occur in the components to the end of the period of extended operation 

consistent with the requirements in 10 CFR 54.21(c)(1)(ii). The staff evaluates this TLAA in 

SER Section 4.7.2.

Reactor Vessel – Summary of Aging Management Review – LRA Table 3.1.2-2

The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMR evaluations for the 

Reactor Vessel component groups.

Carbon or Low Alloy Steel Exposed to Indoor Air. In LRA Table 3.1.2-2, the applicant stated 

that, for carbon or low alloy steel reactor vessel components exposed to indoor air (external), 

loss of material is not applicable and that no AMPs are proposed. The AMR items cite generic 

note I. The AMR items also cite plant-specific note 1, which states that, during power operation,

the insulated reactor components have an external temperature greater than 212 °F and are at 

a higher temperature than that of the indoor air and that, during plant shutdown, the 

containment atmosphere is normally below the dew-point temperature. Plant-specific note 1 

further states that, because of the pertinent conditions described, wetting due to condensation 

will not occur; therefore, loss of material due to corrosion is not applicable.

The staff reviewed the associated items in the LRA to confirm that the aging effect is not 

applicable for this component, material, and environment combination. The staff noted that 

moisture accumulation is not expected to occur on the reactor vessel components under the 

atmospheric conditions described. The staff further noted that in the absence of moisture or 

condensation, corrosion will not occur. Therefore, the staff finds the applicant’s proposal 

acceptable.

Reactor Vessel Internals – Summary of Aging Management Review –

LRA Table 3.1.2-3

The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations for the 

Reactor Vessel Internals component groups.

Stainless Steel Bolting, Stainless Steel, or X-750 Alloy Exposed to Reactor Coolant and Neutron 

Flux. In LRA Table 3.1.2-3, the applicant stated that the core plate bolts (rim hold-down bolts), 
3-203

jet pump riser brace clamps, and jet pump slip joint clamps – all of which are fabricated of 

stainless steel and X-750 alloy and exposed to the reactor coolant and neutron flux – will be 

managed for loss of preload due to neutron irradiation by the TLAAs for reactor vessel internals. 

The AMR item cites generic note H, indicating that the loss of preload aging effect is not 

described for this component, material, and environment combination in the GALL Report. The 

AMR item cites plant-specific notes 3 and 4, which indicate that LRA Section 4.2 on TLAAs of 

neutron irradiation effects addresses aging management of these reactor vessel internals 

exposed to neutron fluence.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant addressed cracking, 

cumulative fatigue, loss of material, and loss of fracture toughness for this component, material, 

and environment combination in other AMR items in LRA Table 3.1.2-3. The staff finds that the 

applicant has identified all other credible aging effects for this component, material, and 

environment combination consistent with the GALL Report.

The staff’s evaluation of the applicant’s TLAAs for loss of material in the core plate rim 

hold-down bolts, jet pump riser brace clamps, and jet pump slip joint clamps are documented in 

SER Sections 4.2.8, 4.2.9, and 4.2.10, respectively. The staff finds the applicant’s proposal to 

manage loss of preload using the TLAAs acceptable because (1) the applicant demonstrated 

that the loss of preload analyses for the core plate rim hold-down bolts and jet pump riser brace 

clamps remain valid through the period of extended operation and (2) the analysis for the jet 

pump slip joint clamps will be revised for a higher acceptable neutron fluence value or other 

correction actions, such as repair or replacement of the clamps, will be performed to ensure 

acceptable clamp preload as specified in Commitment No. 47 in the UFSAR supplement.

X-750 Alloy Jet Pump Assemblies: Inlet Riser and Brace, Hold-Down Beam, Diffuser, Tailpipe, 

Wedges, and Repair Components Exposed to Reactor Coolant and Neutron Flux. In LRA 

Table 3.1.2-3, the applicant stated that X-750 alloy jet pump assemblies (i.e., inlet riser and 

brace, hold-down beam, diffuser, tailpipe, wedges, and repair components) exposed to reactor 

coolant and neutron flux will be managed for loss of material by the BWR Vessel Internals 

program. The AMR item cites generic note F and plant-specific note 5, which state that the 

BWR Vessel Internals program is used to manage loss of material due to wear of X-750 alloy 

replacement jet pump main wedges and auxiliary wedges.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant addressed cracking, 

cumulative fatigue damage, loss of fracture toughness, and loss of preload for this component, 

material, and environment combination in other AMR items in LRA Table 3.1.2-3. Based on its 

review of the GALL Report and BWRVIP-41, which state that this component, material, and 

environmental combination is susceptible to loss of fracture toughness and cracking, the staff 

finds that the applicant has identified all credible aging effects for this component, material, and 

environment combination.

The staff’s evaluation of the applicant’s BWR Vessel Internals program is documented in SER 

Section 3.0.3.2.3. The staff noted that the GALL Report recommends GALL Report AMP XI.M9, 

“BWR Vessel Internals,” to manage loss of material for stainless steel and nickel alloy jet pump 

components exposed to reactor coolant and neutron flux. The staff finds the applicant’s 

proposal to manage the effects of aging using the BWR Vessel Internals program acceptable 
3-204

because the visual inspections required by BWRVIP-41 are capable of detecting loss of material 

of the jet pump assemblies and because inspection frequency recommended by BWRVIP-41 

ensures that the functionality of the jet pump assemblies will be monitored.

3.1.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the Reactor Vessel, Internals, and Reactor Coolant System components 

within the scope of license renewal and subject to an AMR will be adequately managed so that 

the intended functions will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

3.2 Aging Management of Engineered Safety Features Systems

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

engineered safety features (ESF) systems components of the following:

• High Pressure Core Spray System

• Low Pressure Core Spray System

• Reactor Core Isolation Cooling System

• Residual Heat Removal System

• Standby Gas Treatment System

3.2.1 Summary of Technical Information in the Application

LRA Section 3.2 provides AMR results for the ESF systems components. LRA Table 3.2.1, 

“Summary of Aging Management Evaluations for the Engineered Safety Features,” is a 

summary comparison of the applicant’s AMRs with those evaluated in the GALL Report for the 

ESF systems components.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report.

3.2.2 Staff Evaluation

The staff reviewed LRA Section 3.2 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the ESF systems components within the 

scope of license renewal and subject to an AMR will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

The staff conducted a review of the applicant’s AMRs to verify the applicant’s claim that certain 

AMRs are consistent with the GALL Report or are not applicable. The staff did not repeat its 

review of the matters described in the GALL Report; however, the staff did verify that the 

material presented in the LRA is applicable and that the applicant identified the appropriate 

GALL Report AMRs. AMRs that the staff confirmed are consistent with the GALL Report are 

noted as such in Table 3.2-1; therefore, no further discussion is required. AMRs that the staff 

confirmed are not applicable to LSCS or require no aging management are noted in Table 3.2-1 
3-205

and discussed in SER Section 3.2.2.1.1. Details of the staff’s evaluation of AMRs that the 

applicant claimed are consistent with the GALL Report, but for which a different AMP from the 

program recommended in the GALL Report is used to manage aging, and AMRs for which the 

staff requested additional information are documented in SER Section 3.2.2.1.2.

During its review, the staff also reviewed AMRs that are consistent with the GALL Report and 

those for which further evaluation is recommended. The staff confirmed that the applicant’s 

further evaluations are consistent with the SRP-LR Section 3.2.2.2 acceptance criteria. The 

staff’s evaluations of AMRs for which the GALL Report recommends further evaluation are 

documented in SER Section 3.2.2.2.

The staff also conducted a technical review of the remaining AMRs that are not consistent with,

or are not addressed in, the GALL Report. The technical review evaluated whether all plausible 

aging effects have been identified and whether the aging effects listed are appropriate for the 

material-environment combinations specified. The staff’s evaluations of AMRs that are not 

consistent with, or are not addressed in, the GALL Report are documented in SER 

Section 3.2.2.3.

Table 3.2-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.2 and addressed in the GALL Report.

Staff Evaluation for Engineered Safety Features Systems Components in the 

GALL Report

Component Group 

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel, steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water (borated) 

(3.2.1-1)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a timelimited aging 

analysis (TLAA) to 

be evaluated for the 

period of extended 

operation. See the 

SRP, Section 4.3 

“Metal Fatigue,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1)).

Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.2.2.2.1)

Steel (with stainless 

steel cladding) pump 

casings exposed to 

treated water 

(borated) (3.2.1-2)

Loss of material 

due to cladding 

breach

A plant-specific 

aging management 

program is to be 

evaluated 

Reference NRC 

Information 

Notice 94-63, “Boric 

Acid Corrosion of 

Charging Pump 

Casings Caused by 

Cladding Cracks.”

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.2.2.2.2) 
3-206

Component Group 

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel 

partially-encased 

tanks with breached 

moisture barrier 

exposed to raw 

water (3.2.1-3)

Loss of material 

due to pitting 

and crevice 

corrosion

A plant-specific 

aging management 

program is to be 

evaluated for pitting 

and crevice 

corrosion of tank 

bottom because 

moisture and water 

can egress under 

the tank due to 

cracking of the 

perimeter seal from 

weathering.

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.2.2.2.3)

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to air 

– outdoor (3.2.1-4)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report 

(see SER 

Section 3.2.2.2.3)

Stainless steel 

orifice (miniflow 

recirculation) 

exposed to treated 

water (borated) 

(3.2.1-5)

Loss of material 

due to erosion

A plant-specific 

aging management 

program is to be 

evaluated for erosion 

of the orifice due to 

extended use of the 

centrifugal HPSI 

pump for normal 

charging. See LER 

50-275/94-023 for 

evidence of erosion.

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.2.2.2.4)

Steel drywell and 

suppression 

chamber spray 

system (internal 

surfaces): flow 

orifice; spray nozzles 

exposed to air –

indoor, uncontrolled 

(internal) (3.2.1-6)

Loss of material 

due to general 

corrosion; 

fouling that 

leads to 

corrosion

A plant-specific 

aging management 

program is to be 

evaluated

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.2.5)

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to air 

– outdoor (3.2.1-7)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report 

(see SER 

Section 3.2.2.2.6)

Aluminum, copper 

alloy (>15% Zn or 

>8% Al) piping, 

piping components, 

and piping elements 

exposed to air with 

borated water 

leakage (3.2.1-8)

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.2.2.1.1)
3-207

Component Group 

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel external 

surfaces, bolting 

exposed to air with 

borated water 

leakage (3.2.1-9)

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Cast austenitic

stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water (borated) 

>250°C (>482°F), 

treated water 

>250°C (>482°F) 

(3.2.1-10)

Loss of fracture 

toughness due 

to thermal aging 

embrittlement

Chapter XI.M12, 

“Thermal Aging 

Embrittlement of 

Cast Austenitic 

Stainless Steel 

(CASS)”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to steam, 

treated water 

(3.2.1-11)

Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Flow-Accelerated 

Corrosion

An exception 

applies to the 

Flow-Accelerated 

Corrosion

Consistent with the 

GALL Report

Steel, high-strength 

closure bolting 

exposed to air with 

steam or water 

leakage (3.2.1-12)

Cracking due to 

cyclic loading, 

stress corrosion 

cracking

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Steel; stainless steel 

bolting, closure 

bolting exposed to 

air – outdoor 

(external), air –

indoor, uncontrolled 

(external) (3.2.1-13)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Steel closure bolting 

exposed to air with 

steam or water

leakage (3.2.1-14)

Loss of material 

due to general 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Copper alloy, nickel 

alloy, steel; stainless 

steel, stainless steel, 

steel; stainless steel 

bolting, closure 

bolting exposed to 

any environment, air 

– outdoor (external), 

raw water, treated 

borated water, fuel 

oil, treated water, air 

– indoor, 

uncontrolled 

(external) (3.2.1-15)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report
3-208

Component Group 

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel containment 

isolation piping and 

components (internal 

surfaces), piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.2.1-16)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection, and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Aluminum, stainless 

steel piping, piping 

components, and 

piping elements 

exposed to treated 

water (3.2.1-17)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection,

Water Chemistry, 

and

Bolting Integrity

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report 

(see SER 

Section 3.2.2.1.2)

Stainless steel 

containment 

isolation piping and 

components (internal 

surfaces) exposed to 

treated water 

(3.2.1-18)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Stainless steel heat 

exchanger tubes 

exposed to treated 

water, treated water 

(borated) (3.2.1-19)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection, and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

treated water 

(borated) >60°C

(>140°F) (3.2.1-20)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Steel (with stainless 

steel or nickel-alloy 

cladding) safety 

injection tank 

(accumulator) 

exposed to treated 

water (borated) 

>60°C (>140°F) 

(3.2.1-21)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

treated water 

(borated) (3.2.1-22)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.2.2.1.1)
3-209

Component Group 

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel heat 

exchanger 

components, 

containment 

isolation piping and 

components (internal 

surfaces) exposed to 

raw water (3.2.1-23)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

- influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.2.1-24)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Stainless steel heat 

exchanger 

components, 

containment 

isolation piping and 

components (internal 

surfaces) exposed to 

raw water (3.2.1-25)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Stainless steel heat 

exchanger tubes 

exposed to raw 

water (3.2.1-26)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Stainless steel, steel 

heat exchanger 

tubes exposed to 

raw water (3.2.1-27)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to closedcycle cooling water 

>60°C (>140°F) 

(3.2.1-28)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Steel Piping, piping 

components, and 

piping elements 

exposed to closedcycle cooling water 

(3.2.1-29)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Steel heat 

exchanger 

components 

exposed to closedcycle cooling water 

(3.2.1-30)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report
3-210

Component Group 

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to closedcycle cooling water 

(3.2.1-31)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Copper alloy heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to closedcycle cooling water 

(3.2.1-32)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report

Copper alloy, 

stainless steel heat 

exchanger tubes 

exposed to closedcycle cooling water 

(3.2.1-33)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Copper alloy (>15% 

Zn or >8% Al) 

piping, piping 

components, and 

piping elements, 

heat exchanger 

components 

exposed to closedcycle cooling water 

(3.2.1-34)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Gray cast iron motor 

cooler exposed to 

treated water 

(3.2.1-35)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Gray cast iron 

piping, piping 

components, and 

piping elements 

exposed to closedcycle cooling water 

(3.2.1-36)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Gray cast iron 

piping, piping 

components, and 

piping elements 

exposed to soil 

(3.2.1-37)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Elastomers,

elastomer seals and 

components 

exposed to air –

indoor, uncontrolled 

(external) (3.2.1-38)

Hardening and 

loss of strength 

due to 

elastomer 

degradation

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External Surfaces

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report
3-211

Component Group 

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel containment 

isolation piping and 

components 

(external surfaces) 

exposed to 

condensation 

(external) (3.2.1-39)

Loss of material 

due to general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Steel ducting, piping, 

and components 

(external surfaces), 

ducting, closure 

bolting, containment 

isolation piping and 

components 

(external surfaces) 

exposed to air –

indoor, uncontrolled 

(external) (3.2.1-40)

Loss of material 

due to general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report

Steel external 

surfaces exposed to 

air – outdoor 

(external) (3.2.1-41)

Loss of material 

due to general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Aluminum piping, 

piping components, 

and piping elements 

exposed to air –

outdoor (3.2.1-42)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Elastomers,

elastomer seals and 

components 

exposed to air –

indoor, uncontrolled 

(internal) (3.2.1-43)

Hardening and 

loss of strength 

due to 

elastomer 

degradation

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Steel piping and 

components (internal 

surfaces), ducting 

and components 

(internal surfaces) 

exposed to air –

indoor, uncontrolled 

(internal) (3.2.1-44)

Loss of material 

due to general 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Steel encapsulation 

components 

exposed to air –

indoor, uncontrolled 

(internal) (3.2.1-45)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Steel piping and 

components (internal 

surfaces) exposed to 

condensation 

(internal) (3.2.1-46)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report
3-212

Component Group 

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel encapsulation 

components 

exposed to air with 

borated water 

leakage (internal) 

(3.2.1-47)

Loss of material 

due to general, 

pitting, crevice, 

and boric acid 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

(internal surfaces); 

tanks exposed to 

condensation 

(internal) (3.2.1-48)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil 

(3.2.1-49)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Copper alloy, 

stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil 

(3.2.1-50)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Steel, copper alloy, 

stainless steel heat 

exchanger tubes 

exposed to 

lubricating oil 

(3.2.1-51)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Steel (with coating or 

wrapping) piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.2.1-52)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Stainless steel, 

nickel alloy piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.2.1-53)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Buried and 

Underground 

Piping

Consistent with the 

GALL Report

Steel, stainless 

steel, nickel alloy

underground piping, 

piping components, 

and piping elements 

exposed to airindoor uncontrolled 

or condensation 

(external) (3.2.1-53x)

Loss of material 

due to general 

(steel only), 

pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping

and Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)
3-213

Component Group 

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water >60°C 

(>140°F) (3.2.1-54)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M7, 

“BWR Stress 

Corrosion Cracking,”

and Chapter XI.M2, 

“Water Chemistry”

No BWR Stress 

Corrosion 

Cracking, and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to concrete 

(3.2.1-55)

None None, provided 

1) attributes of the 

concrete are 

consistent with 

ACI 318 or ACI 349 

(low water-to-cement 

ratio, low 

permeability, and 

adequate air 

entrainment) as cited 

in NUREG-1557, 

and 

2) plant OE indicates 

no degradation of 

the concrete

No, if 

conditions 

are met.

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Aluminum piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(internal/external) 

(3.2.1-56)

None None NA - No 

AEM or 

AMP

Consistent with 

NUREG-1801 (the 

GALL Report)

Consistent with the 

GALL Report

Copper alloy piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(external), gas 

(3.2.1-57)

None None NA - No 

AEM or 

AMP

Consistent with 

NUREG-1801 (the 

GALL Report)

Consistent with the 

GALL Report

Copper alloy (≤15% 

Zn and ≤8% Al) 

piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage (3.2.1-58)

None None NA - No 

AEM or 

AMP

Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Galvanized steel 

ducting, piping, and 

components 

exposed to air –

indoor, controlled 

(external) (3.2.1-59)

None None NA - No 

AEM or 

AMP

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)
3-214

Component Group 

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Glass piping 

elements exposed to 

air – indoor, 

uncontrolled 

(external), lubricating 

oil, raw water, 

treated water, 

treated water 

(borated), air with 

borated water 

leakage, 

condensation 

(internal/external), 

gas, closed-cycle 

cooling water, air –

outdoor (3.2.1-60)

None None NA - No 

AEM or 

AMP

Consistent with 

NUREG-1801 (the 

GALL Report)

Consistent with the 

GALL Report

Nickel alloy piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(external) (3.2.1-61)

None None NA - No 

AEM or 

AMP

Consistent with 

NUREG-1801 (the 

GALL Report)

Consistent with the 

GALL Report

Nickel alloy piping, 

piping components, 

and piping elements 

exposed to air with 

borated water 

leakage (3.2.1-62)

None None NA - No 

AEM or 

AMP

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to air –

indoor, uncontrolled 

(external), air with 

borated water 

leakage, concrete, 

gas, air – indoor, 

uncontrolled 

(internal) (3.2.1-63)

None None NA - No 

AEM or 

AMP

Consistent with 

NUREG-1801

Consistent with the 

GALL Report

Steel Piping, piping 

components, and 

piping elements 

exposed to air –

indoor, controlled 

(external), gas 

(3.2.1-64)

None None NA - No 

AEM or 

AMP

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Any material, piping, 

piping components, 

and piping elements 

exposed to treated 

water, treated water 

(borated) (3.2.1-65)

Wall thinning 

due to erosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Flow- Accelerated 

Corrosion

An exception 

applies to the 

Flow-Accelerated 

Corrosion 

program

Consistent with the 

GALL Report
3-215

Component Group 

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Metallic piping, 

piping components, 

and tanks exposed 

to raw water or 

waste water 

(3.2.1-66)

Loss of material 

due to recurring 

internal 

corrosion

A plant-specific 

aging management 

program is to be 

evaluated to address 

recurring internal 

corrosion

Yes, plantspecificNot Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.2.9)

Stainless steel or 

aluminum tanks 

(within the scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to soil or 

concrete, or the 

following external 

environments airoutdoor, air-indoor 

uncontrolled, moist 

air, condensation 

(3.2.1-67)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Steel, stainless 

steel, or aluminum 

tanks (within the 

scope of Chapter 

XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to soil or 

concrete, or the 

following external 

environments airoutdoor, air-indoor 

uncontrolled, moist 

air, condensation 

(3.2.1-68)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Insulated steel, 

stainless steel, 

copper alloy, or 

aluminum, piping, 

piping components, 

and tanks exposed 

to condensation, airoutdoor (3.2.1-69)

Loss of material 

due to general 

(steel, and 

copper alloy 

only), pitting, 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” or 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks,” (for 

tanks only)

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Steel, stainless steel 

or aluminum tanks 

(within the scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to treated 

water, treated 

borated water 

(3.2.1-70)

Loss of material 

due to general 

(steel only), 

pitting and 

crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)
3-216

Component Group 

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Insulated stainless 

steel, aluminum, or 

copper alloy 

(> 15% Zn) piping, 

piping components, 

and tanks exposed 

to condensation, airoutdoor (3.2.1-71)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” or 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks,” (for 

tanks only)

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.2.2.1.1)

Metallic piping, 

piping components, 

heat exchangers, 

tanks with internal 

coatings/linings 

exposed to closedcycle cooling water, 

raw water, treated 

water, treated 

borated water, or 

lubricating oil 

(3.2.1-72)

Loss of coating 

or lining integrity 

due to blistering, 

cracking, 

flaking, peeling, 

delamination, 

rusting, or 

physical 

damage, and 

spalling for 

cementitious 

coatings/linings

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks”

No Not Used Not Used by LSCS 

(see SER 

Section 3.2.2.3.3)

Metallic piping, 

piping components, 

heat exchangers, 

tanks with internal 

coatings/linings 

exposed to closedcycle cooling water, 

raw water, treated 

water, treated 

borated water, or 

lubricating oil 

(3.2.1-73)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically 

influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks”

No Not Used Not Used by LSCS 

(see SER 

Section 3.2.2.1.1)

Gray cast iron piping 

components with 

internal 

coatings/linings 

exposed to closedcycle cooling water, 

raw water, or treated 

water (3.2.1-74)

Loss of material 

due to selective 

leaching

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks”

No Not Used Not Used by LSCS 

(see SER 

Section 3.2.2.1.1)

3.2.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.2.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the ESF systems components:

• Bolting Integrity

• Buried and Underground Piping

• External Surfaces Monitoring of Mechanical Components

• Flow-Accelerated Corrosion
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• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

• Lubricating Oil Analysis

• One-Time Inspection

• Selective Leaching

• Service Level III and Service Level III Augmented Coatings Monitoring and Maintenance 

Program

• TLAA

• Water Chemistry

LRA Tables 3.2.2-1 through 3.2.2-5 summarize the results of AMRs for the ESF systems 

components and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components in these 

GALL Report component groups were bounded by the GALL Report evaluation. The applicant 

provided a note for each AMR item. The notes describe how the information in the tables aligns 

with the information in the GALL Report. The staff audited those AMRs with notes A through E, 

which indicate how the AMR was consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these AMR items to confirm consistency with the GALL Report and the validity 

of the AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff audited these AMR items to confirm consistency with 

the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to 

the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant 

was consistent with the AMP identified in the GALL Report and whether the AMR was valid for 

the site-specific conditions.

Note C indicates that the component for the AMR item, although different from that in the 

GALL Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP is consistent with the AMP identified by the GALL Report. Note C indicates 

that the applicant was unable to find a listing of some system components in the GALL Report; 

however, the applicant identified a different component in the GALL Report that had the same 

material, environment, aging effect, and AMP as those of the component under review. The 

staff audited these AMR items to confirm consistency with the GALL Report. The staff also 

determined whether the AMR item of the different component applied to the component under 

review and whether the AMR was valid for the site-specific conditions.

Note D indicates that the component for the AMR item, although different from that in the 

GALL Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff 

audited these AMR items to confirm consistency with the GALL Report and confirmed whether 

the AMR item of the different component was applicable to the component under review. The 
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staff confirmed whether it had reviewed and accepted the exceptions to the GALL Report AMPs. 

The staff also determined whether the AMP identified by the applicant was consistent with the 

AMP identified in the GALL Report and whether the AMR was valid for the site-specific 

conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect; however, a different AMP is credited. The staff audited these 

AMR items to confirm consistency with the GALL Report and determined whether the identified 

AMP would manage the aging effect consistent with the AMP identified in the GALL Report and 

whether the AMR was valid for the site-specific conditions.

The staff did not repeat its review of the matters described in the GALL Report for those items 

that the staff determined were bounded by the GALL Report evaluation. However, it did confirm 

that the material presented in the LRA was applicable and that the applicant identified the 

appropriate GALL Report AMRs. The staff’s evaluation is discussed below.

AMR Results Identified as Not Applicable or Not Used

For LRA Table 3.2.1, items 3.2.1-2, 3.2.1-3, 3.2.1-5, 3.2.1-8, 3.2.1-9, 3.2.1-20 through 3.2.1-22, 

3.2.1-24, 3.2.1-35, 3.2.1-36, 3.2.1-45, 3.2.1-47, and 3.2.1-58, the applicant claimed that the 

corresponding AMR items in the GALL Report are not applicable because the associated items 

are only applicable to PWRs. The staff reviewed the SRP-LR; confirmed that these items only 

apply to PWRs; and finds that these items are not applicable to LSCS, which is a BWR.

For LRA Table 3.2.1, items 3.2.1-10, 3.2.1-14, 3.2.1-18, 3.2.1-23, 3.2.1-25 through 3.2.1-29, 

3.2.1-31, 3.2.1-33, 3.2.1-34, 3.2.1-37, 3.2.1-39, 3.2.1-41 through 3.2.1-44, 3.2.1-52, 3.2.1-53x, 

3.2.1-55, 3.2.1-59, 3.2.1-62, 3.2.1-64, and 3.2.1-67 through 3.2.1-71, the applicant claimed that 

the corresponding items in the GALL Report are not applicable because the component, 

material, and environment combination described in the SRP-LR does not exist for in-scope 

SCs at LSCS. The staff reviewed the LRA and UFSAR and confirmed that the applicant’s LRA 

does not have any AMR results applicable for these items.

SER Table 3.2-1, items 3.2.1-73 and 3.2.1-74, reflect changes to the SRP-LR incorporated by

LR-ISG-2013-01, “Aging Management of Loss of Coating or Lining Integrity for Internal 

Coatings/Linings on In-Scope Piping, Piping Components, Heat Exchangers and Tanks.” The 

ISG added these items to allow applicants to credit the new GALL Report AMP XI.M42, “Internal 

Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks,” to 

manage loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion; fouling that leads to corrosion; or selective leaching in certain components. The 

applicant did not credit the related plant-specific AMP, “Service Level III and Service Level III 

Augmented Coatings Monitoring and Maintenance Program,” for the aging effect and 

components that reference SRP-LR items 3.2.1-73 and 3.2.1-74; instead, it credited alternate 

items and programs to manage the effects of these aging mechanisms for these components. 

For example, loss of material for the internally coated RCIC turbine lube oil reservoirs is 

managed by the Lubricating Oil Analysis and One-Time Inspection programs. The staff finds 

this approach acceptable because the alternate items and programs used are adequate to 

manage the effects of aging for these components and because this approach is consistent with 

GALL Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, 

Heat Exchangers, and Tanks.”
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For the LRA Table 3.2.1 items discussed below, the applicant claimed that the corresponding 

AMR items in the GALL Report are not applicable. For these items, the staff reviewed sources 

beyond the LRA and UFSAR or issued one or more RAIs, or both, in order to verify the 

applicant’s claim of non-applicability.

LRA Table 3.2.1, item 3.2.1-14 addresses steel closure bolting exposed to air with steam or 

water leakage. The GALL Report recommends GALL Report AMP XI.M18, “Bolting Integrity,” to 

manage loss of material due to general corrosion for this component group. The applicant 

stated that this item is not applicable because there is no steel closure bolting exposed to air 

with steam or water leakage in the ESF systems. The staff evaluated the applicant’s claim and 

notes that the possibility for the steel closure bolts in the ESF systems to be exposed to an air 

with steam or water leakage environment during the period of extended operation cannot be 

eliminated. However, the staff finds that the steel closure bolts in the ESF systems will be 

adequately age managed for loss of material due to general corrosion and finds the 

non-applicability of LRA item 3.2.1-14 acceptable because of the following:

• Through LRA Table 3.2.1, items 3.2.1-13 and 3.2.1-40, the applicant will use the Bolting 

Integrity and External Surfaces Monitoring of Mechanical Components programs to 

manage loss of material of all closure bolting in the ESF systems.

• Both programs conduct periodic visual inspections, which are capable of detecting loss 

of material due to general corrosion in closure bolting.

• Use of these programs is consistent with GALL Report recommendations.

Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.2.1, item 3.2.1-17, addresses aluminum and stainless steel piping, piping 

components, and piping elements exposed to treated water, which will be managed for loss of 

material due to pitting and crevice corrosion. For the AMR items that cite generic note E, the 

LRA credits the Bolting Integrity program to manage the aging effects for stainless steel bolting 

in the High Pressure Core Spray, Low Pressure Core Spray, Reactor Core Isolation Cooling, 

and the Residual Heat Removal Systems. The GALL Report recommends GALL Report 

AMP XI.M2, “Water Chemistry,” and AMP XI.M32, “One-Time Inspection,” programs to ensure 

that this aging effect is adequately managed. GALL Report AMP XI.M2 recommends using 

periodic monitoring of the treated water in order to minimize loss of material or cracking to 

manage the effects of aging. GALL Report AMP XI.M32 recommends performing one-time 

nondestructive examinations to verify the effectiveness of AMP XI.M2.

The staff’s evaluation of the applicant’s Bolting Integrity program is documented in SER 

Section 3.0.3.2.4. The staff noted that the Bolting Integrity program proposes to manage the 

effects of aging for stainless steel bolting through the use of periodic inspections for indication of 

loss of material due to pitting and crevice corrosion. However, the applicant did not state the 

parameters, sample size, or frequency of inspections to be performed on submerged bolting for 

item 3.2.1-17, which addresses submerged bolting in several ESF systems. By letter dated 

July 7, 2015, the staff issued RAI 3.2.2.1.1-1, requesting that the applicant provide the 

parameters for visual inspections, clarify whether a representative sample will be removed and 

inspected, and justify the inspection frequency for submerged bolting.

In its response dated August 6, 2015, the applicant stated that the design of the submerged 

bolting for the suction strainers in the ESF systems called for these bolts to be torqued and then 

“staked” (either by purposeful distortion of the threads beyond the nut or by spot welding the nut 
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to the bolt) to prevent them from loosening. In addition, the geometry of these bolted 

connections allows for visual inspection of a portion of the bolt shanks between the flanges of 

the strainer and the associated suction piping. The applicant stated that the existing diver 

inspection procedures will be enhanced to include a requirement to verify that the nuts continue 

to be “staked” by physical manipulation to ensure the nuts are not loose and to require visual 

inspection of the bolt heads, nuts, and threaded bolt shank, where accessible. In addition, the 

applicant stated that the existing repetitive tasks, which will be enhanced to include diver 

inspections of all suction strainer bolting, are scheduled at least once each 10-year ISI interval. 

The applicant stated by verifying that the associated bolts remain “staked,” that physical 

manipulation shows they are not loose, and that the bolt surfaces do not show any loss of 

material will be adequate to ensure that the bolting has not lost preload and to detect loss of 

material without removal of the bolts. In addition, the 10-year frequency is comparable to other 

AMPs for which only limited samples are inspected during each 10-year period.

The staff notes that aging management of submerged bolting in several auxiliary systems is 

also addressed in the applicant’s response to RAI 3.2.2.1.1-1 and that these components are 

discussed in SER Section 3.3.2.1.5. The staff finds the applicant’s response acceptable 

because the proposed changes to the inspection details and frequency of the existing diver 

inspection procedure will ensure that degradation of submerged bolting will be identified. The 

staff’s concerns described in RAI 3.2.2.1.1-1 are resolved.

The staff concludes that, for LRA item 3.2.1-17, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.2.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation Is 

Recommended

In LRA Section 3.2.2.2, the applicant further evaluated aging management, as recommended by 

the GALL Report, for the ESF systems components and provided information concerning how it 

will manage the following aging effects:

• cumulative fatigue damage

• loss of material due to cladding breach

• loss of material due to pitting and crevice corrosion

• loss of material due to erosion

• loss of material due to general corrosion and fouling that leads to corrosion

• cracking due to SCC

• QA for aging management of nonsafety-related components

• ongoing review of operating experience

• loss of material due to recurring internal corrosion

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 

the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.2.2.2. The staff’s review of the applicant’s 

further evaluation follows.
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Cumulative Fatigue Damage

LRA Section 3.2.2.2.1 is associated with LRA Table 3.2.1, item 3.2.1-1, which addresses 

cumulative fatigue damage management for the Control Rod Drive, High Pressure Core Spray, 

Low Pressure Core Spray, Reactor Coolant Pressure Boundary, Reactor Core Isolation Cooling, 

Reactor Water Cleanup, and Residual Heat Removal Systems. The applicant addressed the 

further evaluation criteria of the SRP-LR by stating that fatigue is a TLAA, as defined in 

10 CFR 54.3, “Definitions,” and is required to be evaluated in accordance with 10 CFR 54.21(c). 

The applicant stated that its evaluation of the TLAA is addressed in LRA Section 4.3.

The staff reviewed LRA Section 3.2.2.2.1 against the criteria in SRP-LR Section 3.2.2.2.1, which 

state that cumulative fatigue damage of engineered safety features is a TLAA and that these 

TLAAs are to be evaluated in accordance with the TLAA acceptance criteria requirements of 

10 CFR 54.21(c). The staff reviewed the applicant’s AMR items and determined that the AMR 

results are consistent with the recommendations of the GALL Report and SRP-LR for managing 

cumulative fatigue damage.

LRA Section 3.2.2.2.1 states that TLAAs are evaluated in accordance with 10 CFR 54.21(c)(1) 

and that the evaluation of this TLAA is addressed in LRA Section 4.3. This is consistent with 

SRP-LR Section 3.2.2.2.1 and, therefore, is acceptable. The staff’s evaluation of the TLAA for 

the Control Rod Drive, High Pressure Core Spray, Low Pressure Core Spray, Reactor Coolant 

Pressure Boundary, Reactor Core Isolation Cooling, Reactor Water Cleanup, and Residual Heat 

Removal systems that are being managed for cumulative fatigue damage is documented in 

SER Section 4.3.

Loss of Material Due to Cladding Breach

LRA Section 3.2.2.2.2, associated with LRA Table 3.2.1, item 3.2.1-2, addresses loss of 

material due to cladding breach in PWR steel charging pump casings with stainless steel 

cladding exposed to treated borated water. The applicant stated that this item is not applicable 

because it only applies to PWRs. The staff confirmed that this item is associated only with PWR 

plants and that the applicant’s reactor type is a BWR; therefore, the staff finds the applicant’s 

determination acceptable.

Loss of Material Due to Pitting and Crevice Corrosion

The staff reviewed LRA Section 3.2.2.2.3 against the following criteria in SRP-LR 

Section 3.2.2.2.3:

Item 1. LRA Section 3.2.2.2.3, associated with LRA Table 3.2.1, item 3.2.1-3, addresses loss of 

material in partially encased stainless steel tanks exposed to raw water. The criteria in SRP-LR 

Section 3.2.2.2.3, item 1, recommend that a plant-specific AMP be evaluated because moisture 

and water can egress under the tank if the perimeter seal is degraded. The applicant stated 

that this item is not applicable because the item is only applicable to PWR plants and because 

there are no partially encased stainless steel tanks exposed to raw water in the ESF systems. 

The staff evaluated the applicant’s claim and finds it acceptable because, based on a review of 

LRA Section 3.2 and the UFSAR, there are no partially encased stainless steel tanks exposed 

to raw water in the ESF systems.

Item 2. LRA Section 3.2.2.2.3, item 2, associated with LRA Table 3.2.1, item 3.2.1-4, addresses 

loss of material due to pitting and crevice corrosion in stainless steel piping, piping components, 
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piping elements, and tanks exposed to outdoor air. The criteria in SRP-LR Section 3.2.2.2.3, 

item 2, state that loss of material could occur for stainless steel components exposed to outdoor 

air environments that containing sufficient halide and environments in which condensation or 

deliquescence is possible. The SRP-LR further states that GALL Report AMP XI.M36, “External 

Surfaces Monitoring of Mechanical Components,” is an acceptable method to manage the aging 

effect. The applicant addressed the further evaluation criteria of the SRP-LR and stated that 

this item is applicable to its units and is within the scope of license renewal. The applicant also 

stated that it will implement the External Surfaces Monitoring of Mechanical Components 

program to manage loss of material due to pitting and crevice corrosion in stainless steel piping, 

piping components, and piping elements exposed to outdoor air in the Reactor Core Isolation 

Cooling System.

The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical 

Components program is documented in SER Section 3.0.3.1.12. The staff noted that the 

applicant’s External Surfaces Monitoring of Mechanical Components program, when 

implemented, includes periodic representative inspections of components in which

condensation could occur; therefore, the program will be capable of managing the aging effect. 

In its review of the components associated with item 3.2.1-4, the staff finds that the applicant 

has met the further evaluation criteria and that the applicant’s proposal to manage the effects of 

aging using the External Surfaces Monitoring of Mechanical Components program is acceptable 

because the applicant’s program includes periodic inspections that can detect loss of material 

due to pitting and crevice corrosion.

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.2.2.2.3, item 2, criteria. For those components associated with LRA 

Section 3.2.2.2.3, item 2, the staff concludes that LRA is consistent with the GALL Report and 

that the applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3).

Loss of Material Due to Erosion

LRA Section 3.2.2.2.4, associated with LRA Table 3.2.1, item 3.2.1-5, addresses stainless steel 

high-pressure safety injection pump minimum flow recirculation orifices exposed to treated 

borated water. The applicant stated that item 3.2.1-5 is not applicable because it only applies to 

PWRs. The staff evaluated the applicant’s claim and finds it acceptable because item 3.2.1-5 

addresses the use of the high-pressure safety injection pumps for normal charging in PWRs and 

does not apply to LSCS.

Loss of Material Due to General Corrosion and Fouling That Leads to Corrosion

LRA Section 3.2.2.2.5, associated with LRA Table 3.2.1, item 3.2.1-6, addresses loss of 

material due to general corrosion and fouling that leads to corrosion in steel drywell and 

suppression chamber spray system nozzle and flow orifice internal surfaces exposed to 

uncontrolled indoor air. The applicant stated that, for item 3.2.1-6, the applicability is limited to 

steel orifices or spray nozzles exposed to indoor air and, therefore, is not applicable. The staff 

confirmed that the applicant’s containment spray nozzles are stainless steel and that no steel 

orifices are present in the containment spray subsystem.

However, the staff noted that this further evaluation subsection includes plugging of the spray 

nozzles and discusses internal surface corrosion of the steel spray systems in the drywell and 
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suppression chamber. The staff also noted that nozzle plugging can be caused by the buildup 

of corrosion products from upstream components, not just corrosion of the nozzles themselves. 

The staff further noted that even though this system is in standby for the majority of time, the 

wetting and drying of these components can accelerate corrosion and lead to flow blockage due 

to fouling. Based on this, by letter dated July 27, 2015, the staff issued RAI 3.2.2.2.5-1, 

requesting that the applicant provide the bases for not needing a plant-specific AMP to manage 

plugging of spray nozzles caused by accelerated corrosion of steel components upstream of the 

nozzles due to occasional wetting and drying. In addition, the RAI asked the applicant to clarify 

which environment (condensation or treated water) is being considered and to discuss whether 

the suppression pool spray header will be considered as a unique environment due to the 

variations in flow or to provide the bases for considering it as part of a larger population from a 

sampling perspective.

In its response dated August 26, 2015, the applicant stated that plugging of the drywell and 

suppression pool spray nozzles will be managed by the new Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program. The applicant also stated that it does 

not consider the environment for these spray nozzles to be unique, but it did consider “flow 

blockage” as a unique aging effect that warranted a separate population for a sample within the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program. The 

applicant revised LRA Sections A.2.1.25 and B.2.1.25 to include flow blockage of the spray 

nozzles in the associated AMP and revised Table 3.2.2-4, “Residual Heat Removal System

Summary of Aging Management Evaluation,” to include “flow blockage” as an AERM for the 

stainless steel spray nozzles in the drywell and suppression pool. The staff notes that the new 

AMR item added to Table 3.2.2-4 cites generic note H, indicating that the aging effect is not in 

the GALL Report for this component, material, and environment combination.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components program is documented in SER Section 3.0.3.1.13. The staff finds 

the response acceptable because the applicant included flow blockage as an additional AERM

and revised the above AMP to include this aging effect in periodic sampling for the program. 

The staff’s concerns described in RAI 3.2.2.2.5-1 are resolved.

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.2.2.2.5. For those items associated with LRA Section 3.2.2.2.5, the staff 

concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

Cracking Due to Stress Corrosion Cracking

LRA Section 3.2.2.2.6, associated with LRA Table 3.2.1, item 3.2.1-7, addresses cracking due 

to SCC in stainless steel piping, piping components, piping elements, and tanks exposed to 

outdoor air. The criteria in SRP-LR Section 3.2.2.2.6 state that cracking could occur for 

stainless steel components exposed to outdoor air environments containing sufficient halides 

and environments in which condensation or deliquescence is possible. The SRP-LR further 

states that GALL Report AMP XI.M36, “External Surfaces Monitoring of Mechanical 

Components,” is an acceptable method to manage the aging effect. The applicant addressed 

the further evaluation criteria of the SRP-LR and stated that this item is applicable to its units 

and within the scope of license renewal. The applicant also stated that it will implement the 

External Surfaces Monitoring of Mechanical Components program to manage cracking due to 
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SCC in stainless steel piping, piping components, and piping elements exposed to outdoor air in 

the Reactor Core Isolation Cooling System.

The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical 

Components program is documented in SER Section 3.0.3.1.12. The staff noted that the 

applicant’s External Surfaces Monitoring of Mechanical Components program, when 

implemented, includes periodic representative inspections of components in which

condensation could occur; therefore, the program will be capable of managing the aging effect. 

In its review of the components associated with item 3.2.1-7, the staff finds that the applicant 

has met the further evaluation criteria and that its proposal to manage the effects of aging using 

the External Surfaces Monitoring of Mechanical Components program is acceptable because 

the applicant’s program includes periodic inspections, which can detect cracking due to SCC.

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.2.2.2.6 criteria. For those components associated with LRA 

Section 3.2.2.2.6, the staff concludes that the LRA is consistent with the GALL Report and that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program.

Ongoing Review of Operating Experience

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience of AMPs.

Loss of Material Due to Recurring Internal Corrosion

LRA Section 3.2.2.2.9, associated with LRA Table 3.2.1, item 3.2.1-66, addresses loss of 

material due to recurring internal corrosion in metallic piping, piping components, and tanks 

exposed to raw or waste water. The criteria in SRP-LR Section 3.2.2.2.9 state that AMPs may 

need to be augmented beyond the recommendations in the GALL Report if recurring internal 

corrosion is identified during searches of plant-specific operating experience conducted for the 

development of the LRA. The applicant stated that this item is not applicable because its review 

of operating experience for Engineered Safety Features systems did not identify instances of 

recurring internal corrosion with the threshold frequency specified in LR-ISG-2012-02. The staff 

evaluated the applicant’s claim and finds it acceptable because, as noted in the AMP Audit 

Report, the staff conducted an independent search of the past 10 years of operating experience 

reports and did not identify repetitive occurrences of internal corrosion in Engineered Safety 

Features systems with a frequency greater than that given in LR-ISG-2012-02.

3.2.2.3 Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.2.2-1 through 3.2.2-5, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations that are not consistent with, or are not 

addressed in, the GALL Report.
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In LRA Tables 3.2.2-1 through 3.2.2-5, the applicant indicated, through notes F through J, that 

the combination of component type, material, environment, and AERM does not correspond to 

an item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, note F indicates that the material for the AMR item

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR item component and material is not evaluated in the GALL Report. Note H indicates that 

the aging effect for the AMR item component, material, and environment combination is not 

evaluated in the GALL Report. Note I indicates that the aging effect identified in the 

GALL Report for the item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the item is evaluated in the GALL Report.

For component type, material, and environment combinations that are not evaluated in the 

GALL Report, the staff reviewed the applicant’s evaluation to determine whether the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. 

The staff’s evaluation is documented in the following sections.

High Pressure Core Spray System – Summary of Aging Management Review –

LRA Table 3.2.2-1

The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations for the 

High Pressure Core Spray System component groups.

Zinc Piping, Piping Components, and Piping Elements Exposed to Uncontrolled Indoor Air. In 

LRA Tables 3.2.2-1, 3.2.2-2, and 3.2.2-3, the applicant stated that zinc casting piping, piping 

components, and piping elements exposed to uncontrolled indoor air are not subject to any 

AERM. The AMR items cite generic note F. The AMR items also cite plant-specific note 3, 

which states that even though there is no expected aging effect for the zinc components 

exposed to indoor air, the External Surfaces Monitoring of Mechanical Components program will 

be used to ensure the absence of any aging effects.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that, although zinc alloys have good 

corrosion resistance under atmospheric conditions, the applicant has proposed to use the 

External Surfaces Monitoring of Mechanical Components program to ensure that aging is not 

occurring. The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical 

Components program is documented in SER Section 3.0.3.1.12. The staff finds the applicant’s 

proposal to monitor any potential aging effect using the External Surfaces Monitoring of 

Mechanical Components program acceptable because the periodic inspections conducted by 

the program are capable of detecting loss of material, cracking, and other surface degradation if 

it is occurring.

Zinc Piping, Piping Components, and Piping Elements Exposed to Lubricating Oil. In LRA 

Tables 3.2.2-1, 3.2.2-2, and 3.2.2-3, the applicant stated that zinc piping, piping components, 

and piping elements exposed internally to lubricating oil will be managed for loss of material by 

the Lubricating Oil Analysis and One-Time Inspection programs. The AMR items cite generic 

note F with a plant-specific note 4, which states that “the component is zinc casting exposed to 

lubricating oil and is susceptible to loss of material.”
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The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. Based on its review of the GALL Report, which states 

that galvanized steel (i.e., steel coated with a protective zinc coating) exposed to outdoor air 

(i.e., condensation) should be managed for loss of material, the staff finds that the applicant has 

identified all credible aging effects for this component, material, and environment combination.

The staff’s evaluation of the applicant’s Lubricating Oil Analysis and One-Time Inspection 

programs is documented in SER Sections 3.0.3.1.14 and 3.0.3.1.9, respectively. The staff finds 

the applicant’s proposal to manage the effects of aging using the Lubricating Oil Analysis and 

One-Time Inspection programs acceptable because lubricating oil testing (sampling and 

analysis) and condition monitoring will identify detrimental contaminants, such as water, 

sediments, specific wear elements, and elements from an outside source. The contaminant 

levels are trended in the program’s database, and recommendations are made when adverse 

trends are observed, which could include in-leakage and corrosion product buildup. 

Additionally, the One-Time Inspection program that will be used to verify the system-wide 

effectiveness of the Lubricating Oil Analysis program by inspections focusing on locations that 

are isolated from the flow stream, that are stagnant, or that have low flow for extended periods

of time and are susceptible to the gradual accumulation or concentration of agents that promote 

certain aging effects.

Low Pressure Core Spray System – Summary of Aging Management Review –

LRA Table 3.2.2-2

The staff reviewed LRA Table 3.2.2-2, which summarizes the results of AMR evaluations for the 

Low Pressure Core Spray System component groups.

Zinc Piping, Piping Components, and Piping Elements Exposed to Uncontrolled Indoor Air. The 

staff’s evaluation for zinc piping, piping components, and piping elements exposed to 

uncontrolled indoor air, which will be managed by the External Surfaces Monitoring of 

Mechanical Components program and is associated with generic note F, is documented in SER 

Section 3.2.2.3.1.

Zinc Piping, Piping Components, and Piping Elements Exposed to Lubricating Oil. The staff’s 

evaluation of zinc piping, piping components, and piping elements exposed to lubricating oil, 

which will be managed for loss of material by the Lubricating Oil Analysis and One-Time 

Inspection programs and is associated with generic note F, is documented in SER 

Section 3.2.2.3.1.

Reactor Core Isolation Cooling System – Summary of Aging Management 

Evaluation – LRA Table 3.2.2-3

The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for the 

Reactor Core Isolation Cooling System component groups.

Carbon Steel Turbine Lube Oil Reservoirs with Internal Coatings Exposed to Lubricating Oil. In 

LRA Table 3.2.2-3, the applicant states that carbon steel turbine lube oil reservoirs with internal 

coatings exposed to lubricating oil will be managed for loss of coating integrity by the Service 

Level III and Service Level III Augmented Coatings Monitoring and Maintenance Program. The 

AMR item cites generic note H.
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The staff noted that this material and environment combination is identified in LR-ISG-2013-01, 

“Aging Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on 

In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.” LR-ISG-2013-01 

Table 3.2-1, item 3.2.1-72, states that loss of coatings integrity for metallic piping, piping 

components, heat exchangers, and tanks with internal coatings/linings exposed to lubricating oil 

is managed by GALL Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping 

Components, Heat Exchangers, and Tanks.” The staff noted that given that LR-ISG-2013-01 

was in a draft versus final status when the LRA was developed, the applicant chose to develop 

a plant-specific program to manage loss of coating integrity.

The staff’s evaluation of the applicant’s Service Level III and Service Level III Augmented 

Coatings Monitoring and Maintenance Program is documented in SER Section 3.0.3.3.1. 

The staff finds the applicant’s proposal to manage loss of coating integrity using the Service 

Level III and Service Level III Augmented Coatings Monitoring and Maintenance Program 

acceptable because the program includes periodic visual inspections capable of detecting loss 

of coating integrity by qualified individuals.

Copper Alloy Heat Exchanger Tubes Internally Exposed to Treated Water. In LRA 

Table 3.2.2-3, the applicant stated that copper alloy with 15-percent zinc or more internally 

exposed to treated water will be managed for cracking by the Water Chemistry program. The 

AMR item cites generic note H, and plant-specific note 7, which states that aging effects for 

copper alloy with 15-percent zinc or more in a treated water environment include cracking. The 

One-Time Inspection and Water Chemistry programs are used to manage cracking for copper 

alloy with 15-percent zinc or more in a treated water environment.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that copper alloy with 15-percent zinc or more exposed to treated water is 

susceptible to selective leaching and recommends GALL Report AMP XI.M33, “Selective 

Leaching,” to manage the aging effect. However, the applicant has identified cracking as an 

additional aging effect. The applicant addressed the GALL Report-identified aging effects for 

this component, material, and environment combination in other AMR items in LRA 

Table 3.2.2-3.

The staff’s evaluation of the applicant’s Water Chemistry and One-Time Inspection programs is 

documented in SER Sections 3.0.3.2.1 and 3.0.3.1.9, respectively. The staff finds the 

applicant’s proposal to manage the effects of aging using the Water Chemistry program 

acceptable because the program consists of periodic monitoring of the treated water to control 

known detrimental contaminants, such as chlorides, dissolved oxygen, and sulfate 

concentrations, so that they remain below the levels known to result in loss of material or 

cracking. The staff noted that the One-Time Inspection program will be used to verify the 

system-wide effectiveness of the Water Chemistry program by inspections focusing on locations 

that are isolated from the flow stream, that are stagnant, or that have low flow for extended 

periods and are susceptible to the gradual accumulation or concentration of agents that promote 

certain aging effects. Additionally, the One-Time Inspection program verifies either that 

unacceptable degradation is not occurring or triggers additional actions that will ensure that the 

intended function of affected components will be maintained during the period of extended 

operation.

Stainless Steel Piping, Piping Components, and Piping Elements Exposed to Soil. In LRA 

Table 3.2.2-3, the applicant stated that stainless steel piping, piping components, and piping 
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elements exposed to soil will be managed for cracking by the Buried and Underground Piping 

program. The AMR item cites generic note H.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that stainless steel piping, piping components, and piping elements exposed to soil 

are susceptible to loss of material due to pitting and crevice corrosion and recommends 

GALL Report AMP XI.M41 to manage the aging effect. However, the applicant has cracking as 

an additional aging effect. The applicant addressed the aging effects identified in the GALL 

Report for this component, material, and environment combination in other AMR items in LRA 

Table 3.2.2-3.

The staff’s evaluation of the applicant’s Buried and Underground Piping program is documented 

in SER Section 3.0.3.2.14. The staff finds the applicant’s proposal to manage cracking using 

the Buried and Underground Piping program acceptable because the program includes periodic 

visual inspections capable of detecting cracking in buried stainless steel piping.

Zinc Piping, Piping Components, and Piping Elements Exposed to Uncontrolled Indoor Air. The 

staff’s evaluation for zinc piping, piping components, and piping elements exposed to 

uncontrolled indoor air, which will be managed by the External Surfaces Monitoring of 

Mechanical Components program and is associated with generic note F, is documented in SER 

Section 3.2.2.3.1.

Zinc Piping, Piping Components, and Piping Elements Exposed to Lubricating Oil. The staff’s 

evaluation of zinc piping, piping components, and piping elements exposed to lubricating oil, 

which will be managed for loss of material by the Lubricating Oil Analysis and One-Time 

Inspection programs and is associated with generic note F, is documented in SER 

Section 3.2.2.3.1.

Residual Heat Removal System – of Aging Management Evaluation –

LRA Table 3.2.2-4

The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for the 

Residual Heat Removal System component groups.

Nickel Alloy Flow Device Exposed to Treated Water. In LRA Table 3.2.2-4, the applicant stated 

that the nickel alloy flow device internally exposed to treated water will be managed for loss of 

material by the Water Chemistry program. The AMR items cite generic note G, and 

plant-specific note 3, which states that the Water Chemistry (LRA Section B.2.1.2) program and 

One-Time Inspection (LRA Section B.2.1.21) program are used to manage the aging effect(s) 

applicable to this component type, material, and environment combination.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff reviewed ASM Specialty Handbook – Nickel, 

Cobalt, and Their Alloys, dated December 2000, which states that nickel alloys, such as alloy 

600 from which the elements are constructed, are “highly resistant to general corrosion and 

stress corrosion cracking but can be attacked at high caustic concentrations and temperatures.” 

In addition, SCC has also been found to occur in environments with elevated levels of halides 

and sulfur species. As documented in SER Section 3.0.3.2.1, the staff found that the applicant’s 

Water Chemistry program includes periodic monitoring of the treated water and control of known 

detrimental contaminants in accordance with EPRI 3002002623, “BWR Water Chemistry 
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Guidelines,” Revision 1. These guidelines include the monitoring of chlorides, fluorides, 

sulfates, and sodium (as an indicator for the presence of (caustic) sodium hydroxide). During 

the audit, the staff verified that the applicant monitors these parameters periodically. Therefore, 

cracking is not a likely aging effect. The staff finds that the applicant has identified all credible 

aging effects for this component, material, and environment combination.

The staff’s evaluations of the applicant’s Water Chemistry and One-Time Inspection programs 

are documented in SER Sections 3.0.3.2.1 and 3.0.3.1.9, respectively. The applicant’s Water 

Chemistry program manages loss of material, cracking, and reduction in heat transfer in 

components exposed to a treated water environment through periodic monitoring and control of 

water chemistry. The One-Time Inspection program performs focused inspections of 

components susceptible to certain aging effects to verify the effectiveness of the water 

chemistry controls. The staff finds the applicant’s proposal to manage loss of material using the 

Water Chemistry and One-Time Inspection programs acceptable because maintaining proper 

primary water chemistry will control certain parameters known to contribute to corrosion and 

because a one-time inspection of components in low flow and stagnant areas will confirm the 

effectiveness of the Water Chemistry program (i.e., that age-related degradation is not 

occurring).

Standby Gas Treatment System – Summary of Aging Management Evaluation –

LRA Table 3.2.2-5

The staff reviewed LRA Table 3.2.2-5, which summarizes the results of AMR evaluations for the 

Standby Gas Treatment System component groups.

Elastomers (Flexible Connections) Exposed to Condensation. In LRA Table 3.2.2-5, the 

applicant stated that elastomers exposed to condensation will be managed for hardening, loss 

of strength, and loss of material by the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components program. The AMR items cite generic note G.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. Based on its review of the GALL Report, which states 

that elastomers exposed to condensation are susceptible to hardening, loss of strength, and 

loss of material, the staff finds that the applicant has identified all credible aging effects for this 

component, material, and environment combination.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components program is documented in SER Section 3.0.3.1.13. The staff finds 

the applicant’s proposal to manage aging using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program acceptable because the opportunistic 

visual inspections conducted by the program, with a representative sample of components 

periodically inspected, are capable of detecting hardening, loss of strength, and loss of material 

in elastomers by observing for cracking, other surface discontinuities, and discoloration.

3.2.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the ESF systems components within the scope of license renewal and 

subject to an AMR will be adequately managed so that the intended function(s) will be 
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maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3 Aging Management of Auxiliary Systems

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

auxiliary systems components of the following:

• Closed-Cycle Cooling Water System

• Combustible Gas Control System

• Compressed Air System

• Control Rod Drive System

• Control Room Ventilation System

• Cranes, Hoists, and Refueling Equipment System

• Demineralized Water Makeup System

• Diesel Generator and Auxiliaries System

• Drywell Pneumatic System

• Electrical Penetration Pressurization System

• Essential Cooling Water System

• Fire Protection System

• Fuel Pool Cooling and Storage System

• Nonessential Cooling Water System

• Nonsafety-Related Ventilation System

• Plant Drainage System

• Primary Containment Ventilation System

• Process Radiation Monitoring System

• Process Sampling and Post-Accident Monitoring System

• Radwaste System

• Reactor Water Cleanup System

• Safety-Related Ventilation System

• Standby Liquid Control System

• Suppression Pool Cleanup System

• Traversing Incore Probe System

3.3.1 Summary of Technical Information in the Application

LRA Section 3.3 provides AMR results for the auxiliary systems components and component 

groups. LRA Table 3.3.1, “Summary of Aging Management Evaluations for the Auxiliary 

Systems,” is a summary comparison of the applicant’s AMRs with those evaluated in the 

GALL Report for the auxiliary systems components.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report.
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3.3.2 Staff Evaluation

The staff reviewed LRA Section 3.3 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the auxiliary systems components within 

the scope of license renewal and subject to an AMR will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

The staff conducted a review of the applicant’s AMRs to verify the applicant’s claim that certain 

AMRs are consistent with the GALL Report or are not applicable. The staff did not repeat its 

review of the matters described in the GALL Report; however, the staff did verify that the 

material presented in the LRA is applicable and that the applicant identified the appropriate 

GALL Report AMRs. AMRs that the staff confirmed are consistent with the GALL Report are 

noted as such in Table 3.3-1; therefore, no further discussion is required. AMRs that the staff 

confirmed are not applicable to LSCS or require no aging management are noted in Table 3.3-1 

and discussed in SER Section 3.3.2.1.1. Details of the staff’s evaluation of AMRs that the 

applicant claimed are consistent with the GALL Report, but for which a different AMP from the 

program recommended in the GALL Report is used to manage aging, and AMRs for which the 

staff requested additional information, are documented in SER Sections 3.3.2.1.2 

through 3.3.2.1.9.

During its review, the staff also reviewed AMRs that are consistent with the GALL Report and 

those for which further evaluation is recommended. The staff confirmed that the applicant’s 

further evaluations are consistent with the SRP-LR Section 3.3.2.2 acceptance criteria. The 

staff’s evaluations of AMRs for which the GALL Report recommends further evaluation are 

documented in SER Section 3.3.2.2.

The staff also conducted a technical review of the remaining AMRs that are not consistent with 

or are not addressed in the GALL Report. The technical review evaluated whether all plausible 

aging effects have been identified and whether the aging effects listed are appropriate for the 

material-environment combinations specified. The staff’s evaluations of AMRs that are not 

consistent with, or are not addressed in, the GALL Report are documented in SER 

Section 3.3.2.3.

Table 3.3-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.3 and addressed in the GALL Report.
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Staff Evaluation for Auxiliary Systems Components in the GALL Report

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel Cranes: 

structural girders 

exposed to Air –

indoor, uncontrolled 

(external) (3.3.1-1)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a timelimited aging 

analysis (TLAA) to 

be evaluated for the 

period of extended 

operation for 

structural girders of 

cranes that fall within 

the scope of 

10 CFR 54 

(Standard Review 

Plan, Section 4.7, 

“Other Plant-Specific 

Time-Limited Aging 

Analyses,” for 

generic guidance for 

meeting the 

requirements of 

10 CFR 54.21(c)(1))

Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.3.2.2.1)

Stainless steel, steel 

heat exchanger 

components and 

tubes, piping, piping 

components, and 

piping elements 

exposed to treated 

borated water, air -

indoor, uncontrolled, 

treated water 

(3.3.1-2)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a timelimited aging 

analysis (TLAA) to 

be evaluated for the 

period of extended 

operation. See the 

SRP, Section 4.3 

“Metal Fatigue,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1).

Yes TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.2.1)

Stainless steel heat 

exchanger 

components, nonregenerative 

exposed to treated 

borated water >60°C 

(>140°F) (3.3.1-3)

Cracking due to 

stress corrosion 

cracking; cyclic 

loading

Chapter XI.M2, 

“Water Chemistry”

The AMP is to be 

augmented by 

verifying the 

absence of cracking 

due to stress 

corrosion cracking 

and cyclic loading. 

An acceptable 

verification program 

is to include 

temperature and 

radioactivity 

monitoring of the 

shell side water, and 

eddy current testing 

of tubes.

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.3.2.2.2)

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to air 

– outdoor (3.3.1-4)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.2.3)
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Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel (with stainless 

steel or nickel-alloy 

cladding) pump 

casings exposed to 

treated borated 

water (3.3.1-5)

Loss of material 

due to cladding 

breach

A plant-specific 

aging management 

program is to be 

evaluated. 

Reference NRC 

Information Notice 

94-63, “Boric Acid 

Corrosion of 

Charging Pump 

Casings Caused by 

Cladding Cracks.”

Yes Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.3.2.2.4)

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

air–outdoor (3.3.1-6)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.2.5)

Stainless steel highpressure pump, 

casing exposed to 

treated borated 

water (3.3.1-7)

Cracking due to 

cyclic loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.3.2.1.1)

stainless steel heat 

exchanger 

components and 

tubes exposed to 

treated borated 

water >60°C 

(>140°F) (3.3.1-8)

Cracking due to 

cyclic loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.3.2.1.1)

Steel, aluminum, 

copper alloy (>15% 

Zn or >8% Al) 

external surfaces, 

piping, piping 

components, and 

piping elements, 

bolting exposed to 

air with borated 

water leakage 

(3.3.1-9)

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.3.2.1.1)

Steel, high-strength 

closure bolting 

exposed to air with 

steam or water 

leakage (3.3.1-10)

Cracking due to 

stress corrosion

cracking; cyclic 

loading

Chapter XI.M18, 

“Bolting Integrity”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Steel, high-strength 

high-pressure pump, 

closure bolting 

exposed to air with 

steam or water 

leakage (3.3.1-11)

Cracking due to 

stress corrosion 

cracking; cyclic 

loading

Chapter XI.M18, 

“Bolting Integrity”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)
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Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel; stainless steel 

closure bolting, 

bolting exposed to 

condensation, air –

indoor, uncontrolled 

(external), air –

outdoor (external) 

(3.3.1-12)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Steel closure bolting 

exposed to air with 

steam or water 

leakage (3.3.1-13)

Loss of material 

due to general 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Steel, stainless steel 

bolting exposed to 

soil (3.3.1-14)

Loss of preload Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Steel; stainless 

steel, copper alloy, 

nickel alloy, stainless 

steel closure bolting, 

bolting exposed to 

air – indoor, 

uncontrolled 

(external), any 

environment, air –

outdoor (external), 

raw water, treated 

borated water, fuel 

oil, treated water 

(3.3.1-15)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water >60°C 

(>140°F) (3.3.1-16)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M25, 

“BWR Reactor 

Water Cleanup 

System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Stainless steel heat 

exchanger tubes 

exposed to treated 

water, treated 

borated water 

(3.3.1-17)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Stainless steel highpressure pump, 

casing, piping, piping 

components, and 

piping elements 

exposed to treated 

borated water >60°C 

(>140°F), sodium 

pentaborate solution 

>60°C (>140°F) 

(3.3.1-18)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,” 

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)
3-235

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel 

regenerative heat 

exchanger 

components 

exposed to treated 

water >60°C 

(>140°F) (3.3.1-19)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection, and

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Stainless steel, 

stainless steel; steel 

with stainless steel 

cladding heat 

exchanger 

components 

exposed to treated 

borated water >60°C 

(>140°F), treated 

water >60°C 

(>140°F) (3.3.1-20)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection, and

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to treated 

water (3.3.1-21)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection, and

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Copper alloy piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.3.1-22)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection, and

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Aluminum piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.3.1-23)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Aluminum Piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.3.1-24)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)
3-236

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel, 

stainless steel; steel 

with stainless steel 

cladding, aluminum 

piping, piping 

components, and 

piping elements, 

heat exchanger 

components 

exposed to treated 

water, sodium 

pentaborate solution 

(3.3.1-25)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection, and

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.2)

Steel with stainless 

steel cladding) 

piping, piping 

components, and 

piping elements 

exposed to treated 

water (3.3.1-26)

Loss of material 

due to pitting 

and crevice 

corrosion (only 

after cladding 

degradation)

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Stainless steel heat 

exchanger tubes 

exposed to treated 

water (3.3.1-27)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection, and

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed 

treated borated 

water (primary, 

oxygen levels 

controlled) >60°C 

(>140°F) (3.3.1-28)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.3.2.1.1)

Steel (with stainless 

steel cladding); 

stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

borated water 

(primary, oxygen 

levels controlled) 

(3.3.1-29)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.3.2.1.1)

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-30)

Changes in 

material 

properties due

to aggressive 

chemical attack

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)
3-237

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Fiberglass, HDPE 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (internal) 

(3.3.1-30x)

Cracking, 

blistering, 

change in color 

due to water 

absorption

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Concrete; 

cementitious 

material Piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-31)

Cracking due to 

settling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Reinforced concrete, 

asbestos cement 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-32)

Cracking due to 

aggressive 

chemical attack 

and leaching; 

Changes in 

material 

properties due 

to aggressive 

chemical attack

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Elastomer seals and 

components 

exposed to raw 

water (3.3.1-32x)

Hardening and 

loss of strength 

due to 

elastomer 

degradation; 

loss of material 

due to erosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-33)

Loss of material 

due to abrasion, 

cavitation, 

aggressive 

chemical attack, 

and leaching

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Nickel alloy, copper 

alloy piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-34)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Copper alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-35)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)
3-238

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Copper alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-36)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-37)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report

Copper alloy, steel 

heat exchanger 

components 

exposed to raw 

water (3.3.1-38)

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-39)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-40)

Loss of material 

due to pitting 

and crevice 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.3)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-41)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.4)

Copper alloy, 

titanium, stainless 

steel heat exchanger 

tubes exposed to 

raw water (3.3.1-42)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report
3-239

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel 

Piping, piping 

components, and 

piping elements 

exposed to closedcycle cooling water 

>60°C (>140°F) 

(3.3.1-43)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report

Stainless steel; steel 

with stainless steel 

cladding heat 

exchanger 

components 

exposed to closedcycle cooling water 

>60°C (>140°F) 

(3.3.1-44)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report

Steel Piping, piping 

components, and 

piping elements; 

tanks exposed to 

closed-cycle cooling 

water (3.3.1-45)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report

Steel, copper alloy 

heat exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to closedcycle cooling water 

(3.3.1-46)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report

Stainless steel; steel 

with stainless steel 

cladding heat 

exchanger 

components 

exposed to closedcycle cooling water 

(3.3.1-47)

Loss of material 

due to 

microbiologically

-influenced 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Aluminum piping, 

piping components, 

and piping elements 

exposed to closedcycle cooling water 

(3.3.1-48)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to closedcycle cooling water 

(3.3.1-49)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report
3-240

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel, 

copper alloy, steel 

heat exchanger 

tubes exposed to 

closed-cycle cooling 

water (3.3.1-50)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report

BoraflexTM spent fuel 

storage racks: 

neutron-absorbing 

sheets (PWR), spent 

fuel storage racks: 

neutron-absorbing 

sheets (BWR) 

exposed to treated 

borated water, 

treated water 

(3.3.1-51)

Reduction of 

neutronabsorbing 

capacity due to 

BoraflexTM

degradation

Chapter XI.M22, 

“Boraflex Monitoring”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Steel Cranes: rails 

and structural 

girders exposed to 

air – indoor, 

uncontrolled 

(external) (3.3.1-52)

Loss of material 

due to general 

corrosion

Chapter XI.M23, 

“Inspection of 

Overhead Heavy 

Load and Light Load 

(Related to 

Refueling) Handling 

Systems”

No Inspection of 

Overhead Heavy 

Load and Light 

Load (Related to 

Refueling) 

Handling Systems

Consistent with the 

GALL Report

Steel Cranes - rails 

exposed to air –

indoor, uncontrolled 

(external) (3.3.1-53)

Loss of material 

due to wear

Chapter XI.M23, 

“Inspection of 

Overhead Heavy 

Load and Light Load 

(Related to 

Refueling) Handling 

Systems”

No Inspection of 

Overhead Heavy 

Load and Light 

Load (Related to 

Refueling) 

Handling Systems

Consistent with the 

GALL Report

Copper alloy piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(3.3.1-54)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M24, 

“Compressed Air 

Monitoring”

No Compressed Air 

Monitoring

Consistent with the 

GALL Report

Steel Piping, piping 

components, and 

piping elements: 

compressed air 

system exposed to 

condensation 

(internal) (3.3.1-55)

Loss of material 

due to general 

and pitting 

corrosion

Chapter XI.M24, 

“Compressed Air 

Monitoring”

No Compressed Air 

Monitoring

An exception 

applies to the 

Compressed Air 

Monitoring

program

Consistent with the 

GALL Report

Stainless steel 

Piping, piping 

components, and 

piping elements 

exposed to 

condensation 

(internal) (3.3.1-56)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M24, 

“Compressed Air 

Monitoring”

No Compressed Air 

Monitoring

An exception 

applies to the 

Compressed Air 

Monitoring

program

Consistent with the 

GALL Report
3-241

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Elastomers fire 

barrier penetration 

seals exposed to airindoor, uncontrolled, 

air – outdoor 

(3.3.1-57)

Increased 

hardness; 

shrinkage; loss

of strength due 

to weathering

Chapter XI.M26, 

“Fire Protection”

No Fire Protection Consistent with the 

GALL Report

Steel halon/carbon 

dioxide fire 

suppression system 

piping, piping 

components, and 

piping elements 

exposed to air –

indoor, uncontrolled 

(external) (3.3.1-58)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M26, 

“Fire Protection”

No Fire Protection Consistent with the 

GALL Report

Steel fire rated doors 

exposed to air -

indoor, uncontrolled, 

air – outdoor 

(3.3.1-59)

Loss of material 

due to wear

Chapter XI.M26, 

“Fire Protection”

No Fire Protection Consistent with the 

GALL Report

Reinforced concrete 

structural fire 

barriers: walls, 

ceilings and floors 

exposed to air -

indoor, uncontrolled 

(3.3.1-60)

Concrete 

cracking and 

spalling due to 

aggressive 

chemical attack, 

and reaction 

with aggregates

Chapter XI.M26, 

“Fire Protection,”

and Chapter XI.S6, 

“Structures 

Monitoring”

No Fire Protection, 

and 

Structures 

Monitoring

Consistent with the 

GALL Report

Reinforced concrete 

structural fire 

barriers: walls, 

ceilings and floors 

exposed to air –

outdoor (3.3.1-61)

Cracking, loss 

of material due 

to freeze-thaw, 

aggressive 

chemical attack, 

and reaction 

with aggregates

Chapter XI.M26, 

“Fire Protection,”

and Chapter XI.S6, 

“Structures

Monitoring”

No Fire Protection, 

and 

Structures 

Monitoring

Consistent with the 

GALL Report

Reinforced concrete 

structural fire 

barriers: walls, 

ceilings and floors 

exposed to air -

indoor, uncontrolled, 

air – outdoor 

(3.3.1-62)

Loss of material 

due to corrosion 

of embedded 

steel

Chapter XI.M26, 

“Fire Protection,”

and Chapter XI.S6, 

“Structures 

Monitoring”

No Fire Protection, 

and 

Structures 

Monitoring

Consistent with the 

GALL Report

Steel fire hydrants 

exposed to air –

outdoor (3.3.1-63)

Loss of material

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M27, 

“Fire Water System”

No Fire Water System

Exceptions apply 

to the Fire Water 

System program

Consistent with the 

GALL Report
3-242

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel, copper alloy 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-64)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion; flow 

blockage due to 

fouling

Chapter XI.M27, 

“Fire Water System”

No Fire Water 

System, and 

Bolting Integrity

Exceptions apply 

to the Fire Water 

System program

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.5)

Aluminum piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-65)

Loss of material 

due to pitting 

and crevice 

corrosion, 

fouling that 

leads to 

corrosion; flow 

blockage due to 

fouling

Chapter XI.M27, 

“Fire Water System”

No Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.6)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-66)

Loss of material 

due to pitting 

and crevice 

corrosion; 

fouling that 

leads to 

corrosion; flow 

blockage due to 

fouling

Chapter XI.M27, 

“Fire Water System”

No Fire Water System

Exceptions apply 

to the Fire Water 

System program

Consistent with the 

GALL Report

Steel tanks exposed 

to air – outdoor 

(external) (3.3.1-67)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to fuel oil 

(3.3.1-68)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M30, 

“Fuel Oil Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Copper alloy piping, 

piping components, 

and piping elements 

exposed to fuel oil 

(3.3.1-69)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M30, 

“Fuel Oil Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Fuel Oil 

Chemistry, and 

One-Time 

Inspection

Consistent with the 

GALL Report
3-243

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements; 

tanks exposed to 

fuel oil (3.3.1-70)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M30, 

“Fuel Oil Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Fuel Oil 

Chemistry, and 

One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel, 

aluminum piping, 

piping components, 

and piping elements 

exposed to fuel oil 

(3.3.1-71)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M30, 

“Fuel Oil Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Fuel Oil 

Chemistry, and 

One-Time 

Inspection

Consistent with the 

GALL Report

Gray cast iron, 

copper alloy (>15% 

Zn or >8% Al) 

piping, piping 

components, and 

piping elements, 

heat exchanger 

components 

exposed to treated 

water, closed-cycle 

cooling water, soil, 

raw water, waste 

water (3.3.1-72)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Selective 

Leaching

Consistent with the 

GALL Report

Concrete; 

cementitious 

material piping,

piping components, 

and piping elements 

exposed to air –

outdoor (3.3.1-73)

Changes in 

material 

properties due 

to aggressive 

chemical attack

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to air –

outdoor (3.3.1-74)

Cracking due to 

settling

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Reinforced concrete, 

asbestos cement 

piping, piping 

components, and 

piping elements 

exposed to air –

outdoor (3.3.1-75)

Cracking due to 

aggressive 

chemical attack 

and leaching; 

Changes in 

material 

properties due 

to aggressive 

chemical attack

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)
3-244

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Elastomers 

elastomer: seals and 

components 

exposed to air –

indoor, uncontrolled 

(internal/external) 

(3.3.1-76)

Hardening and 

loss of strength 

due to 

elastomer 

degradation

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to air –

outdoor (3.3.1-77)

Loss of material 

due to abrasion, 

cavitation, 

aggressive 

chemical attack, 

and leaching

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Steel piping and 

components 

(external surfaces), 

ducting and 

components 

(external surfaces), 

ducting; closure 

bolting exposed to 

air – indoor, 

uncontrolled 

(external), air –

indoor, uncontrolled 

(external), air –

outdoor (external), 

condensation 

(external) (3.3.1-78)

Loss of material 

due to general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External Surfaces 

Monitoring of 

Mechanical 

Components, and 

Fire Protection

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.7)

Copper alloy piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(external) (3.3.1-79)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Steel heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(external), air –

outdoor (external) 

(3.3.1-80)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report

Copper alloy, 

aluminum piping, 

piping components, 

and piping elements 

exposed to air –

outdoor (external), 

air – outdoor 

(3.3.1-81)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)
3-245

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Elastomers 

elastomer: seals and 

components 

exposed to air –

indoor, uncontrolled 

(external) (3.3.1-82)

Loss of material 

due to wear

Chapter XI.M36,

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report

Stainless steel 

Diesel engine 

exhaust piping, 

piping components, 

and piping elements 

exposed to diesel 

exhaust (3.3.1-83)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Elastomers 

elastomer seals and 

components 

exposed to closedcycle cooling water 

(3.3.1-85)

Hardening and 

loss of strength 

due to 

elastomer 

degradation

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Elastomers, linings, 

elastomer: seals and 

components 

exposed to treated 

borated water, 

treated water, raw 

water (3.3.1-86)

Hardening and 

loss of strength 

due to 

elastomer 

degradation

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

The SRP-LR, as 

amended by ISGs, 

does not list an Item 

No. (3.3.1-87)

N/A N/A N/A N/A N/A

Steel; stainless steel 

piping, piping 

components, and 

piping elements, 

piping, piping 

components, and 

piping elements, 

diesel engine 

exhaust exposed to 

raw water (potable), 

diesel exhaust 

(3.3.1-88)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Steel, copper alloy 

piping, piping 

components, and 

piping elements 

exposed to moist air 

or condensation 

(internal) (3.3.1-89)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

For fire water system 

components: 

Chapter XI.M27, 

“Fire Water System,”

or for other 

components: 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report
3-246

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel ducting and 

components (internal 

surfaces) exposed to 

condensation 

(internal) (3.3.1-90)

Loss of material 

due to general, 

pitting, crevice, 

and (for drip 

pans and drain 

lines) 

microbiologically

-influenced 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.8)

Steel piping, piping 

components, and 

piping elements; 

tanks exposed to 

waste water 

(3.3.1-91)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Aluminum piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(internal) (3.3.1-92)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Copper alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water (potable) 

(3.3.1-93)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Stainless steel 

ducting and 

components 

exposed to 

condensation 

(3.3.1-94)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Copper alloy, 

stainless steel, 

nickel alloy, steel 

piping, piping 

components, and 

piping elements, 

heat exchanger 

components, piping, 

piping components, 

and piping elements; 

tanks exposed to 

waste water, 

condensation 

(internal) (3.3.1-95)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Elastomer: seals and 

components 

exposed to air –

indoor, uncontrolled 

(internal) (3.3.1-96)

Loss of material 

due to wear

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)
3-247

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements, 

reactor coolant 

pump oil collection 

system: tanks, 

reactor coolant 

pump oil collection 

system: piping, 

tubing, valve bodies 

exposed to 

lubricating oil 

(3.3.1-97)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Lubricating Oil 

Analysis, and 

One-Time 

Inspection

Consistent with the 

GALL Report

Steel heat 

exchanger 

components 

exposed to 

lubricating oil 

(3.3.1-98)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Lubricating Oil 

Analysis, and 

One-Time 

Inspection

Consistent with the 

GALL Report

Copper alloy, 

aluminum piping, 

piping components, 

and piping elements 

exposed to

lubricating oil 

(3.3.1-99)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Lubricating Oil 

Analysis, and 

One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil 

(3.3.1-100)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Lubricating Oil 

Analysis, and 

One-Time 

Inspection

Consistent with the 

GALL Report

Aluminum heat 

exchanger tubes 

exposed to 

lubricating oil 

(3.3.1-101)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Lubricating Oil 

Analysis, and 

One-Time 

Inspection

Consistent with the 

GALL Report

Boral®; boron steel, 

and other materials 

(excluding 

BoraflexTM) spent 

fuel storage racks: 

neutron-absorbing 

sheets (PWR), spent 

fuel storage racks: 

neutron-absorbing 

sheets (BWR) 

exposed to treated 

borated water, 

treated water 

(3.3.1-102)

Reduction of 

neutronabsorbing 

capacity; 

change in 

dimensions and 

loss of material 

due to effects of 

SFP 

environment

Chapter XI.M40, 

“Monitoring of 

Neutron-Absorbing 

Materials other than 

Boraflex”

No Monitoring of 

NeutronAbsorbing 

Materials Other 

Than Boraflex

Consistent with the 

GALL Report
3-248

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Reinforced concrete, 

asbestos cement 

piping, piping 

components, and 

piping elements 

exposed to soil or 

concrete (3.3.1-103)

Cracking due to 

aggressive 

chemical attack 

and leaching; 

Changes in 

material 

properties due 

to aggressive 

chemical attack

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

HDPE, fiberglass 

piping, piping 

components, and 

piping elements 

exposed to soil or 

concrete (3.3.1-104)

Cracking, 

blistering, 

change in color 

due to water 

absorption

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Concrete cylinder 

piping, asbestos 

cement pipe piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.3.1-105)

Cracking, 

spalling, 

corrosion of 

rebar due to 

exposure of 

rebar

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Steel (with coating or 

wrapping) piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.3.1-106)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Buried and 

Underground 

Piping

Consistent with the 

GALL Report

Stainless steel, 

nickel alloy piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.3.1-107)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Titanium, super 

austenitic, 

aluminum, copper 

alloy, stainless steel, 

nickel alloy piping, 

piping components, 

and piping elements, 

bolting exposed to 

soil or concrete 

(3.3.1-108)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Steel bolting 

exposed to soil or 

concrete (3.3.1-109)

Loss of material 

due to general, 

pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Buried and 

Underground 

Piping

Consistent with the 

GALL Report
3-249

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Underground 

aluminum, copper 

alloy, stainless steel, 

nickel alloy steel 

piping, piping 

components, and 

piping elements 

(3.3.1-109x)

Loss of material 

due to general 

(steel only), 

pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water >60°C 

(>140°F) (3.3.1-110)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M7, 

“BWR Stress 

Corrosion Cracking,”

and Chapter XI.M2, 

“Water Chemistry”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Steel structural steel 

exposed to air –

indoor, uncontrolled 

(external) 

(3.3.1-111)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to concrete 

(3.3.1-112)

None None, provided 

1) attributes of the 

concrete are 

consistent with 

ACI 318 or ACI 349 

(low water-to-cement 

ratio, low 

permeability, and 

adequate air 

entrainment) as cited 

in NUREG-1557, 

and

2) plant OE indicates 

no degradation of 

the concrete

No, if 

conditions 

are met.

Consistent with 

the GALL Report

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.9)

Aluminum piping, 

piping components, 

and piping elements 

exposed to air – dry 

(internal/external), 

air – indoor, 

uncontrolled 

(internal/external), 

air – indoor, 

controlled (external), 

gas (3.3.1-113)

None None NA - No 

AEM or 

AMP

Consistent with 

the GALL Report

Consistent with the 

GALL Report

Copper alloy piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(internal/external), 

air – dry, gas 

(3.3.1-114)

None None NA - No 

AEM or 

AMP

Consistent with 

the GALL Report

Consistent with the 

GALL Report
3-250

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Copper alloy (≤15% 

Zn and ≤8% Al) 

piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage (3.3.1-115)

None None NA - No 

AEM or 

AMP

Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.3.2.1.1)

Galvanized steel 

piping, piping 

components, and 

piping elements 

exposed to air -

indoor, uncontrolled 

(3.3.1-116)

None None NA - No 

AEM or 

AMP

Consistent with 

the GALL Report

Consistent with the 

GALL Report

Glass Piping 

elements exposed to 

air – indoor, 

uncontrolled 

(external), lubricating 

oil, closed-cycle 

cooling water, air –

outdoor, fuel oil, raw 

water, treated water, 

treated borated 

water, air with 

borated water 

leakage, 

condensation 

(internal/external) 

gas (3.3.1-117)

None None NA - No 

AEM or 

AMP

Consistent with 

the GALL Report

Consistent with the 

GALL Report

Nickel alloy piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(external) 

(3.3.1-118)

None None NA - No 

AEM or 

AMP

Consistent with 

the GALL Report

Consistent with the 

GALL Report

Nickel alloy, PVC, 

glass piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage, air – indoor, 

uncontrolled, 

condensation 

(internal), waste 

water (3.3.1-119)

None None NA - No 

AEM or 

AMP

Consistent with 

the GALL Report

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.9)
3-251

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to air –

indoor, uncontrolled 

(internal/external), 

air – indoor, 

uncontrolled 

(external), air with 

borated water 

leakage, concrete, 

air – dry, gas 

(3.3.1-120)

None None NA - No 

AEM or 

AMP

Consistent with 

the GALL Report

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.9)

Steel piping, piping 

components, and 

piping elements 

exposed to air –

indoor, controlled 

(external), air – dry, 

gas (3.3.1-121)

None None NA - No 

AEM or 

AMP

Consistent with 

the GALL Report

Consistent with the 

GALL Report

Titanium heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

or air – outdoor 

(3.3.1-122)

None None NA - No 

AEM or 

AMP

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Titanium (ASTM 

Grades 1,2, 7, 11, or 

12 that contains > 

5% aluminum or 

more than 0.20% 

oxygen or any 

amount of tin) heat 

exchanger 

components other 

than tubes, piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-123)

None None NA - No 

AEM or 

AMP

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)
3-252

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel, steel 

(with stainless steel 

or nickel-alloy 

cladding) spent fuel 

storage racks 

(BWR), spent fuel 

storage racks 

(PWR), piping, 

piping components, 

and piping elements; 

exposed to treated 

water >60°C 

(>140°F), treated 

borated water >60°C 

(>140°F) (3.3.1-124)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Steel (with stainless 

steel cladding); 

stainless steel spent 

fuel storage racks 

(BWR), spent fuel 

storage racks 

(PWR), piping, 

piping components, 

and piping elements 

exposed to treated 

water, treated 

borated water 

(3.3.1-125)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and 

Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection, and

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Any material, piping, 

piping components, 

and piping elements 

exposed to treated 

water, treated water 

(borated), raw water

(3.3.1-126)

Wall thinning 

due to erosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Metallic piping, 

piping components, 

and tanks exposed 

to raw water or 

waste water 

(3.3.1-127)

Loss of material 

due to recurring 

internal 

corrosion

A plant-specific 

aging management 

program is to be 

evaluated to address 

recurring internal 

corrosion

Yes, plantspecificOpen-Cycle 

Cooling Water 

System, 

Fire Water 

System, and 

Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.2.8)
3-253

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel, stainless 

steel, or aluminum 

tanks (within the 

scope of Chapter 

XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to soil or 

concrete, or the 

following external 

environments airoutdoor, air-indoor 

uncontrolled, moist 

air, condensation

(3.3.1-128)

Loss of material 

due to general 

(steel only), 

pitting, or 

crevice 

corrosion; 

cracking due to 

stress corrosion 

cracking 

(stainless steel 

and aluminum 

only)

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Steel tanks exposed 

to soil or concrete; 

air-indoor 

uncontrolled, raw 

water, treated water, 

waste water, 

condensation 

(3.3.1-129)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Metallic sprinklers 

exposed to airindoor controlled, 

air-indoor 

uncontrolled, airoutdoor, moist air, 

condensation, raw 

water, treated water 

(3.3.1-130)

Loss of material 

due to general 

(where

applicable), 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion, 

fouling that 

leads to 

corrosion; flow 

blockage due to 

fouling

Chapter XI.M27, 

“Fire Water System”

Fire Water System

Exceptions apply 

to the Fire Water 

System program

Consistent with the 

GALL Report

Steel, stainless 

steel, copper alloy, 

or aluminum fire 

water system piping, 

piping components 

and piping elements 

exposed to airindoor uncontrolled 

(internal), airoutdoor(internal), or 

condensation 

(internal) (3.3.1-131)

Loss of material 

due to general 

(steel, and 

copper alloy 

only), pitting, 

crevice, and 

microbiologically

-influenced 

corrosion, 

fouling that 

leads to 

corrosion; flow 

blockage due to 

fouling

Chapter XI.M27, 

“Fire Water System”

No Fire Water System

Exceptions apply 

to the Fire Water 

System program

Consistent with the 

GALL Report
3-254

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Insulated steel, 

stainless steel, 

copper alloy, 

aluminum, or copper 

alloy (> 15% Zn) 

piping, piping 

components, and 

tanks exposed to 

condensation, airoutdoor (3.3.1-132)

Loss of material 

due to general 

(steel, and 

copper alloy 

only), pitting, 

and crevice 

corrosion; 

cracking due to 

stress corrosion 

cracking 

(aluminum, 

stainless steel 

and copper alloy 

(>15% Zn) only)

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” or 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” (for 

tanks only)

No External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report

Underground HDPE

piping, piping 

components, and 

piping elements in 

an air-indoor 

uncontrolled or 

condensation 

(external) 

environment 

(3.3.1-133)

Cracking, 

blistering, 

change in color 

due to water 

absorption

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Steel, stainless 

steel, or copper alloy 

piping, piping 

components, and 

piping elements, and 

heat exchanger 

components 

exposed to a raw 

water environment 

(for nonsafetyrelated components 

not covered by NRC 

GL 89-13) 

(3.3.1-134)

Loss of material 

due to general 

(steel and 

copper alloy 

only), pitting, 

crevice, and 

microbiologically 

influenced 

corrosion, 

fouling that 

leads to 

corrosion

Chapter XI.MI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Steel or stainless 

steel pump casings 

submerged in a 

waste water (internal 

and external) 

environment 

(3.3.1-135)

Loss of material 

due to general 

(steel only), 

pitting, crevice, 

and 

microbiologically 

influenced 

corrosion

Chapter XI.MI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)
3-255

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel, stainless steel 

or aluminum fire 

water storage tanks 

exposed to airindoor uncontrolled, 

air-outdoor, 

condensation, moist 

air, raw water, 

treated water 

(3.3.1-136)

Loss of material 

due to general 

(steel only), 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion, 

fouling that 

leads to 

corrosion; 

cracking due to 

stress corrosion 

cracking 

(stainless steel 

and aluminum 

only)

Chapter XI.M27, 

“Fire Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Steel, stainless steel 

or aluminum tanks 

(within the scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to treated 

water, treated 

borated water 

(3.3.1-137)

Loss of material 

due to general 

(steel only) 

pitting and 

crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.3.2.1.1)

Metallic piping, 

piping components, 

heat exchangers, 

tanks with internal 

coatings/linings 

exposed to closedcycle cooling water, 

raw water, treated 

water, treated 

borated water, waste 

water, lubricating oil, 

or fuel oil (3.3.1-138)

Loss of coating 

or lining integrity 

due to blistering, 

cracking, 

flaking, peeling, 

delamination, 

rusting, or 

physical 

damage, and 

spalling for 

cementitious 

coatings/linings

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks”

No Not Used Not used by LSCS 

(see SER Section 

3.3.2.3.7)

Metallic piping, 

piping components, 

heat exchangers, 

tanks with internal 

coatings/linings 

exposed to closedcycle cooling water, 

raw water, treated 

water, treated 

borated water, or 

lubricating oil 

(3.3.1-139)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks”

No Not Used Not Used 

(see SER 

Section 3.3.2.1.1)
3-256

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Gray cast iron piping 

components with 

internal 

coatings/linings 

exposed to closedcycle cooling water, 

raw water, or treated 

water (3.3.1-140)

Loss of material 

due to selective 

leaching

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks”

No Not Used Not Used 

(see SER 

Section 3.3.2.1.1)

3.3.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.3.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the auxiliary systems components:

• Bolting Integrity

• Buried and Underground Piping

• Closed Treated Water Systems

• Compressed Air Monitoring

• External Surfaces Monitoring of Mechanical Components

• Fire Protection

• Fire Water System

• Flow-Accelerated Corrosion

• Fuel Oil Chemistry

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

• Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems

• Lubricating Oil Analysis

• Monitoring of Neutron-Absorbing Materials Other Than Boraflex

• One-Time Inspection

• Open-Cycle Cooling Water System

• Selective Leaching

• Service Level III and Service Level III Augmented Coatings Monitoring and Maintenance 

Program

• Structures Monitoring

• TLAA

• Water Chemistry

LRA Tables 3.3.2-1 through 3.3.2-25 summarize the AMR results for the auxiliary system 

components and indicate AMRs claimed to be consistent with the GALL Report.
3-257

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components in these 

GALL Report component groups were bounded by the GALL Report evaluation. The applicant 

provided a note for each AMR item. The notes describe how the information in the tables aligns 

with the information in the GALL Report. The staff audited those AMRs with notes A through E, 

which indicate how the AMR was consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these AMR items to confirm consistency with the GALL Report and the validity 

of the AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff audited these AMR items to confirm consistency with 

the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to 

the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant 

was consistent with the AMP identified in the GALL Report and whether the AMR was valid for 

the site-specific conditions.

Note C indicates that the component for the AMR item, although different from that in the 

GALL Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP is consistent with the AMP identified by the GALL Report. Note C indicates 

that the applicant was unable to find a listing of some system components in the GALL Report; 

however, the applicant identified a different component in the GALL Report that had the same 

material, environment, aging effect, and AMP as those of the component under review. The 

staff audited these AMR items to confirm consistency with the GALL Report. The staff also 

determined whether the AMR item of the different component applied to the component under 

review and whether the AMR was valid for the site-specific conditions.

Note D indicates that the component for the AMR item, although different from that in the 

GALL Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff 

audited these AMR items to confirm consistency with the GALL Report and confirmed whether 

the AMR item of the different component was applicable to the component under review. The 

staff confirmed whether it had reviewed and accepted the exceptions to the GALL Report AMPs. 

The staff also determined whether the AMP identified by the applicant was consistent with the 

AMP identified in the GALL Report and whether the AMR was valid for the site-specific 

conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect; however, a different AMP is credited. The staff audited these 

AMR items to confirm consistency with the GALL Report and determined whether the identified 

AMP would manage the aging effect consistent with the AMP identified in the GALL Report and 

whether the AMR was valid for the site-specific conditions.

The staff did not repeat its review of the matters described in the GALL Report for those items 

that the staff determined were bounded by the GALL Report evaluation. However, it did confirm 

that the material presented in the LRA was applicable and that the applicant identified the 

appropriate GALL Report AMRs. The staff’s evaluation is discussed below.
3-258

AMR Results Identified as Not Applicable or Not Used

For LRA Table 3.3.1, items 3.3.1-7 through3.3.1-9, 3.3.1-28, 3.3.1-29, and 3.3.1-115, the 

applicant claimed that the corresponding AMR items in the GALL Report are not applicable 

because the associated items are only applicable to PWRs. The staff reviewed the SRP-LR; 

confirmed that these items only apply to PWRs; and finds that these items are not applicable to 

LSCS, which is a BWR.

For LRA Table 3.3.1, items 3.3.1-10, 3.3.1-11, 3.3.1-17 through 3.3.1-18, 3.3.1-23, 3.3.1-24, 

3.3.1-26, 3.3.1-30 through 3.3.1-35, 3.3.1-39, 3.3.1-48, 3.3.1-51, 3.3.1-67, 3.3.1-73 

through 3.3.1-75, 3.3.1-77, 3.3.1-81, 3.3.1-85, 3.3.1-86, 3.3.1-93, 3.3.1-96, 3.3.1-103 

through 3.3.1-105, 3.3.1-107, 3.3.1-108, 3.3.1-109x, 3.3.1-111, 3.3.1-122 through 3.3.1-124, 

3.3.1-128, 3.3.1-129, and 3.3.1-133 through 3.3.1-137, the applicant claimed that the 

corresponding items in the GALL Report are not applicable because the component, material, 

and environment combination described in the SRP-LR does not exist for in-scope SCs at 

LSCS. The staff reviewed the LRA and UFSAR and confirmed that the applicant’s LRA does 

not have any AMR results applicable for these items.

SER Table 3.3-1, items 3.3.1-139 and 3.3.1-140, reflect changes to the SRP-LR incorporated by 

LR-ISG-2013-01, “Aging Management of Loss of Coating or Lining Integrity for Internal 

Coatings/Linings on In-Scope Piping, Piping Components, Heat Exchangers and Tanks.” The 

ISG added these items to manage loss of coating integrity and to allow applicants to credit the 

new GALL Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping 

Components, Heat Exchangers, and Tanks,” to manage loss of material due to general, pitting, 

crevice, and microbiologically-influenced corrosion; fouling that leads to corrosion; or selective 

leaching in certain components. Because the final ISG was issued only shortly before the LRA 

was submitted, the applicant did not cite SRP-LR items 3.3.1-139 and 3.3.1-140 in the LRA. 

The staff finds the applicant’s proposal to not use SRP-LR items 3.3.1-139 and 3.3.1-140 

acceptable because they used other programs to manage loss of material, such as the 

following: (a) loss of material of the galvanized steel fire water system piping and piping 

components is managed by the Fire Water System program, and (b) loss of material for the 

copper greater than 15-percent zinc diesel generator cooler heat exchanger tube sheet is 

managed by the Open-Cycle Cooling Water System and Selective Leaching programs. This 

approach is consistent with GALL Report AMP XI.M42, “Internal Coatings/Linings for In-Scope 

Piping, Piping Components, Heat Exchangers, and Tanks.”

For the LRA Table 3.3.1 items discussed below, the applicant claimed that the corresponding 

AMR items in the GALL Report are not applicable. For these items, the staff reviewed sources 

beyond the LRA and UFSAR or issued one or more RAIs, or both, in order to verify the 

applicant’s claim of non-applicability.

LRA Table 3.3.1, item 3.3.1-13, addresses steel closure bolting exposed to air with steam or 

water leakage. The GALL Report recommends GALL Report AMP XI.M18, “Bolting Integrity,” to 

manage loss of material due to general corrosion for this component group. The applicant 

stated that this item is not applicable because there is no steel closure bolting exposed to air 

with steam or water leakage in the auxiliary systems. The staff evaluated the applicant’s claim 

and notes that the possibility for the steel closure bolts in the auxiliary systems to be exposed to 

an air with steam or water leakage environment during the period of extended operation cannot 

be eliminated. However, the staff finds that the steel closure bolts in the auxiliary systems will 

be adequately age managed for loss of material due to general corrosion and finds the 

non-applicability of LRA item 3.3.1-13 acceptable because of the following:
3-259

• Through LRA Table 3.3.1, items 3.3.1-12 and 3.3.1-78, the applicant will use the Bolting 

Integrity and External Surfaces Monitoring of Mechanical Components programs to 

manage loss of material of all closure bolting in the auxiliary systems.

• Both programs conduct periodic visual inspections, which are capable of detecting loss 

of material due to general corrosion in closure bolting.

• Use of these programs is consistent with the GALL Report.

LRA Table 3.3.1, item 3.3.1-16, addresses stainless steel piping exposed to treated water 

greater than 60 °C (140 °F). The GALL Report recommends GALL Report AMP XI.M2, “Water 

Chemistry,” and AMP XI.M25, “BWR Reactor Water Cleanup System,” to manage cracking due 

to SCC for this component group. The applicant stated that this item is not applicable because 

there is no stainless steel piping greater than or equal to NPS 4-inches exposed to treated water 

greater than 60 °C (140 °F). The staff notes that GALL Report AMP XI.M25 addresses cracking 

as delineated in GL 88-01, “NRC Position on Intergranular Stress Corrosion Cracking (IGSCC) 

in BWR Austenitic Stainless Steel Piping,” dated January 25, 1988, and only applies to stainless 

steel piping greater than or equal to NPS 4-inches. The staff evaluated the applicant’s claim 

and finds it acceptable because piping greater than or equal to NPS 4-inches in the reactor 

water cleanup system was confirmed to be carbon steel.

LRA Table 3.3.1, item 3.3.1-47, addresses stainless steel heat exchanger components exposed 

to closed-cycle cooling water. The GALL Report recommends GALL Report AMP XI.M21A, 

“Closed Treated Water Systems,” to manage loss of material due to microbiologically-influenced 

corrosion for this component group. The applicant stated that this item is not applicable 

because microbiologically-influenced corrosion is not a predicted aging mechanism for loss of 

material in the closed-cycle cooling water environment. The applicant also stated that stainless 

steel heat exchanger components exposed to closed-cycle cooling water are being managed for 

loss of material through item 3.3.1-49. The staff notes that the later AMR item manages loss of 

material due to pitting and crevice corrosion but does not include microbiologically-influenced 

corrosion.

The staff evaluated the applicant’s claim and notes that, although LRA item 3.3.1-47 states that 

microbiologically-influenced corrosion is not a predicted aging mechanism in this environment, 

the operating experience discussion in LRA Section B.2.1.13, “Closed-Cycle Cooling Water 

Systems,” recounts an issue whereby the primary containment chilled water system 

experienced chemistry parameter changes indicative of microbiological growth in the closed 

treated water. The discussion included corrective actions taken by the applicant to address this 

issue. In addition, the staff notes that, during its audit of the applicant’s program, it verified that 

the program elements for the applicant’s program were consistent with the corresponding 

program elements in GALL Report AMP XI.M21A and that the appropriate program elements 

included microbiological testing. Based on the above, the staff discounts the applicant’s 

statement for item 3.3.1-47 related to microbiologically-influenced corrosion not being a 

predicted aging mechanism because the applicant’s Closed Treated Water Systems program 

clearly includes microbiological testing, consistent with GALL Report AMP XI.M21A. In addition, 

as demonstrated by the program’s operating experience discussion, microbiological activity has 

been identified in closed-cycle cooling water environment. Because the program currently 

includes microbiological testing, the use of AMR item 3.3.1-49 is acceptable for managing loss

of material due to pitting and crevice corrosion for stainless steel heat exchanger components 

exposed to closed-cycle cooling water.
3-260

LRA Table 3.3.1, item 3.3.1-68 addresses steel piping, piping components, and piping elements 

exposed to fuel oil. The GALL Report recommends GALL Report AMP XI.M30, “Fuel Oil 

Chemistry,” and AMP XI.M32, “One-Time Inspection,” to manage loss of material due to 

general, pitting, and crevice corrosion. The applicant stated that this item is not applicable 

because loss of material in carbon steel piping, piping components, and piping elements 

exposed to fuel oil is addressed in LRA Table 3.3.1, item 3.3.1-70. The staff evaluated the 

applicant’s claim and finds it acceptable because carbon steel piping, piping components, and 

piping elements exposed to fuel oil is being manage for loss of material using the above 

GALL Report recommendation in LRA Table 3.3.1, item 3.3.1-70.

LRA Table 3.3.1, item 3.3.1-79, addresses copper-alloy piping, piping components, and piping 

elements exposed to condensation (external). The GALL Report recommends GALL Report 

AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” to manage loss of 

material for this component group. The applicant stated that this item is not applicable because 

the component group is addressed in LRA Table 3.3.1, item 3.3.1-89. The applicant stated that 

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program 

will be used to manage loss of material for copper-alloy heat exchanger tubes during heat 

exchanger internal inspections because the copper components are heat exchanger tubes 

located within heating, ventilation, and air conditioning ducting. The staff finds the applicant’s 

proposal to manage loss of material using the Internal Surfaces in Miscellaneous Piping and 

Ducting Components program acceptable because the program includes periodic external 

visual inspections of the tubing capable of detecting loss of material for copper-alloy piping, 

piping components, and piping elements.

LRA Table 3.3.1, item 3.3.1-110, addresses stainless steel piping, piping components, and

piping elements exposed to treated water greater than 60 °C (140 °F). The GALL Report

recommends GALL Report AMP XI.M7, “BWR Stress Corrosion Cracking,” and AMP XI.M2, 

“Water Chemistry,” to manage cracking due to SCC for these components. The applicant 

indicated that this item is not applicable because (1) the BWR Stress Corrosion Cracking

program manages crack initiation and growth in Reactor Coolant Pressure Boundary System

piping, piping components, and piping elements equal to, or greater than, NPS 4-inches and 

(2) a different AMR item (LRA item 3.3.1-19) addresses cracking in stainless steel piping, piping 

components, and piping elements less than NPS 4-inches, which are exposed to treated water 

greater than 140 °F in the auxiliary systems.

In its review, the staff noted that the following reference with its Enclosure 1 indicates that the 

applicant’s BWR Stress Corrosion Cracking program, which is based on GL 88-01, includes 

ASME Code Class 1, 2, and 3 piping made of stainless steel that contains reactor coolant at a 

temperature above 200 °F during power operation.

During its review, the staff noted that applicant’s response to GL 88-01, dated July 29, 1988, 

which provides the basis for the applicant’s BWR Stress Corrosion Cracking program, includes 

piping welds located in the reactor water cleanup system. The staff also noted that LRA 

Section 3.3.1 indicates that the reactor water cleanup system is included in the auxiliary 

systems. However, the staff noted that LRA item 3.3.1-110 and Table 3.3.2-21 (the AMR table 

for the reactor water cleanup system) do not identify the piping welds that are included in the

applicant’s program as described in the reference document above.

By letter dated July 7, 2015, the staff issued RAI 3.3.1.110-1, requesting that the applicant 

clarify why LRA item 3.3.1-110 and Table 3.3.2-21 do not identify the reactor water cleanup

system piping welds that are included in the program as described in the reference document 
3-261

above. The staff also requested that the applicant add relevant AMR items to manage cracking 

due to SCC for these components if these welds are within the scope of the program.

In its response dated August 6, 2015, the applicant stated that the stainless steel portion of the 

plant reactor water cleanup system that is included in the scope of the BWR Stress Corrosion 

Cracking program is the ASME Code Class 1 portion of the system. The applicant also stated 

that this piping is identified as piping design class A949LS on license renewal boundary

drawings LR-LAS-M-97, sheet 1 (LSCS, Unit 1), and LR-LAS-M-143, sheet 1 (LSCS, Unit 2), at 

drawing coordinate B-8. The applicant further stated that, as discussed in LRA Section 2.3.1.1,

“Reactor Coolant Pressure Boundary System,” and LRA Section 2.3.3.21, “Reactor Water 

Cleanup System,” this portion of the LSCS, Units 1 and 2, reactor water cleanup system is 

scoped with the Reactor Coolant Pressure Boundary System. In addition, the applicant 

indicated that the ASME Code Class 1 piping, piping components and piping elements are not

identified in LRA Table 3.3.2-21 for the reactor water cleanup system; instead, they are 

identified in LRA Table 3.1.2-1 as pressure boundary stainless steel piping, piping components,

and piping elements (Table 1, item 3.1.1-97).

In its review, the staff finds the applicant’s response acceptable because the applicant clarified 

that (1) the reactor water cleanup system piping and associated welds identified within the 

scope of the applicant’s program are part of the reactor coolant pressure boundary and (2) the 

applicant’s AMR of SCC for these components is included in AMR item 3.1.1-97 as described in 

LRA Table 3.1.2-1. The staff’s concern described in RAI 3.3.1.110-1 is resolved.

For LRA Table 3.3.1, item 3.3.1-110, the applicant claimed that it is not applicable. The staff 

reviewed the LRA and the applicant’s response to RAI 3.3.1.110-1 as discussed above and 

confirmed that LRA item 3.3.1-110 is not applicable because item 3.1.1-97 addresses cracking 

due to SCC for the stainless steel piping and welds in the reactor coolant pressure boundary.

LRA Table 3.3.1, item 3.3.1-126 addresses any material piping, piping components, and piping 

elements exposed to treated water, treated water (borated), or raw water. The GALL Report

recommends GALL Report AMP XI.M17, “Flow-Accelerated Corrosion,” to manage wall thinning 

due to erosion for this component group. The applicant stated that this item is not applicable 

because there are no piping, piping components, and piping elements exposed to treated water, 

treated water (borated), or raw water susceptible to wall thinning due to erosion in auxiliary 

systems. The staff evaluated the applicant’s claim and finds it acceptable because, during its 

audit, the staff searched the applicant’s operating experience database and did not identify 

components in auxiliary systems that were experiencing wall thinning due to erosion.

Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-25, addresses stainless steel and aluminum exposed to treated 

water (external), which will be managed for loss of material due to pitting and crevice corrosion. 

For the AMR item that cites generic note E, the LRA credits the Water Chemistry and Inspection 

of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems programs to 

manage the aging effect for aluminum crane/hoist in the fuel preparation machine. The 

GALL Report recommends GALL Report AMP XI.M2, “Water Chemistry,” and AMP XI.M32,

“One-Time Inspection,” to ensure that this aging effect is adequately managed. GALL Report

AMP XI.M32 recommends using a visual inspection to manage the effects of aging.

The staff’s evaluation of the applicant’s Water Chemistry and Inspection of Overhead Heavy 

Load and Light Load (Related to Refueling) Handling Systems programs are documented in 
3-262

SER Sections 3.0.3.2.1 and 3.0.3.2.7, respectively. The staff noted that GALL Report

AMP XI.M23, “Inspection of Overhead Heavy Load and Light Load (Related to Refueling) 

Handling Systems,” recommends that the surface condition of cranes’ structural components be 

monitored by visual inspection to ensure that loss of material is not occurring. GALL Report

AMP XI.M23 also recommends that the visual inspections be performed at a frequency in 

accordance with ASME Code B30.2, “Overhead and Gantry Cranes (Top Running Bridge, 

Single or Multiple Girder, Top Running Trolley Hoist),” and with other appropriate standards in 

the ASME Code B30 series, or once every refueling cycle just before use for systems that are 

infrequently in service. The staff noted that the applicant’s Inspection of Overhead Heavy Load 

and Light Load (Related to Refueling) Handling Systems program proposes to manage the 

effects of aging of loss of material for the aluminum crane and/or hoist through the use of 

periodic visual inspections. These periodic inspections are performed consistent with the 

appropriate ASME Code B30 series standard for all cranes, hoists, and handling equipment 

systems within the scope of license renewal. For the crane and hoist in the fuel preparation 

machine, periodic inspections are performed at least just before use during refueling outages. 

Based on its review of components associated with LRA Table 3.3.1, item 3.3.1-25, for which 

the applicant cited generic note E, the staff finds the applicant’s proposal to manage the effects 

of aging using the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) 

Handling Systems program acceptable because (1) the applicant will perform periodic visual 

inspections at least just before use during refueling outages to detect loss of material on cranes 

and or hoists and (2) the Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems program is the GALL Report-recommended AMP to manage the 

aging effects of cranes and hoists structural components.

The staff concludes that, for LRA item 3.3.1-25, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

Loss of Material Due to Pitting, Crevice Corrosion, and Fouling that Leads to 

Corrosion

During its review of components associated with LRA Table 3.3.1, item 3.3.1-40, for which the 

applicant cited generic note A, the staff noted that the LRA credits the Open-Cycle Cooling 

Water System program to manage loss of material for the stainless steel “fish barrier.” The staff 

evaluated the components associated with this item during its AMP audit because fish barrier 

components were atypical for piping and piping components normally associated with this item. 

As documented in its Audit Report, the staff reviewed the System and Structure Screening 

Report for the Essential Cooling Water System and noted that the component type “fish barrier”

includes the stainless steel buoy cylinders, cable, and wire cloth. The accompanying comment 

states that a shad net is installed in the lake screen house flume and that the polymeric portions 

of the shad net (netting, twine, and ty-wraps) are periodically replaced making them short lived 

and not subject to an AMR. Based on the discussion provided in the screening report for the 

associated components, the staff finds that periodic visual inspections performed by the 

Open-Cycle Cooling Water System program can adequately manage loss of material for the 

stainless steel components associated with the fish barrier.

The staff concludes that for LRA item 3.3.1-40, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).
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Loss of Material Due to Pitting, Crevice Corrosion, and Microbiologically-Influenced 

Corrosion

LRA Table 3.3.1, item 3.3.1-41, addresses stainless steel piping and piping components 

exposed to raw water, which will be managed for loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion. For the AMR item that cites generic note E, the LRA 

credits the RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power 

Plants,” program to manage the aging effect for the stainless steel concrete anchors in the Lake 

Screen House. The GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle 

Cooling Water System,” program to ensure that this aging effect is adequately managed for loss 

of material due to corrosion and recommends using periodic visual inspections to manage the 

effects of aging.

The staff’s evaluation of the applicant’s RG 1.127, “Inspection of Water-Control Structures 

Associated with Nuclear Power Plants,” program is documented in SER Section 3.0.3.2.20. The 

staff notes that the applicant’s RG 1.127, “Inspection of Water-Control Structures Associated 

with Nuclear Power Plants,” program proposes to manage the effects of aging for stainless steel 

concrete anchors through the use of periodic visual inspections. Based on its review of 

components associated with item 3.3.1-41 for which the applicant cited generic note E, the staff 

finds the applicant’s proposal to manage the effects of aging using its RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants program acceptable because 

the proposed program manages other structural bolting components using periodic visual 

inspections and because these inspections are sufficient to detect loss of material before loss of 

function.

The staff concludes that, for LRA item 3.3.1-41, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion; Fouling that Leads to Corrosion; and Flow Blockage Due to Fouling

LRA Table 3.3.1, item 3.3.1-64, addresses steel and copper-alloy piping, piping components, 

and piping elements exposed to raw water, which will be managed for loss of material due to 

general, pitting, crevice, and microbiologically-influenced corrosion; fouling that leads to 

corrosion; and flow blockage due to fouling. For the AMR items that cite generic note E, the 

applicant stated that “[t]he Bolting Integrity (LRA Section B.2.1.11) program has been 

substituted and will be used to manage loss of material of carbon and low alloy steel bolting 

exposed to raw water in the Nonessential Cooling Water System and Fire Protection System.” 

The staff noted that GALL Report AMP XI.M27 does not specifically address loss of material for 

bolting.

The staff’s evaluation of the applicant’s Bolting Integrity program is documented in SER 

Section 3.0.3.2.4. The staff noted that the Bolting Integrity program proposes to manage the 

effects of aging for carbon and low alloy steel bolting through the use of periodic inspections for 

indication of loss of preload, cracking, and loss of material due to corrosion. However, the 

applicant did not state the parameters, sample size, or frequency of inspections to be performed 

on submerged bolting for item 3.3.1-64, which addresses the diesel fire pump suction screens. 

By letter dated July 7, 2015, the staff issued RAI 3.2.2.1.1-1, requesting that the applicant 

(a) state and justify the parameters for inspections and state whether a representative sample 
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will be removed and inspected and (b) justify the inspection frequency for submerged bolting, 

other than those associated with the lake screen house traveling screen framework for which 

they specified a frequency of once per refuel interval, which is consistent with GALL Report 

AMP XI.M18.

In its response to Part (a) of RAI 3.2.2.1.1-1, dated August 6, 2015, the applicant stated that the 

bolting on the ECCS and RCIC suction strainers, service water diver safety barriers, diesel fire 

pump suction screens, and the lake screen house traveling screens framework is submerged 

non-pressure-retaining bolting. The applicant also stated that the existing plant-specific 

inspection procedures would be enhanced so that 100 percent of the accessible surfaces of 

these submerged bolts will require inspection of the bolt heads, nuts, and threaded bolt shank 

beyond the nut by divers during each inspection. The applicant also stated that the 

plant-specific procedures would be further enhanced to require manipulation of the nuts to 

ensure that they are not loose. The applicant further stated that the geometry of the ECCS and 

RCIC strainer bolting is such that portions of the threaded shank beyond the nuts are visible; 

therefore, loss of material can be detected without the need to remove the nuts for inspection.

The applicant stated that, because of tight clearances, the bolt heads on the outside of traveling 

screens are not accessible; however, because these bolts and associated nuts are accessible 

on the inside of the framework and are exposed to the same environment, the inspections

performed on the portions of the bolts and nuts inside the framework would be indicative of the

condition of the inaccessible portions of the bolting.

The staff noted that the submerged bolting for LRA item 3.3.1-64 does not have a pressure 

boundary function; therefore, it is appropriate that certain aspects of GALL Report AMP XI.M18 

would not be applicable to these bolts (i.e., testing for leakage). In its review, the staff also 

noted that GALL Report AMP XI.S6 recommends that structural bolting be monitored for loose 

bolts, missing or loose nuts, and other conditions indicative of loss of preload.

The staff finds the applicant’s response acceptable because the applicant enhanced its Bolting 

Integrity program to perform inspections on 100 percent of the accessible surfaces of the 

submerged bolting during each inspection. Performing these inspections provides reasonable 

assurance of the condition of the inaccessible bolting because, in all instances, the accessible 

and inaccessible bolting addressed by LRA item 3.3.1-64 would be exposed to the same 

environment. The staff’s concerns described in Part (a) of RAI 3.2.2.1.1-1 are resolved.

In its response to Part (b) of the RAI, the applicant stated that the program will be enhanced to 

require that all ECCS and RCIC suction strainer submerged bolting is inspected during each 

10-year ISI interval. The applicant also stated that the program would be enhanced to perform 

the inspections of the service water diver safety barriers and diesel fire pump suction screen 

bolting during every refueling outage, consistent with the recommendations of GALL Report 

AMP XI.M18. The staff finds the applicant’s response acceptable because (a) inspection of all 

of the bolting for the ECCS and RCIC suction strainers every 10-year ISI interval would ensure 

that a representative sample of these bolts is examined during each ISI period and (b) the 

bolting for the service water diver safety and diesel fire pump suction screens will be inspected 

during every outage, consistent with the recommendations of GALL Report AMP XI.M18. The 

staff’s concerns described in Part (b) of RAI 3.2.2.1.1-1 are resolved.

The staff concludes that, for LRA item 3.3.1-64, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 
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be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

Loss of Material Due to Pitting and Crevice Corrosion; Fouling that Leads to 

Corrosion; and Flow Blockage Due to Fouling

LRA Table 3.3.1, item 3.3.1-65, addresses aluminum piping, piping components, and piping 

elements exposed to raw water, which will be managed for loss of material due to pitting and 

crevice corrosion; fouling that leads to corrosion; and flow blockage due to fouling. For the AMR 

items that cite generic note E, the LRA credits the Open-Cycle Cooling Water System program 

to manage the aging effects for aluminum piping, piping components, and piping elements. The 

GALL Report recommends GALL Report AMP XI.M27, “Fire Water System,” to ensure that this 

aging effect is adequately managed. GALL Report AMP XI.M27 recommends using flow 

testing, other testing, and visual inspections to manage the effects of aging.

The staff’s evaluation of the applicant’s Open-Cycle Cooling Water System program is 

documented in SER Section 3.0.3.2.5. The staff noted that the Open-Cycle Cooling Water 

System program proposes to manage the effects of aging for aluminum piping, piping 

components, and piping elements through the use of visual inspections or nondestructive 

examinations. Based on its review of components associated with item 3.3.1-65, all of which 

are located in the Nonessential Cooling Water System, for which the applicant cited generic 

note E, the staff finds the applicant’s proposal to manage the effects of aging using the 

Open-Cycle Cooling Water System program acceptable because it will perform inspections 

comparable to the Fire Water System program, which are capable of detecting loss of material 

due to pitting and crevice corrosion, fouling that leads to corrosion, and flow blockage due to 

fouling before a loss of intended function.

The staff concludes that, for LRA item 3.3.1-65, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

Loss of Material Due to General Corrosion

LRA Table 3.3.1, item 3.3.1-78 addresses external surfaces of steel piping and components, 

ducting and components, ducting, and closure bolting exposed to uncontrolled air-indoor, 

air-outdoor, and condensation, which will be managed for loss of material due to general 

corrosion. The LRA credits the External Surfaces Monitoring of Mechanical Components 

program to manage the aging effect for external surfaces for steel piping and components, 

ducting and components, ducting, and closure bolting exposed to uncontrolled indoor air, 

outdoor air, and condensation. However, for the AMR items that cite generic note E in LRA 

Table 3.3.2-12 and plant-specific note 2, the LRA credits the Fire Protection program as a 

substitute to the “External Surfaces Monitoring of Mechanical Components” to manage the 

aging effect(s) for carbon steel and galvanized steel fire barriers (doors). The GALL Report

recommends GALL Report AMP XI.M36, “External Surfaces Monitoring of Mechanical 

Components,” to ensure that this aging effect is adequately managed. GALL Report

AMP XI.M36 recommends using periodic visual inspections and walkdowns to manage the 

effects of aging of the external surfaces of metallic components.

The staff’s evaluations of the applicant’s External Surfaces Monitoring of Mechanical 

Components and Fire Protection programs are documented in SER Sections 3.0.3.1.12 
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and 3.0.3.2.9, respectively. The staff noted that the External Surfaces Monitoring of Mechanical 

Components program proposes to manage the effects of aging for metallic and elastomeric 

components (e.g., piping components and ducting) within the scope of license renewal through 

the use of visual inspections of external surfaces for evidence of loss of material, cracking, and

changes in material properties. The External Surfaces Monitoring of Mechanical Components 

program states that the inspections to detect corrosion under insulation will be conducted during 

each 10-year period of the period of extended operation. Inspections, with the exception of 

inspections performed to detect corrosion under insulation, are performed at a frequency not to 

exceed one refueling cycle. The staff further noted that the Fire Protection program manages 

the aging effects, such as loss of material, on fire doors through visual inspections and 

functional testing at least once every refueling cycle (24 months). Based on its review of 

components associated with item 3.3.1-78 for which the applicant cited generic note E, 

plant-specific note 2, the staff finds the applicant’s proposal to manage the effects of aging 

using the Fire Protection program acceptable because the applicant’s program is consistent, 

with enhancements, with GALL Report AMP XI.M26, which recommends visual inspections of 

fire-rated doors to detect any degradation of door surfaces, and because the inspections will be 

conducted at the same frequency under the Fire Protection program (once every 2 years) 

compared to the inspection frequency under the External Surfaces Monitoring of Mechanical 

Components program.

The staff concludes that, for LRA Item 3.3.1-78, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

Loss of Material Due to General, Pitting, Crevice and (for Drip Pans and Drain 

Lines) Microbiologically-Influenced Corrosion

LRA Table 3.3.1, item 3.3.1-90 addresses the internal surfaces of steel ducting and components

exposed to condensation, which will be managed for loss of material due to general, pitting, 

crevice, and (for drip pans and drain lines) microbiologically-influences corrosion. The LRA 

credits the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

program to manage the aging effect for internal surfaces of steel ducting and components 

exposed to condensation. However, for the AMR items that cite generic note E and 

plant-specific note 10 in LRA Table 3.3.2-12, the LRA credits the Fire Protection program as a 

supplement to the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program to manage the aging effect(s) for galvanized steel fire barriers (damper 

housing) when exposed to condensation. The GALL Report recommends GALL Report

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,” to ensure that this aging effect is adequately managed. GALL Report

AMP XI.M38 recommends using periodic visual inspections to ensure that existing 

environmental conditions are not causing material degradation that could result in a loss of 

component intended functions.

The staff’s evaluations of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components and Fire Protection programs are documented in SER 

Sections 3.0.3.1.13 and 3.0.3.2.9, respectively. The staff noted that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components program proposes to manage the 

effects of aging for metallic components (e.g., piping components and piping elements) within 

the scope of license renewal through the use of visual inspections of internal surfaces when 

they are made accessible during periodic system surveillances or during the performance of 
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maintenance activities. The applicant stated that the inspections will be conducted, at a 

minimum, in each 10-year period of the period of extended operation with a representative 

sample of 20 percent of the population. The staff further noted that the Fire Protection program 

manages the aging effects, such as loss of material, of fire barriers, such as fire dampers, 

through visual inspections and functional testing at least once every refueling cycle (24 months). 

Based on its review of components associated with item 3.3.1-90 for which the applicant cited 

generic note E, the staff finds the applicant’s proposal to manage the effects of aging using the 

Fire Protection program as a supplement to the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components program acceptable because the applicant’s program is 

consistent, with enhancements, with GALL Report AMP XI.M26, which recommends periodic 

visual inspections of fire barriers, such as fire dampers, and because the inspections will be 

conducted at a greater frequency under the Fire Protection program (once every 2 years) 

compared to the inspection frequency (once every 10 years) under the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components program.

The staff concludes that, for LRA Item 3.3.1-90, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

No Recommended Aging Effect

LRA Table 3.3.1, item 3.3.1-112 (GALL Report AMR item AP-282), addresses steel piping, 

piping components, and piping elements exposed to concrete, which have no AERMs and no 

recommended AMP as long as “(1) attributes of the concrete are consistent with ACI 318 or 

ACI 349 (low water-to-cement ratio, low permeability, and adequate air entrainment) as cited in 

NUREG-1557, and (2) plant operating experience indicates no degradation of the concrete.” 

The GALL Report recommends that there are no AERMs as long as the above conditions are 

met.

During its review of components associated with item 3.3.1-112 for which the applicant cited 

generic notes A and C, the staff identified the need for an RAI. In LR-ISG-2011-03, “Changes to 

the Generic Aging Lessons Learned (GALL) Report Revision 2 Aging Management Program 

(AMP) XI.M41, ‘Buried and Underground Piping and Tanks,’” GALL Report AMP XI.M41 states 

that “buried piping and tanks are in direct contact with soil or concrete.” Buried components are 

within the scope of GALL Report AMP XI.M41. GALL Report AMR items EP-111 and SP-145 

state that loss of material is managed for piping and piping components exposed to soil or 

concrete by GALL Report AMP XI.M41. The staff acknowledges that there is an internal conflict 

in the GALL Report between GALL Report AMR item AP-282 and AMP XI.M41 and 

items EP-111 and SP-145. The staff has concluded that when components are exposed to 

concrete, if the encased components are not potentially externally exposed to water, there are 

no AERMs and no recommended AMP. However, the staff lacks sufficient information to 

conclude that the piping and piping components cited in LRA Tables 3.3.2-11 and 3.3.2-14 are 

not potentially exposed to water. By letter dated May 29, 2015, the staff issued 

RAI 3.3.2.1.11-1, requesting that the applicant state whether the carbon steel piping and piping 

components exposed to concrete cited in LRA Tables 3.3.2-11 and 3.3.2-14 are potentially 

exposed to water (e.g., groundwater).

In its response dated June 25, 2015, the applicant stated that the Essential Cooling Water, 

Nonessential Cooling Water, Reactor Core Isolation Cooling, Diesel Generator and Auxiliaries, 

Fire Protection, and Condensate Systems all include piping embedded in concrete that is 
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located below the nominal groundwater table. The applicant revised LRA Tables 3.2.2-3, 

3.3.2-8, 3.3.2-11, 3.3.2-12, 3.3.2-14, and 3.4.2-1 to state that loss of material will be managed 

for steel piping exposed to concrete by the Buried and Underground Piping program. The new 

AMR items cite generic note A.

The staff finds the applicant’s response acceptable because the Buried and Underground Piping 

program includes periodic inspections and tests that are capable of detecting loss of material. 

The staff’s concern described in RAI 3.3.2.1.11-1 is resolved.

The staff concludes that, for LRA item 3.3.1-112, the applicant has demonstrated that the 

effects of aging for these components will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

LRA Table 3.3.1, item 3.3.1-119, addresses polyvinyl chloride (PVC) piping, piping components, 

and piping elements exposed to air-indoor uncontrolled for which there are no AERMs. The 

GALL Report recommends that there are no AERMs and no recommended AMP.

During its review of polymeric hoses associated with item 3.3.1-119 for which the applicant cited 

generic note A, the staff noted that the LRA states that there are no AERMs and no AMP. The 

applicant cited plant-specific note 1, which states that “[s]ome system drains include polymer 

hoses (Tygon® tubing). Tygon® tubing has no aging effects in a Waste Water environment. 

Tygon® is a registered trademark of Norton Performance Plastics that represents a family of 

various thermoplastic polymers. Tygon® is a PVC-based material that is clear or transparent 

and normally used for flexible tubing. It is considered non-aging and non-oxidizing, and has 

broad chemical resistance.” Based on a review of the information at 

http://www.tubes-international.com/tygon_tubing.html (accessed on April 1, 2015), the staff 

confirmed that Tygon® tubing can be constructed of PVC materials. Based on its review of 

polymeric hoses associated with item 3.3.1-119 for which the applicant cited generic note A, the

staff finds the applicant’s proposal acceptable because GALL Report item SP-152 states that 

PVC piping, piping components, and piping elements have no AERMs and no proposed AMP.

The staff concludes that, for LRA item 3.3.1-119, the applicant has demonstrated that the 

effects of aging for these components will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

LRA Table 3.3.1, item 3.3.1-120 addresses, in part, stainless steel piping, piping components, 

and piping elements exposed to concrete. AMR item 120 in SRP-LR Table 3.3-1 recommends 

that there is no aging effect or aging mechanism and that no AMP is recommended for this 

component group exposed to this environment.

During its review of structural stainless steel components that were identified in LRA 

Tables 3.5.2-1, 3.5.2-4, 3.5.2-5, 3.5.2-7, 3.5.2-8, 3.5.2-9, and 3.5.2-13 associated with LRA 

item 3.3.1-120 (for which the applicant cited generic note C), the staff noted that the applicant 

did not identify any AERMs for the exposure of the stainless steel components to a concrete 

environment. Specifically, the applicant identified that the following stainless steel components 

exposed to concrete do not have any AERMS and do not require aging management under 

10 CFR 54.21(a)(3): (a) liners, liner anchors, and integral attachments, (b) anchor bolting, 

(c) hatches and plugs, (d) stainless steel concrete anchors, (e) electrical and mechanical 

penetration sleeves and assemblies, and (f) downcomers.
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The staff performed a review of the applicant’s basis to determine whether the applicant had 

omitted any AERMs for the exposure of these stainless steel components to a concrete 

environment. The staff noted that, although GALL Report AMR item VII.J. AP-19 identifies that 

there are not any AERMs for stainless steel piping and piping components exposed to concrete, 

other AMR items in the GALL Report identify that stainless steel components exposed to 

concrete may be susceptible to loss of material effects as a result of pitting or crevice corrosion 

aging mechanisms, including (a) AP-137 and SP-94 for stainless steel piping and piping 

components exposed to concrete, (b) SP-137 for stainless steel tanks exposed to concrete, and 

(c) AP-243 and SP-143 for stainless steel bolting exposed to concrete. Therefore, the staff 

determined that it did not have sufficient information to conclude that loss of material due to 

pitting and crevice corrosion would not need to be identified as an AERM for the exposure of 

these types of stainless steel components to a concrete environment. An analogous RAI on the 

topic of AERMs for steel components exposed to concrete is given in RAI 3.3.2.1.1-11, which 

was issued to Exelon in a letter dated May 29, 2015.

By letter dated August 28, 2015, the staff issued RAI 3.5.2.1-1, requesting that the applicant 

address these issues. The staff asked the applicant to provide its basis for why loss of material 

due to pitting and crevice corrosion has not been identified as an AERM for those structural 

liners, liner anchors, anchor bolting, electrical and mechanical penetration sleeves, and 

assemblies or hatches or plugs that are made from stainless steel materials and are exposed to 

a concrete environment. If loss of material due to pitting and crevice corrosion is an applicable 

AERM for the exposure of these components to concrete, the staff asked the applicant to 

identify and justify the AMP or programs that will be used to manage this aging effect during the 

period of extended operation.

The applicant responded to RAI 3.5.2.1-1 in a letter dated September 28, 2015. The applicant 

explained that there are 23 AMR items in LRA Tables 3.5.2-1, 3.5.2-4, 3.5.2-5, 3.5.2-7, 3.5.2-8, 

3.5.2-9, and 3.5.2-13 for stainless steel components that are exposed to a “concrete” 

environment. The applicant stated that 14 of these AMR items apply to electrical penetration 

assemblies, mechanical penetrations, penetration sleeves, downcomers, and the suppression 

chamber liner that are located in the Primary Containment building or reactor building. The

applicant stated that five of these AMR items apply to liners, liner anchors, and integral 

attachments located in the sumps of the Auxiliary Building, Diesel Generator Building, Radwaste 

Building, Reactor Building, and Turbine Building. The applicant stated that three of these AMR 

items are for hatches/plugs, the fuel pool line and casks loading pit liner, and reactor weld dryer 

and separator pool in the reactor building. The applicant stated that the last of these AMR items 

applies to the stainless steel anchor bolting in the Lake Screen House.

The applicant stated that these stainless steel components are located in areas of concrete 

building structures that separate them from direct contact with soil and or exposure to potential 

in-seepage of groundwater. The applicant also stated that no portions of these components are 

located in areas that are exposed to soil, are buried or underground, or are part of the underside 

of an aboveground metallic tank. Therefore, the applicant stated that the AMR items for these 

components are consistent with GALL AMR Item VII.J.AP-19, which recommends “none” as the 

aging effect for stainless steel components that are exposed to concrete inside of concrete 

buildings where the components are not buried or underground, exposed to soil, or part of 

inaccessible aboveground tank bottoms. The applicant stated that, because loss of material 

due to pitting and crevice corrosion is not an applicable AERM for these AMR items, there is no 

AMP needed to manage these components during the period of extended operation.
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The staff noted that the applicant’s explanation clarifies which stainless steel components are 

exposed to concrete and have AMR items aligned to AMR item 120 in SRP-LR Table 3.3-1 and 

to GALL AMR item VII.J.AP-19. The staff also noted that the applicant’s response explains that 

the components in question are exposed to concrete in locations that are far from soil and would 

not be exposed to water seepage into the concrete materials. Therefore, the staff finds that the 

applicant has provided an acceptable basis for concluding that loss of material due to pitting or 

crevice corrosion is not an applicable AERM for these components because the components 

are located in concrete locations remote from any soil moisture or sources of water that could 

seep into the concrete materials. Based on this review, the staff finds that the applicant has 

provided an adequate basis for concluding that there are no AERMs for these stainless steel 

components because (a) the applicant has demonstrated that these AMR items for stainless 

steel components in concrete are consistent with GALL AMR item VII.J.AP-19 and (b) GALL 

Report AMR item VII.J.AP-19 does not identify any AERMs for stainless steel components that 

are exposed to concrete where there is no expectation of exposure to moisture or water 

seepage in the concrete. RAI 3.5.2.1-1, Parts 1 and 2, are resolved.

The staff concludes that for LRA item 3.3.1-120, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation Is 

Recommended

In LRA Section 3.3.2.2, the applicant further evaluated aging management, as recommended by 

the GALL Report, for the auxiliary system components and provided information concerning 

how it will manage the following aging effects:

• cumulative fatigue damage

• cracking due to SCC and cyclic loading

• cracking due to SCC

• loss of material due to cladding breach

• loss of material due to pitting and crevice corrosion

• QA for aging management of nonsafety-related components

• ongoing review of operating experience

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 

the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.3.2.2. The staff’s review of the applicant’s 

further evaluation follows.

Cumulative Fatigue Damage

LRA Section 3.3.2.2.1, associated with LRA Table 3.3.1, items 3.3.1-1 and 3.3.1-2, addresses 

cumulative fatigue damage management for the Feedwater; High Pressure Core Spray; Reactor 

Coolant Pressure Boundary; Reactor Core Isolation Cooling; Reactor Water Cleanup; and 

Cranes, Hoists, and Refueling Equipment systems. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that fatigue is a TLAA, as defined in 10 CFR 54.3,

“Definitions,” and is required to be evaluated in accordance with 10 CFR 54.21(c). The 
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applicant stated that its evaluation of the crane load cycles as a TLAA for the Cranes, Hoists, 

and Refueling Equipment system is addressed in LRA Section 4.7. The applicant stated that its 

evaluation of the TLAA for the remaining systems is addressed in LRA Section 4.3.

The staff reviewed LRA Section 3.3.2.2.1 against the criteria in SRP-LR Section 3.3.2.2.1, which 

state that cumulative fatigue damage of auxiliary systems is a TLAA and that these TLAAs are 

to be evaluated in accordance with the TLAA acceptance criteria requirements of 

10 CFR 54.21(c). The staff reviewed the applicant’s AMR items and determined that the AMR 

results are consistent with the recommendations of the GALL Report and SRP-LR for managing 

cumulative fatigue damage.

LRA Section 3.3.2.2.1 states that TLAAs are evaluated in accordance with 10 CFR 54.21(c) and 

that the evaluation of these TLAAs are addressed in LRA Sections 4.3 and 4.7. This is 

consistent with SRP-LR Section 3.3.2.2.1 and, therefore, is acceptable. The staff’s evaluation 

of the TLAA for the Feedwater, High Pressure Core Spray, Reactor Coolant Pressure Boundary,

Reactor Core Isolation Cooling, and Reactor Water Cleanup systems being managed for 

cumulative fatigue damage is documented in SER Section 4.3. The staff’s evaluation of the 

TLAA for the Cranes, Hoists, and Refueling Equipment system being managed for cumulative 

fatigue damage is documented in SER Section 4.7.

Cracking Due to Stress Corrosion Cracking and Cyclic Loading

LRA Section 3.3.2.2.2, associated with LRA Table 3.3.1, item 3.3.1-3, addresses cracking in the 

stainless steel non-regenerative heat exchanger exposed to treated water above 140 oF. 

SRP-LR Section 3.3.2.2.2 and Table 3.3.1 identify item 3.3.1-3 as being applicable to PWRs 

only. The applicant stated that this item is not applicable because it only applies to PWRs. The 

staff evaluated the applicant’s claim and finds it acceptable because the applicant’s facility is not 

a PWR.

Cracking Due to Stress Corrosion Cracking

LRA Section 3.3.2.2.3, associated with LRA Table 3.3.1, item 3.3.1-4, addresses cracking due 

to SCC in stainless steel piping, piping components, piping elements, and tanks exposed to 

outdoor air. The criteria in SRP-LR Section 3.2.2.2.3 state that cracking could occur for 

stainless steel components exposed to outdoor air environments containing sufficient halides 

and environments in which condensation or deliquescence is possible. The SRP-LR further 

states that GALL Report AMP XI.M36, “External Surfaces Monitoring of Mechanical 

Components,” is an acceptable method to manage the aging effect. The applicant addressed 

the further evaluation criteria of the SRP-LR and stated that this item is applicable to its units 

and within the scope of license renewal. The applicant also stated that it will implement the 

External Surfaces Monitoring of Mechanical Components program to manage cracking due to 

SCC in stainless steel piping, piping components, and piping elements exposed to outdoor air in 

the Diesel Generator and Auxiliaries System.

The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical

Components program is documented in SER Section 3.0.3.1.12. The staff noted that the 

applicant’s External Surfaces Monitoring of Mechanical Components program, when 

implemented, includes periodic representative inspections of components in which

condensation could occur; therefore, the program will be capable of managing the aging effect. 

In its review of the components associated with item 3.3.1-4, the staff finds that the applicant 

has met the further evaluation criteria and that the applicant’s proposal to manage the effects of 
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aging using the External Surfaces Monitoring of Mechanical Components program is acceptable 

because the applicant’s program implements periodic inspections, which can detect cracking 

due to SCC.

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.3.2.2.3 criteria.

For those items associated with LRA Section 3.3.2.2.3, the staff concludes that the LRA is 

consistent with the GALL Report and that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Loss of Material Due to Cladding Breach

LRA Section 3.3.2.2.4, associated with LRA Table 3.3.1, item 3.3.1-5, addresses loss of 

material due to cladding breach in PWR steel charging pump casings with stainless steel 

cladding exposed to treated borated water. The applicant stated that this item is not applicable 

because it only applies to PWRs. The staff confirmed that this item is associated only with PWR 

plants and that the applicant’s reactor type is BWR; therefore, the staff finds the applicant’s 

determination acceptable.

Loss of Material Due to Pitting and Crevice Corrosion

LRA Section 3.3.2.2.5, associated with LRA Table 3.3.1 item 3.3.1-6, addresses loss of material 

due to pitting and crevice corrosion in stainless steel piping, piping components, piping 

elements, and tanks exposed to outdoor air. The criteria in SRP-LR Section 3.3.2.2.5 state that 

loss of material could occur for stainless steel components exposed to outdoor air environments 

containing sufficient halides and environments in which condensation or deliquescence is 

possible. The SRP-LR further states that GALL Report AMP XI.M36, “External Surfaces 

Monitoring of Mechanical Components,” is an acceptable method to manage the aging effect. 

The applicant addressed the further evaluation criteria of the SRP-LR and stated that this item is 

applicable to its units and within the scope of license renewal. The applicant also stated that it 

will implement the External Surfaces Monitoring of Mechanical Components program to manage 

loss of material due to pitting and crevice corrosion in stainless steel piping, piping components, 

and piping elements exposed to outdoor air in the Diesel Generator and Auxiliaries System.

The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical

Components program is documented in SER Section 3.0.3.1.12. The staff noted that the 

applicant’s External Surfaces Monitoring of Mechanical Components program, when 

implemented, includes periodic representative inspections of components in which

condensation could occur; therefore, the program will be capable of managing the aging effect. 

In its review of the components associated with item 3.3.1-6, the staff finds that the applicant 

has met the further evaluation criteria and the applicant’s proposal to manage the effects of 

aging using the External Surfaces Monitoring of Mechanical Components program is acceptable 

because the applicant’s program implements periodic inspections, which can detect loss of 

material due to pitting and crevice corrosion.

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.3.2.2.5 criteria. For those items associated with LRA Section 3.3.2.2.5, the 

staff concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 
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function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program.

Ongoing Review of Operating Experience

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience of AMPs.

Loss of Material Due to Recurring Internal Corrosion

LRA Section 3.3.2.2.8, associated with LRA Table 3.3.1, item 3.3.1-127, addresses recurring 

internal corrosion in metallic piping, piping components, and tanks exposed to raw or waste 

water, which will be managed for loss of material by the Open-Cycle Cooling Water System, 

Fire Water System, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components programs. The criteria in SRP-LR Section 3.3.2.2.8 state that AMPs may need to 

be augmented beyond the recommendations in the GALL Report if recurring internal corrosion 

is identified during searches of plant-specific operating experience. The applicant addressed 

the further evaluation criteria of the SRP-LR by stating that LSCS will implement the following 

inspections:

• Inspections will be conducted at a minimum of 10 locations in both the essential cooling 

water system and non-essential cooling water system every 24 months until the 

frequency of occurrence for microbiologically-influenced corrosion no longer meets the 

criteria for recurring internal corrosion. These inspections will be conducted as part of 

the Open-Cycle Cooling Water program and will supplement the existing inspections that 

are being performed as part of the commitments to GL 89-13.

• Inspections will be conducted at five locations every year in the aboveground fire 

protection system piping that is susceptible to microbiologically-influenced corrosion. 

These inspection locations will be selected with process conditions similar to those in 

buried portions of the piping to provide sufficient understanding of the buried piping 

condition. In addition, these inspections will be conducted as part of the Fire Water 

System program and will continue until the frequency of occurrence for 

microbiologically-influenced corrosion no longer meets the criteria for recurring internal 

corrosion.

• Inspections will be conducted at 10 different locations in the plant drainage system 

during each 10-year period and will continue until the frequency of occurrences no 

longer meets the criteria for recurring internal corrosion. These inspections will be 

conducted as part of the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components program.

• For the above inspections, the selected inspection locations will be periodically reviewed 

to validate their relevance and will be adjusted as appropriate. The evaluation of 

inspection results will include a comparison to the nominal wall thickness or previous 

wall thickness measurement to determine the rate of corrosion degradation, a 

comparison of the design minimum allowable wall thickness to determine the 

acceptability of the component for continued use, and a determination of the 

re-inspection interval. If these examinations identify significant degradation, additional 
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locations will be examined in accordance with the component’s classification (i.e., ASME 

Code Section III or non-ASME Code Section III piping) and the degree of degradation. 

Deficiencies will be documented in accordance with the 10 CFR Part 50, Appendix B, 

corrective action program.

The staff’s evaluations of the applicant’s Open-Cycle Cooling Water System, Fire Water 

System, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

programs are documented in SER Sections 3.0.3.2.5, 3.0.3.2.10, and 3.0.3.1.13, respectively.

In its review of the components associated with item 3.3.1-127, the staff finds that the applicant 

has met the further evaluation criteria and that the applicant’s proposal to manage the effects of 

aging using the programs is acceptable because the applicant has augmented the three 

programs beyond the recommendations in the GALL Report for the corresponding AMPs with 

additional inspections and sample expansion criteria.

Based on the programs identified, the staff determines that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.8 criteria. For those items associated with LRA Section 3.3.2.2.8, the 

staff concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

For LRA Tables 3.3.2-1 through 3.3.2-25, the staff reviewed additional details of the AMR 

results for material, environment, AERM, and AMP combinations that are not consistent with or 

are not addressed in the GALL Report.

In LRA Tables 3.3.2-1 through 3.3.2-25, the applicant indicated, by notes F through J, that the 

combination of component type, material, environment, and AERM does not correspond to an

item in the GALL Report. The applicant provided further information about how it will manage 

the aging effects. Specifically, note F indicates that the material for the AMR item component is 

not evaluated in the GALL Report. Note G indicates that the environment for the AMR item

component and material is not evaluated in the GALL Report. Note H indicates that the aging 

effect for the AMR item component, material, and environment combination is not evaluated in 

the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the 

item component, material, and environment combination is not applicable. Note J indicates that 

neither the component nor the material and environment combination for the item is evaluated in 

the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. 

The staff’s evaluation is documented in the following sections.

Closed-Cycle Cooling Water System – Summary of Aging Management Review –

LRA Table 3.3.2-1

The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations for the 

Closed-Cycle Cooling Water System component groups. The staff’s review did not identify any
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AMR items with notes F through J, indicating that the combinations of component type, material,

environment, and AERM for the Closed-Cycle Cooling Water System component groups are 

consistent with the GALL Report.

Combustible Gas Control System – Summary of Aging Management Review –

LRA Table 3.3.2-2

The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for the 

Combustible Gas Control System component groups. The staff’s review did not identify any 

AMR items with notes F through J, indicating that the combinations of component type, material,

environment, and AERM for the Combustible Gas Control System component groups are 

consistent with the GALL Report.

Compressed Air System – Summary of Aging Management Review –

LRA Table 3.3.2-3

The staff reviewed LRA Table 3.3.2–3, which summarizes the results of AMR evaluations for the 

Compressed Air System component groups. The staff’s review did not identify any AMR items 

with notes F through J, indicating that the combinations of component type, material,

environment, and AERM for the Compressed Air System component groups are consistent with 

the GALL Report.

Control Rod Drive System – Summary of Aging Management Review –

LRA Table 3.3.2-4

The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for the 

Control Rod Drive System component groups. The staff’s review did not identify any AMR items 

with notes F through J, indicating that the combinations of component type, material,

environment, and AERM for the Control Rod Drive System component groups are consistent 

with the GALL Report.

Control Room Ventilation System – Summary of Aging Management Review –

LRA Table 3.3.2-5

The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for the 

Control Room Ventilation System component groups.

Elastomer Flexible Connections, Ducting, and Components Exposed to Internal Condensation. 

In LRA Tables 3.3.2-5, 3.3.2-8, and 3.3.2-22, the applicant stated that elastomer flexible 

connections, ducting, and components exposed to internal condensation will be managed for 

hardening, loss of strength, and loss of material by the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program. The AMR items cite generic note G.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. Based on its review of the GALL Report, which states 

that elastomers exposed to condensation are susceptible to hardening, loss of strength, and 

loss of materials, the staff finds that the applicant has identified all credible aging effects for the 

component, material, and environment combinations.
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The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components program is documented in SER Section 3.0.3.1.13. The staff finds 

the applicant’s proposal to manage aging using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program acceptable because the opportunistic 

visual inspections conducted by the program, with a representative sample of components 

periodically inspected, are capable of detecting hardening, loss of strength, and loss of material 

in elastomers by observing for cracking, other surface discontinuities, and discoloration.

Aluminum Heat Exchanger Fins and Copper Alloy Heat Exchanger Tubes Exposed to External 

Condensation. In LRA Tables 3.3.2-5 and 3.3.2-22, the applicant stated that aluminum heat 

exchanger fins and copper alloy (less than 15-percent zinc) heat exchanger tubes exposed to 

external condensation will be managed for reduction of heat transfer by the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components program. The AMR items 

cite generic note G and plant-specific notes, which state that the components are located within 

HVAC ducting, and the external surfaces are subject to the internal HVAC environment of 

condensation during normal operation. The notes also state that the visual inspections 

performed by the AMP are capable of identifying aging mechanisms that cause reduction of 

heat transfer for these components.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant addressed loss of 

material for this component, material, and environment combination in other AMR items in LRA 

Tables 3.3.2-5 and 3.3.2-22. Based on its review of the GALL Report, the staff finds that the 

applicant has identified all credible aging effects for this component, material, and environment 

combination.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components program is documented in SER Section 3.0.3.1.13. The staff finds 

the applicant’s proposal to manage aging using the above program acceptable because the 

opportunistic visual inspections conducted by the program, with a representative sample of 

components periodically inspected, are capable of detecting reduction in heat transfer in 

aluminum fins and copper alloy tubes.

Cranes, Hoists, and Refueling Equipment System – Summary of Aging 

Management Review – LRA Table 3.3.2-6

The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for the 

Cranes, Hoists, and Refueling Equipment System component groups. The staff’s review did not 

identify any AMR items with notes F through J, indicating that the combinations of component 

type, material, environment, and AERM for the Cranes, Hoists and Refueling Equipment System

component groups are consistent with the GALL Report.

Demineralized Water Makeup System – Summary of Aging Management Review –

LRA Table 3.3.2-7

The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for the 

Demineralized Water Makeup System component groups.

Carbon Steel and Copper Alloy with Internal Coatings, and Galvanized Steel Piping, Piping 

Components, and Heat Exchangers Exposed to Treated Water, Raw Water, and Waste Water. 
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In LRA Tables 3.3.2-7, 3.3.2-11, 3.3.2-12, 3.3.2-14, and 3.3.2-16, the applicant stated that 

carbon steel and copper alloy with 15-percent zinc or more, with internal coatings, and 

galvanized steel piping, piping components, and heat exchangers exposed to treated water, raw 

water, and waste water will be managed for loss of coating integrity by the Service Level III and 

Service Level III Augmented Coatings Monitoring and Maintenance Program. The AMR items 

cite generic note H.

The staff noted that this material and environment combination is identified in 

LR-ISG-2013-01, “Aging Management of Loss of Coating or Lining Integrity for Internal 

Coatings/Linings on In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.” 

LR-ISG-2013-01 Table 3.3-1, item 3.3.1-138, states that loss of coating integrity for metallic 

piping, piping components, and heat exchangers with internal coatings/linings exposed to 

treated water, raw water, and waste water is managed by GALL Report AMP XI.M42, “Internal 

Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.” The 

staff noted that, because LR-ISG-2013-01 was in a draft versus final status at the time the LRA 

was developed, the applicant chose to develop a plant-specific program to manage loss of 

coating integrity.

The staff’s evaluation of the applicant’s Service Level III and Service Level III Augmented 

Coatings Monitoring and Maintenance Program is documented in SER Section 3.0.3.3.1. The 

staff finds the applicant’s proposal to manage loss of coating integrity using the Service Level III 

and Service Level III Augmented Coatings Monitoring and Maintenance Program acceptable 

because the program includes periodic visual inspections capable of detecting loss of coating 

integrity by qualified individuals.

Copper Alloy Valve Body Exposed to Treated Water. In LRA Table 3.2.2-7, the applicant stated 

that copper alloy with 15-percent zinc or more valve bodies exposed to treated water will be 

managed for cracking by the Water Chemistry program. The AMR item cites generic note H, 

and plant-specific note 1, which states that vent valves in the supply pipe to the clean gland 

water tank are brass, ASTM B584, alloy material that has a zinc content of 15 percent. The 

One-Time Inspection (LRA Section B.2.1.21) program and Water Chemistry (LRA 

Section B.2.1.2) program are used to manage cracking in treated water for this component, 

material, and environment combination.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that copper alloy with 15-percent zinc or more exposed to treated water is 

susceptible to selective leaching and recommends GALL Report AMP XI.M33, “Selective 

Leaching,” to manage the aging effect. However, the applicant has identified cracking as an 

additional aging effect. The applicant addressed the GALL Report-identified aging effects for 

this component, material, and environment combination in other AMR items in LRA 

Table 3.2.2-7.

The staff’s evaluation of the applicant’s Water Chemistry and One-Time Inspection programs is 

documented in SER Sections 3.0.3.2.1 and 3.0.3.1.9, respectively. The staff finds the 

applicant’s proposal to manage the effects of aging using the Water Chemistry program 

acceptable because the program consists of periodic monitoring of the treated water to control 

known detrimental contaminants, such as chlorides, dissolved oxygen, and sulfate 

concentrations, so that they remain below the levels known to result in loss of material or 

cracking. The staff noted that the One-Time inspection program will be used to verify the 

system-wide effectiveness of the Water Chemistry program by inspections focusing on locations 

that are isolated from the flow stream, that are stagnant, or that have low flow for extended 
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periods and are susceptible to the gradual accumulation or concentration of agents that promote 

certain aging effects. Additionally, the One-Time Inspection program verifies either that 

unacceptable degradation is not occurring or triggers additional actions that will ensure that the 

intended function of affected components will be maintained during the period of extended 

operation.

Diesel Generator and Auxiliaries System – Summary of Aging Management Review

– LRA Table 3.3.2-8

The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for the 

Diesel Generator and Auxiliaries System component groups.

Carbon Steel Piping, Piping Components, and Piping Elements Exposed to Diesel Exhaust 

(Internal). In LRA Table 3.3.2-8, the applicant stated that carbon steel piping, piping 

components, and piping elements exposed to diesel exhaust will be managed for cumulative 

fatigue damage by a TLAA. The AMR item cites generic note H. The AMR item cites 

plant-specific note 1, which states that the TLAA used to manage fatigue in this component is 

evaluated in LRA Section 4.3.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that steel piping, piping components, and piping elements exposed to diesel 

exhaust are susceptible to loss of material and recommends GALL Report AMP XI.M38 to 

manage the aging effect. However, the applicant has identified cumulative fatigue damage as 

an additional aging effect. The applicant addressed the GALL Report-identified aging effects for 

this component, material, and environment combination in other AMR items in LRA 

Table 3.3.2-8.

The staff’s evaluation of the applicant’s TLAA for metal fatigue is documented in SER 

Section 4.3.2, which evaluates the applicant’s TLAA for ASME Code Section III, Class 2 and 3,

and ANSI B31.1 allowable stress calculations. The staff finds the applicant’s proposal to 

manage cumulative fatigue damage using a TLAA acceptable because the applicant provided 

the thermal and pressure transients that will affect this component and justified that the 

projected cycle occurrences of these transients will not be exceeded during the period of 

extended operation; therefore, the original stress calculations remain valid, and fatigue will be 

adequately managed.

Copper Alloy Heat Exchanger Tubes and Tube Sheets Exposed to Closed-Cycle Cooling Water. 

In LRA Table 3.3.2-8, the applicant stated that copper-alloy (with 15 percent or more zinc) heat 

exchanger tubes and tube sheets exposed to closed-cycle cooling water will be managed for 

cracking by the Closed Treated Water Systems program. The AMR items cite generic note H.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that copper-alloy heat exchanger components exposed to closed treated water are 

susceptible to loss of material and reduction of heat transfer due to fouling and recommends the 

Closed Treated Water Systems program to manage these aging effects. However, the 

applicant has identified cracking as an additional aging effect. The applicant addressed the 

aging effects identified in the GALL Report for this component, material, and environment 

combination in other AMR items in LRA Table 3.3.2-8.

The staff’s evaluation of the applicant’s Closed Treated Water Systems program is documented 

in SER Section 3.0.3.2.6. The staff finds the applicant’s proposal to manage cracking of 
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copper-alloy heat exchanger components using the specified program acceptable because the 

Closed Treated Water Systems program manages cracking of heat exchanger component 

fabricated from other materials and because the applicant periodically verifies the effectiveness 

of the program through nondestructive examinations of representative samples of components.

Elastomer Ducting and Components Exposed to Internal Condensation. The staff’s evaluation 

for elastomer ducting and components exposed to internal condensation, which will be 

managed for hardening and loss of strength by the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program and are associated with generic 

note G, is documented in SER Section 3.3.2.3.5.

Drywell Pneumatic System – Summary of Aging Management Review –

LRA Table 3.3.2-9

The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for the 

Drywell Pneumatic System component groups.

Polymer Piping and Piping Components Exposed to Air (External Indoor Uncontrolled) or 

Condensation. In LRA Table 3.3.2-9, the applicant stated that polymer piping and piping 

components exposed to air (external indoor uncontrolled) and condensation will be managed for 

change in material properties and loss of material by the External Surfaces Monitoring of 

Mechanical Components program and by the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components program. The AMR items cite generic note G.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. Based on its review of the GALL Report, which states 

that polymers exposed to air (external indoor uncontrolled) and condensation are susceptible to 

change in material properties and loss of material, the staff finds that the applicant has identified 

all credible aging effects for this component, material, and environment combination.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components program is documented in SER Section 3.0.3.1.13. The staff’s 

evaluation of the applicant’s External Surfaces Monitoring of Mechanical Components program 

is documented in SER Section 3.0.3.1.12. The staff finds the applicant’s proposal to manage 

aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program and by using the External Surfaces Monitoring of Mechanical 

Components program acceptable because the opportunistic visual inspections conducted by the 

programs, with a representative sample of components periodically inspected, are capable of 

detecting change in material properties and loss of material in polymers by observing for 

cracking, other surface discontinuities, and discoloration.

Electrical Penetration Pressurization System – Summary of Aging Management 

Review – LRA Table 3.3.2-10

The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations for 

the Electrical Penetration Pressurization System component groups. The staff’s review did not 

identify any AMR items with notes F through J, indicating that the combinations of component 

type, material, environment, and AERM for the Electrical Penetration Pressurization System

component groups are consistent with the GALL Report.
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Essential Cooling Water System – Summary of Aging Management Review –

LRA Table 3.3.2-11

The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations for 

the Essential Cooling Water System component groups.

Carbon Steel and Copper Alloy with 15% Zinc or More, with Internal Coatings, and Galvanized 

Steel Piping, Piping Components, and Heat Exchangers Exposed to Treated Water, Raw Water, 

and Waste Water. The staff’s evaluation for carbon steel and copper alloy with 15-percent zinc 

or more, with internal coatings, and galvanized steel piping, piping components, and heat 

exchangers exposed to treated water, raw water, and waste water, which will be managed for 

loss of coating integrity by the Service Level III and Service Level III Augmented Coatings 

Monitoring and Maintenance Program and are associated with generic note H, is documented in 

SER Section 3.3.2.3.7.

Fire Protection System – Summary of Aging Management Review –

LRA Table 3.3.2-12

The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations for 

the Fire Protection System component groups.

Carbon Steel and Copper Alloy with Internal Coatings, and Galvanized Steel Piping, Piping 

Components, and Heat Exchangers Exposed to Treated Water, Raw Water, and Waste Water. 

The staff’s evaluation for carbon steel and copper alloy with 15-percent zinc or more, with 

internal coatings, and galvanized steel piping, piping components, and heat exchangers 

exposed to treated water, raw water, and waste water, which will be managed for loss of coating 

integrity by the Service Level III and Service Level III Augmented Coatings Monitoring and 

Maintenance Program and are associated with generic note H, is documented in SER 

Section 3.3.2.3.7.

Carbon Steel Piping, Piping Components, and Piping Elements Exposed to Diesel Exhaust 

(Internal). In LRA Table 3.3.2-12, the applicant stated that carbon steel piping, piping 

components, and piping elements exposed to diesel exhaust will be managed for cumulative 

fatigue damage by a TLAA. The AMR item cites generic note H. The AMR item cites 

plant-specific note 6, which states that the TLAA used to manage fatigue in this component is 

evaluated in LRA Section 4.3.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that steel piping, piping components, and piping elements exposed to diesel 

exhaust are susceptible to loss of material and recommends GALL Report AMP XI.M38 to 

manage the aging effect. However, the applicant has identified cumulative fatigue damage as 

an additional aging effect. The applicant addressed the GALL Report-identified aging effects for 

this component, material, and environment combination in other AMR items in LRA 

Table 3.3.2-8.

The staff’s evaluation of the applicant’s TLAA for metal fatigue is documented in SER 

Section 4.3.2, which evaluates the applicant’s TLAA for ASME Code Section III, Class 2 and 3,

and ANSI B31.1 allowable stress calculations. The staff finds the applicant’s proposal to 

manage cumulative fatigue damage using a TLAA acceptable because the applicant provided 

the thermal and pressure transients that will affect this component and justified that the 

projected cycle occurrences of these transients will not be exceeded during the period of 
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extended operation; therefore, the original stress calculations remain valid, and fatigue will be 

adequately managed.

Ceramic Fiber, Calcium Silicate, and Mineral Fiber Fire Barriers Exposed to Uncontrolled Indoor 

Air (External). In LRA Table 3.3.2-12, the applicant stated that ceramic fiber, calcium silicate, 

and mineral fiber fire barriers exposed to uncontrolled indoor air (external) have no aging 

effects. The applicant further stated that these components will be managed by the Fire 

Protection program. The AMR items cite generic note F and plant-specific note 4, which states 

that “[b]ased on plant engineering experience, there are no aging effects requiring aging 

management for calcium silicate, ceramic fiber, and mineral fiber in an uncontrolled indoor air 

environment. These materials do not experience aging effects due to temperature, radiation, or 

chemicals capable of attacking the specific chemical composition. These materials in this 

non-aggressive air environment are not expected to experience significant aging effects. 

Nonetheless, the Fire Protection program is credited to assuring the absence of any aging 

effects.”

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that ceramic fiber, calcium silicate, and 

mineral fiber are commonly used as fire barriers and/or insulation and are stable and 

non-reactive under ambient conditions. Maintaining material integrity and dimensional stability 

is key for these materials to fulfill their fire protection function. The staff further noted that, even 

though the GALL Report does not include AMR items for non-metallic fire barriers, GALL Report 

AMP XI.M26, “Fire Protection,” indeed encompasses aging management for other fire 

resistance materials (e.g., flamastic, 3MTM fire wrapping, spray-on fire proofing material, and 

intumescent coating) within the “scope of program.” GALL Report AMP XI.M26, “Fire 

Protection,” recommends that these materials be managed for loss of material and cracking, 

increased hardness, shrinkage, and loss of strength. Although the applicant stated that there 

are no aging effects for these materials, it nevertheless assigned the Fire Protection program to 

age manage these fire barrier materials. The applicant’s Fire Protection program specifies 

visual inspection of fire barrier materials at least once every refueling outage.

The staff’s evaluation of the applicant’s Fire Protection program is documented in SER 

Section 3.0.3.2.9. This program includes visual examinations of the fire barriers within the 

scope of license renewal to detect aging effects at least once every refueling outage. The staff 

finds that the applicant’s proposal to manage the effects of aging using the Fire Protection 

program acceptable because signs of aging effects and material integrity, such as cracking and 

shrinkage, can be detected by visual inspections. Additionally, it is consistent with the NRC 

guidance in RG 1.189, “Fire Protection for Nuclear Power Plants,” Section 1.7.4 “Inspection,” 

Revision 2, dated October 2009, and nuclear industry practice (such as the guidance in 

NUREG-1552, “Fire Barrier Penetration Seals in Nuclear Power Plants,” Supplement 1, dated 

January 1999) for ensuring the integrity of fire barriers through inspections.

Aluminum Silicate, Pyrocrete, and Gypsum Fire Barriers Exposed to Uncontrolled Indoor Air 

(External). In LRA Table 3.3.2-12, the applicant stated that aluminum silicate, pyrocrete, and 

gypsum fire barriers exposed to uncontrolled indoor air (external) will be managed for cracking 

by the Fire Protection program. The AMR items cite generic note F, and plant-specific note 3, 

which states that “the Fire Protection program will be used to manage the aging effects 

applicable to this component type, material, and environment combination.”
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The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that aluminum silicate, pyrocrete, and 

gypsum are typically used as fire barriers and are stable and non-reactive under ambient 

conditions. Maintaining material integrity and dimensional stability is key for the materials to 

fulfill their fire protection function. The staff further noted that, even though the GALL Report 

does not include AMR items for non-metallic fire barriers, GALL Report AMP XI.M26, “Fire 

Protection,” indeed encompasses aging management for other fire resistance materials 

(e.g., flamastic, 3MTM fire wrapping, spray-on fire proofing material, and intumescent coating) 

within the “scope of program.” GALL Report AMP XI.M26, “Fire Protection,” recommends that 

these materials be managed for loss of material and cracking, increased hardness, shrinkage, 

and loss of strength. It further specifies visual inspection of fire barrier materials at least once 

every refueling outage.

The staff’s evaluation of the applicant’s Fire Protection program is documented in SER 

Section 3.0.3.2.9. This program includes visual examinations of the fire barriers within the

scope of license renewal to detect aging effects at least once every refueling outage. The staff 

finds the applicant’s proposal to manage the effects of aging using the Fire Protection program 

acceptable because signs of aging effects and material integrity, such as cracking and 

shrinkage, can be detected by visual inspections. Additionally, it is consistent with the NRC 

guidance in RG 1.189, “Fire Protection for Nuclear Power Plants,” Section 1.7.4, “Inspection,” 

Revision 2, dated October 2009; nuclear industry practice (such as the guidance in 

NUREG-1552, “Fire Barrier Penetration Seals in Nuclear Power Plants,” Supplement 1, dated 

January 1999); and the GALL Report recommendation for ensuring the integrity of fire barriers.

Fuel Pool Cooling and Storage System – Summary of Aging Management Review –

LRA Table 3.3.2-13

The staff reviewed LRA Table 3.3.2-13, which summarizes the results of AMR evaluations for 

the Fuel Pool Cooling and Storage System component groups. The staff’s review did not 

identify any AMR items with notes F through J, indicating that the combinations of component 

type, material, environment, and AERM for the Fuel Pool Cooling and Storage System

component groups are consistent with the GALL Report.

Nonessential Cooling Water System – Summary of Aging Management Review –

LRA Table 3.3.2-14

The staff reviewed LRA Table 3.3.2-14, which summarizes the results of AMR evaluations for 

the Nonessential Cooling Water System component groups.

Carbon Steel and Copper Alloy with Internal Coatings, and Galvanized Steel Piping, Piping 

Components, and Heat Exchangers Exposed to Treated Water, Raw Water, and Waste Water. 

The staff’s evaluation for carbon steel and copper alloy with 15-percent zinc or more, with 

internal coatings, and galvanized steel piping, piping components, and heat exchangers 

exposed to treated water, raw water, and waste water, which will be managed for loss of coating 

integrity by the Service Level III and Service Level III Augmented Coatings Monitoring and 

Maintenance Program and are associated with generic note H, is documented in SER 

Section 3.3.2.3.7.
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Nonsafety-Related Ventilation System – Summary of Aging Management Review –

LRA Table 3.3.2-15

The staff reviewed LRA Table 3.3.2-15, which summarizes the results of AMR evaluations for 

the Nonsafety-Related Ventilation System component groups. The staff’s review did not identify 

any AMR items with notes F through J, indicating that the combinations of component type, 

material, environment, and AERM for the Nonsafety-Related Ventilation System component 

groups are consistent with the GALL Report.

Plant Drainage System – Summary of Aging Management Review –

LRA Table 3.3.2-16

The staff reviewed LRA Table 3.3.2-16, which summarizes the results of AMR evaluations for 

the Plant Drainage System component groups.

Carbon Steel and Copper Alloy with Internal Coatings, and Galvanized Steel Piping, Piping 

Components, and Heat Exchangers Exposed to Treated Water, Raw Water, and Waste Water. 

The staff’s evaluation for carbon steel and copper alloy with 15-percent zinc or more, with 

internal coatings, and galvanized steel piping, piping components, and heat exchangers 

exposed to treated water, raw water, and waste water, which will be managed for loss of coating 

integrity by the Service Level III and Service Level III Augmented Coatings Monitoring and 

Maintenance Program and are associated with generic note H, is documented in SER 

Section 3.3.2.3.7.

Polymer Hoses Exposed to Waste Water. In LRA Table 3.3.2-16, the applicant stated that 

polymer hoses exposed to waste water is not applicable to any AERM. The AMR items cite 

generic note G. The applicant stated that the polymer hoses used in waste water environment 

are Tygon® tubing, which is flexible transparent tubing, is considered non-aging and 

non-oxidizing, and has broad chemical resistance.

The staff noted that this material and environment combination is not identified in the 

GALL Report. The staff also noted that the applicant has been using this material in this 

environment and has not experienced any aging effects. The staff further noted that Tygon®

flexible tubing is widely used in other applications with more aggressive environments with 

satisfactory results. Therefore, the staff finds the applicant’s proposal acceptable because 

Tygon® polymer hoses exposed to a waste water environment are not expected to have any 

detrimental aging effects.

Primary Containment Ventilation System – Summary of Aging Management 

Review – LRA Table 3.3.2-17

The staff reviewed LRA Table 3.3.2-17, which summarizes the results of AMR evaluations for 

the Primary Containment Ventilation System component groups. The staff’s review did not 

identify any AMR items with notes F through J, indicating that the combinations of component 

type, material, environment, and AERM for the Primary Containment Ventilation System

component groups are consistent with the GALL Report.
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Process Radiation Monitoring System – Summary of Aging Management Review –

LRA Table 3.3.2-18

The staff reviewed LRA Table 3.3.2-18, which summarizes the results of AMR evaluations for 

the Process Radiation Monitoring System component groups. The staff’s review did not identify 

any AMR items with notes F through J, indicating that the combinations of component type, 

material, environment, and AERM for the Process Radiation Monitoring System component 

groups are consistent with the GALL Report.

Process Sampling and Post-Accident Monitoring System – Summary of Aging 

Management Review – LRA Table 3.3.2-19

The staff reviewed LRA Table 3.3.2-19, which summarizes the results of AMR evaluations for 

the Process Sampling and Post-Accident Monitoring System component groups. The staff’s 

review did not identify any AMR items with notes F through J, indicating that the combinations of 

component type, material, environment, and AERM for the Process Sampling and Post-Accident 

Monitoring System component groups are consistent with the GALL Report.

Radwaste System – Summary of Aging Management Review – LRA Table 3.3.2-20

The staff reviewed LRA Table 3.3.2-20, which summarizes the results of AMR evaluations for 

the Radwaste System component groups. The staff’s review did not identify any AMR items 

with notes F through J, indicating that the combinations of component type, material,

environment, and AERM for the Radwaste System component groups are consistent with the 

GALL Report.

Reactor Water Cleanup System – Summary of Aging Management Review –

LRA Table 3.3.2-21

The staff reviewed LRA Table 3.3.2-21, which summarizes the results of AMR evaluations for 

the Reactor Water Cleanup System component groups. The staff’s review did not identify any

AMR items with notes F through J, indicating that the combinations of component type, material,

environment, and AERM for the Reactor Water Cleanup System component groups are 

consistent with the GALL Report.

Safety-Related Ventilation System – Summary of Aging Management Review –

LRA Table 3.3.2-22

The staff reviewed LRA Table 3.3.2-22, which summarizes the results of AMR evaluations for 

the Safety-Related Ventilation System component groups.

Elastomer Ducting and Components Exposed to Internal Condensation. The staff’s evaluation 

of elastomer ducting and components exposed to internal condensation, which will be managed 

for hardening, loss of strength, and loss of material by the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program and are associated with generic 

note G, is documented in SER Section 3.3.2.3.5.

Aluminum Heat Exchanger Fins and Copper Alloy (Less Than 15-Percent Zinc) Heat Exchanger 

Tubes Exposed to Condensation. The staff’s evaluation of aluminum heat exchanger fins and 

copper alloy (less than 15-percent zinc) heat exchanger tubes exposed to external 

condensation, which will be managed for reduction of heat transfer by the Inspection of Internal 
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Surfaces in Miscellaneous Piping and Ducting Components program and are associated with 

generic note G, is documented in SER Section 3.3.2.3.5.

Standby Liquid Control System – Summary of Aging Management Review –

LRA Table 3.3.2-23

The staff reviewed LRA Table 3.3.2-23, which summarizes the results of AMR evaluations for 

the Standby Liquid Control System component groups.

Copper Alloy Piping, Piping Components, and Piping Elements Exposed to Treated Water. In 

LRA Table 3.2.2-23, the applicant stated that copper alloy with 15-percent zinc or more exposed 

to treated water will be managed for cracking by the Water Chemistry program. The AMR item

cites generic note H, and plant-specific note 2, which states the aging effects for copper alloy 

with 15-percent zinc or more in a treated water environment include cracking. The One-Time 

Inspection (LRA Section B.2.1.21) program and Water Chemistry (LRA Section B.2.1.2) 

program are used to manage cracking for copper alloy with 15-percent zinc or more in a treated 

water environment.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that copper alloy with 15-percent zinc or more exposed to treated water is 

susceptible to selective leaching and recommends GALL Report AMP XI.M33, “Selective 

Leaching,” to manage the aging effect. However, the applicant has identified cracking as an 

additional aging effect. The applicant addressed the GALL Report-identified aging effects for 

this component, material, and environment combination in other AMR items in LRA 

Table 3.2.2-23.

The staff’s evaluation of the applicant’s Water Chemistry and One-Time Inspection programs is 

documented in SER Sections 3.0.3.2.1 and 3.0.3.1.9, respectively. The staff finds the 

applicant’s proposal to manage the effects of aging using the Water Chemistry program 

acceptable because the program consists of periodic monitoring of the treated water to control 

known detrimental contaminants, such as chlorides, dissolved oxygen, and sulfate 

concentrations, so that they remain below the levels known to result in loss of material or 

cracking. The staff noted that the One-Time Inspection program will be used to verify the 

system-wide effectiveness of the Water Chemistry program by inspections focusing on locations 

that are isolated from the flow stream, that are stagnant, or that have low flow for extended 

periods and are susceptible to the gradual accumulation or concentration of agents that promote 

certain aging effects. Additionally, the One-Time Inspection program verifies either that 

unacceptable degradation is not occurring or triggers additional actions that will ensure the 

intended function(s) of affected components will be maintained during the period of extended 

operation.

Glass Piping, Piping Components, and Piping Elements Exposed to Sodium Pentaborate 

Solution. In LRA Table 3.3.2-23, the applicant stated that for glass piping, piping components, 

and piping elements exposed to a sodium pentaborate solution there is no aging effect and no 

proposed AMP. The AMR item cites generic note G.

The staff reviewed the associated item in the LRA to confirm that no credible aging effects are 

applicable to this component, material, and environment combination. The staff notes that 

LSCS UFSAR Table 9.3-2, “Standby Liquid Control System Operating Pressure Temperature 

Conditions,” provides the temperature range of the associated sodium pentaborate solution as 

70 to 100 °F. The staff finds the applicant’s proposal acceptable based on its review of 
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EPRI 1010639, “Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools,” 

which states that silicate glasses have a high resistance to corrosion in normal environments 

(i.e., an aqueous environment less than 250 °C (482 °F) and not containing hydrofluoric or 

phosphoric acids).

Suppression Pool Cleanup System – Summary of Aging Management Review –

LRA Table 3.3.2-24

The staff reviewed LRA Table 3.3.2-24, which summarizes the results of AMR evaluations for 

the Suppression Pool Cleanup System component groups. The staff’s review did not identify 

any AMR items with notes F through J, indicating that the combinations of component type, 

material, environment, and AERM for the Suppression Pool Cleanup System component groups 

are consistent with the GALL Report.

Traversing Incore Probe System – Summary of Aging Management Review –

LRA Table 3.3.2-25

The staff reviewed LRA Table 3.3.2-25, which summarizes the results of AMR evaluations for 

the Traversing Incore Probe System component groups. The staff’s review did not identify any

AMR items with notes F through J, indicating that the combinations of component type, material,

environment, and AERM for the Traversing Incore Probe System component groups are 

consistent with the GALL Report.

3.3.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the auxiliary systems components within the scope of license renewal 

and subject to an AMR will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.4 Aging Management of Steam and Power Conversion System

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

steam and power conversion system components of the following:

• Condensate System

• Condenser and Air Removal System

• Feedwater System

• Main Steam System

• Main Turbine and Auxiliaries System

3.4.1 Summary of Technical Information in the Application

LRA Section 3.4 provides the AMR results for the steam and power conversion system

components and component groups. LRA Table 3.4.1, “Summary of Aging Management 

Evaluations for the Steam and Power Conversion System,” is a summary comparison of the 

applicant’s AMRs with those evaluated in the GALL Report for the steam and power conversion 

system components and component groups.
3-287

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report.

3.4.2 Staff Evaluation

The staff reviewed LRA Section 3.4 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the steam and power conversion system

components within the scope of license renewal and subject to an AMR will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

The staff conducted a review of the applicant’s AMRs to verify the applicant’s claim that certain 

AMRs are consistent with the GALL Report or are not applicable. The staff did not repeat its 

review of the matters described in the GALL Report; however, the staff did verify that the 

material presented in the LRA is applicable and that the applicant identified the appropriate 

GALL Report AMRs. AMRs that the staff confirmed are consistent with the GALL Report are 

noted as such in Table 3.4-1; therefore, no further discussion is required. AMRs that the staff 

confirmed are not applicable to LSCS or require no aging management are noted in Table 3.4-1 

and are discussed in SER Section 3.4.2.1.1.

During its review, the staff also reviewed AMRs consistent with the GALL Report and those for 

which further evaluation is recommended. The staff confirmed that the applicant’s further 

evaluations are consistent with the SRP-LR Section 3.4.2.2 acceptance criteria. The staff’s 

evaluations of AMRs for which the GALL Report recommends further evaluation are 

documented in SER Section 3.4.2.2.

The staff also conducted a technical review of the remaining AMRs that are not consistent with 

or are not addressed in the GALL Report. The technical review evaluated whether all plausible 

aging effects have been identified and whether the aging effects listed are appropriate for the 

material-environment combinations specified. The staff’s evaluations of AMRs that are not 

consistent with or are not addressed in the GALL Report are documented in SER 

Section 3.4.2.3.

Table 3.4-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.4 and addressed in the GALL Report.
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Staff Evaluation for Steam and Power Conversion System Components in the 

GALL Report

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to steam or 

treated water 

(3.4.1-1)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a timelimited aging 

analysis (TLAA) to 

be evaluated for the 

period of extended 

operation. See the 

SRP, Section 4.3 

“Metal Fatigue,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1).

Yes TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.4.2.2.1)

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

air – outdoor 

(3.4.1-2)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report (see 

SER Section 

3.4.2.2.2)

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

air – outdoor 

(3.4.1-3)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report (see 

SER Section 

3.4.2.2.3)

Steel external 

surfaces, bolting 

exposed to air with 

borated water 

leakage (3.4.1-4)

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to steam, 

treated water 

(3.4.1-5)

Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Flow-Accelerated 

Corrosion

An exception 

applies to the 

Flow-Accelerated 

Corrosion 

program

Consistent with the 

GALL Report

Steel, stainless steel 

bolting exposed to 

soil (3.4.1-6)

Loss of preload Chapter XI.M18, 

“Bolting Integrity”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

High-strength steel 

closure bolting 

exposed to air with 

steam or water 

leakage (3.4.1-7)

Cracking due to 

cyclic loading, 

stress corrosion 

cracking

Chapter XI.M18, 

“Bolting Integrity”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)
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Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel; stainless steel 

bolting, closure 

bolting exposed to 

air – outdoor 

(external), air –

indoor, uncontrolled 

(external) (3.4.1-8)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Steel closure bolting 

exposed to air with 

steam or water 

leakage (3.4.1-9)

Loss of material 

due to general 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Copper alloy, nickel 

alloy, steel; stainless 

steel, steel; stainless 

steel bolting, closure 

bolting exposed to 

any environment, air 

– outdoor (external), 

air – indoor, 

uncontrolled 

(external) (3.4.1-10)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements, 

tanks, heat 

exchanger 

components 

exposed to steam, 

treated water >60°C 

(>140°F) (3.4.1-11)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection, and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Steel; stainless steel 

tanks exposed to 

treated water 

(3.4.1-12)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection, and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to treated 

water (3.4.1-13)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Steel piping, piping 

components, and 

piping elements, 

PWR heat 

exchanger 

components 

exposed to steam, 

treated water 

(3.4.1-14)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection, and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report
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Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel heat 

exchanger 

components 

exposed to treated 

water (3.4.1-15)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection, and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Copper alloy, 

stainless steel, 

nickel alloy, 

aluminum piping, 

piping components, 

and piping elements, 

heat exchanger 

components and 

tubes, PWR heat 

exchanger 

components 

exposed to treated 

water, steam 

(3.4.1-16)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection, and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Copper alloy heat 

exchanger tubes 

exposed to treated 

water (3.4.1-17)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Copper alloy, 

stainless steel heat 

exchanger tubes 

exposed to treated 

water (3.4.1-18)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No One-Time 

Inspection, and 

Water Chemistry

An exception 

applies to the 

Water Chemistry 

program

Consistent with the 

GALL Report

Stainless steel, steel 

heat exchanger 

components 

exposed to raw 

water (3.4.1-19)

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Copper alloy, 

stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.4.1-20)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)
3-291

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel heat 

exchanger 

components 

exposed to raw 

water (3.4.1-21)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Stainless steel, 

copper alloy, steel 

heat exchanger 

tubes, heat 

exchanger 

components 

exposed to raw 

water (3.4.1-22)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to closedcycle cooling water 

>60°C (>140°F) 

(3.4.1-23)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Steel heat 

exchanger 

components 

exposed to closedcycle cooling water 

(3.4.1-24)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Steel heat 

exchanger 

components 

exposed to closedcycle cooling water 

(3.4.1-25)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Stainless steel heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to closedcycle cooling water 

(3.4.1-26)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Copper alloy piping, 

piping components, 

and piping elements 

exposed to closedcycle cooling water 

(3.4.1-27)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)
3-292

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel, stainless 

steel, copper alloy 

heat exchanger 

components and 

tubes, heat 

exchanger tubes 

exposed to closedcycle cooling water 

(3.4.1-28)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M21A, 

“Closed Treated

Water Systems”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Steel tanks exposed 

to air – outdoor 

(external) (3.4.1-29)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Steel, Stainless 

Steel, Aluminum 

Tanks (within the 

scope of Chapter 

XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to soil or 

concrete, or the 

following external 

environments airoutdoor, air-indoor 

uncontrolled, moist 

air, condensation

(3.4.1-30)

Loss of material 

due to general

(steel only), 

pitting, and 

crevice 

corrosion; 

cracking due to 

stress corrosion 

cracking 

(stainless steel 

and aluminum 

only)

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Stainless steel, 

aluminum tanks 

(within the scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to soil or 

concrete, or the 

following external 

environments airoutdoor, air-indoor 

uncontrolled, moist 

air, condensation 

(3.4.1-31)

Loss of material 

due to pitting, 

and crevice 

corrosion; 

cracking due to 

stress corrosion 

cracking

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Aboveground 

Metallic Tanks

Consistent with the 

GALL Report

Gray cast iron 

piping, piping 

components, and 

piping elements 

exposed to soil 

(3.4.1-32)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)
3-293

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Gray cast iron, 

copper alloy (>15% 

Zn or >8% Al) 

piping, piping 

components, and 

piping elements 

exposed to treated 

water, raw water, 

closed-cycle cooling 

water (3.4.1-33)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Steel external 

surfaces exposed to 

air – indoor, 

uncontrolled 

(external), air –

outdoor (external), 

condensation 

(external) (3.4.1-34)

Loss of material 

due to general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report

Aluminum piping, 

piping components, 

and piping elements 

exposed to air –

outdoor (3.4.1-35)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to air –

outdoor (internal) 

(3.4.1-36)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER

Section 3.4.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to 

condensation 

(internal) (3.4.1-37)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.4.1-38)

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

condensation 

(internal) (3.4.1-39)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous

Piping and Ducting 

Components”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)
3-294

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil 

(3.4.1-40)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Steel heat 

exchanger 

components 

exposed to 

lubricating oil 

(3.4.1-41)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Aluminum piping, 

piping components, 

and piping elements 

exposed to 

lubricating oil 

(3.4.1-42)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Copper alloy piping, 

piping components, 

and piping elements 

exposed to 

lubricating oil 

(3.4.1-43)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements, 

heat exchanger 

components 

exposed to 

lubricating oil 

(3.4.1-44)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Aluminum heat 

exchanger 

components and 

tubes exposed to 

lubricating oil 

(3.4.1-45)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Stainless steel,

steel, copper alloy 

heat exchanger 

tubes exposed to 

lubricating oil 

(3.4.1-46)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Steel (with coating or 

wrapping) stainless 

steel, nickel alloy 

piping, piping 

components, and 

piping elements; 

tanks exposed to soil 

or concrete 

(3.4.1-47)

Loss of material 

due to general

(steel only), 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Buried and 

Underground 

Piping

Consistent with the 

GALL Report
3-295

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel, 

nickel alloy bolting 

exposed to soil 

(3.4.1-48)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Stainless steel, 

nickel alloy piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.4.1-49)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Steel bolting 

exposed to soil 

(3.4.1-50)

Loss of material 

due to general, 

pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Underground 

stainless steel, 

nickel alloy, steel 

piping, piping 

components, and 

piping elements 

(3.4.1-50x)

Loss of material 

due to general 

(steel only), 

pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to concrete 

(3.4.1-51)

None None, provided 

1) attributes of the 

concrete are 

consistent with 

ACI 318 or ACI 349 

(low water-to-cement 

ratio, low 

permeability, and 

adequate air 

entrainment) as cited 

in NUREG-1557, 

and 

2) plant OE indicates 

no degradation of 

the concrete

No, if 

conditions 

are met.

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Aluminum piping, 

piping components, 

and piping elements 

exposed to gas, air –

indoor, uncontrolled 

(internal/external) 

(3.4.1-52)

None None NA - No 

AEM or 

AMP

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Copper alloy (≤15% 

Zn and ≤8% Al) 

piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage (3.4.1-53)

None None NA - No 

AEM or 

AMP

Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.4.2.1.1)
3-296

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Copper alloy piping, 

piping components, 

and piping elements 

exposed to gas, air –

indoor, uncontrolled 

(external) (3.4.1-54)

None None NA - No 

AEM or 

AMP

Consistent with 

NUREG-1801 (the 

GALL Report)

Consistent with the 

GALL Report

Glass piping 

elements exposed to 

lubricating oil, air –

outdoor, 

condensation 

(internal/external), 

raw water, treated 

water, air with 

borated water 

leakage, gas, 

closed-cycle cooling 

water, air – indoor, 

uncontrolled 

(external) (3.4.1-55)

None None NA - No 

AEM or 

AMP

Consistent with 

NUREG-1801 (the 

GALL Report)

Consistent with the 

GALL Report

Nickel alloy piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(external) (3.4.1-56)

None None NA - No 

AEM or 

AMP

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Nickel alloy, PVC 

piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage, air – indoor, 

uncontrolled, 

condensation 

(internal) (3.4.1-57)

None None NA - No 

AEM or 

AMP

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to air –

indoor, uncontrolled 

(external), concrete, 

gas, air – indoor, 

uncontrolled 

(internal) (3.4.1-58)

None None NA - No 

AEM or 

AMP

Consistent with 

NUREG-1801 (the 

GALL Report)

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to air –

indoor controlled 

(external), gas 

(3.4.1-59)

None None NA - No 

AEM or 

AMP

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.1.1)
3-297

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Any material, piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.4.1-60)

Wall thinning 

due to erosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Flow-Accelerated 

Corrosion

An exception 

applies to the 

Flow-Accelerated 

Corrosion 

program

Consistent with the 

GALL Report

Metallic piping, 

piping components, 

and tanks exposed 

to raw water or 

waste water 

(3.4.1-61)

Loss of material 

due to recurring 

internal 

corrosion

A plant-specific 

aging management 

program is to be 

evaluated to address 

recurring internal 

corrosion

Yes, plantspecificNot Applicable Not Applicable to 

LSCS (see SER 

Section 3.4.2.2.6)

Steel, stainless steel 

or aluminum tanks 

(within the scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to treated 

Water (3.4.1-62)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Aboveground 

Metallic Tanks

Consistent with the 

GALL Report

Insulated steel, 

stainless steel, 

copper alloy, 

aluminum, or copper 

alloy (> 15% Zn) 

piping, piping 

components, and 

tanks exposed to 

condensation, airoutdoor 

(3.4.1-63)

Loss of material 

due to general 

(steel, and 

copper alloy), 

pitting, or 

crevice 

corrosion, and 

cracking due to 

stress corrosion 

cracking 

(aluminum, 

stainless steel 

and copper alloy 

(>15% Zn) only)

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” or 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” (for 

tanks only)

No External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report

Jacketed calcium 

silicate or fiberglass 

insulation in an airindoor uncontrolled 

or air-outdoor 

environment 

(3.4.1-64)

Reduced 

thermal 

insulation 

resistance due 

to moisture 

intrusion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report

Jacketed 

FOAMGLAS® (glass 

dust) insulation in an 

air-indoor 

uncontrolled or airoutdoor environment 

(3.4.1-65)

Reduced 

thermal 

insulation 

resistance due 

to moisture 

intrusion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report
3-298

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Metallic piping, 

piping components, 

heat exchangers, 

tanks with internal 

coatings/linings 

exposed to closedcycle cooling water, 

raw water, treated 

water, treated 

borated water, or

lubricating oil

(3.4.1-66)

Loss of coating 

or lining integrity 

due to blistering, 

cracking, 

flaking, peeling, 

delamination, 

rusting, or 

physical 

damage, and 

spalling for 

cementitious 

coatings/linings

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks”

No Not Used Not Used 

(see SER 

Section 3.4.2.1.1)

Metallic piping, 

piping components, 

heat exchangers, 

tanks with internal 

coatings/linings 

exposed to closedcycle cooling water, 

raw water, treated 

water, treated 

borated water, or

lubricating oil

(3.4.1-67)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks”

No Not Used Not Used 

(see SER 

Section 3.4.2.1.1)

Gray cast iron piping 

components with 

internal 

coatings/linings 

exposed to closedcycle cooling water, 

raw water, or treated 

water (3.4.1-68)

Loss of material 

due to selective 

leaching

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks”

No Not Used Not Used 

(see SER 

Section 3.4.2.1.1)

3.4.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.4.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the Steam and Power Conversion System components:

• Aboveground Metallic Tanks

• Bolting Integrity

• Buried and Underground Piping

• External Surfaces Monitoring of Mechanical Components

• Flow-Accelerated Corrosion

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

• One-Time Inspection

• TLAA

• Water Chemistry

LRA Tables 3.4.2-1 through 3.4.2-5 summarize AMRs for the Steam and Power Conversion 

System components and indicate AMRs claimed to be consistent with the GALL Report.
3-299

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components in these 

GALL Report component groups were bounded by the GALL Report evaluation. The applicant 

provided a note for each AMR item. The notes describe how the information in the tables aligns 

with the information in the GALL Report. The staff audited those AMRs with notes A through E, 

which indicate how the AMR was consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these AMR items to confirm consistency with the GALL Report and the validity 

of the AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff audited these AMR items to confirm consistency with 

the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to 

the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant 

was consistent with the AMP identified in the GALL Report and whether the AMR was valid for 

the site-specific conditions.

Note C indicates that the component for the AMR item, although different from that in the 

GALL Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP is consistent with the AMP identified by the GALL Report. Note C indicates 

that the applicant was unable to find a listing of some system components in the GALL Report; 

however, the applicant identified a different component in the GALL Report that had the same 

material, environment, aging effect, and AMP as those of the component under review. The 

staff audited these AMR items to confirm consistency with the GALL Report. The staff also 

determined whether the AMR item of the different component applied to the component under 

review and whether the AMR was valid for the site-specific conditions.

Note D indicates that the component for the AMR item, although different from that in the 

GALL Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff 

audited these AMR items to confirm consistency with the GALL Report and confirmed whether 

the AMR item of the different component was applicable to the component under review. The 

staff confirmed whether it had reviewed and accepted the exceptions to the GALL Report AMPs. 

The staff also determined whether the AMP identified by the applicant was consistent with the 

AMP identified in the GALL Report and whether the AMR was valid for the site-specific 

conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect; however, a different AMP is credited. The staff audited these 

AMR items to confirm consistency with the GALL Report and determined whether the identified 

AMP would manage the aging effect consistent with the AMP identified in the GALL Report and 

whether the AMR was valid for the site-specific conditions.

The staff did not repeat its review of the matters described in the GALL Report for those items 

that the staff determined were bounded by the GALL Report evaluation. However, it did confirm 

that the material presented in the LRA was applicable and that the applicant identified the 

appropriate GALL Report AMRs. The staff’s evaluation is discussed below.
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AMR Results Identified as Not Applicable or Not Used

For LRA Table 3.4.1, items 3.4.1-4, 3.4.1-13, 3.4.1-17, 3.4.1-21, 3.4.1-36, 3.4.1-38, 3.4.1-41, 

3.4.1-42, 3.4.1-45, and 3.4.1-46, the applicant claimed that the corresponding AMR items in the 

GALL Report are not applicable because the associated items are only applicable to PWRs. 

The staff reviewed the SRP-LR; confirmed that these items only apply to PWRs; and finds that 

these items are not applicable to LSCS, which is a BWR.

For LRA Table 3.4.1, items 3.4.1-6, 3.4.1-7, 3.4.1-9, 3.4.1-19, 3.4.1-20, 3.4.1-22 through 

3.4.1-30, 3.4.1-32, 3.4.1-33, 3.4.1-39, 3.4.1-40, 3.4.1-43, 3.4.1-44, 3.4.1-48 through 3.4.1-52, 

3.4.1-56, 3.4.1-57, and 3.4.1-59, the applicant claimed that the corresponding items in the 

GALL Report are not applicable because the component, material, and environment 

combination described in the SRP-LR does not exist for in-scope SCs at LSCS. The staff 

reviewed the LRA and UFSAR and confirmed that the applicant’s LRA does not have any AMR 

results applicable for these items.

SER Table 3.4-1, items 3.4.1-66, 3.4.1-67, and 3.4.1-68, reflect changes to the SRP-LR 

incorporated by LR-ISG-2013-01, “Aging Management of Loss of Coating or Lining Integrity for 

Internal Coatings/Linings on In-Scope Piping, Piping Components, Heat Exchangers and 

Tanks.” The ISG added these items to manage loss of coating integrity and to allow applicants 

to credit the new GALL Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, 

Piping Components, Heat Exchangers, and Tanks,” to manage loss of material due to general, 

pitting, crevice, and microbiologically-influenced corrosion; fouling that leads to corrosion; or 

selective leaching in certain components. Because the final ISG was issued only shortly before 

the LRA was submitted, the applicant did not cite SRP-LR items 3.4.1-66, 3.4.1-67, 

and 3.4.1-68 in the LRA. The staff evaluated the corresponding items in the GALL Report and, 

based on a review of plant-specific documents during the AMP audit, determined that they are 

not applicable because the component, material, and environment combination described in the 

SRP-LR does not exist for in-scope SCs in the steam and power conversion systems at LSCS. 

Therefore, the staff finds the applicant’s approach to not cite these items acceptable.

For LRA Table 3.4.1 items discussed below, the applicant claimed that the corresponding AMR 

items in the GALL Report are not applicable. For these items, the staff reviewed sources 

beyond the LRA and UFSAR or issued one or more RAIs, or both, in order to verify the 

applicant’s claim of non-applicability.

LRA Table 3.4.1, item 3.4.1-9, addresses steel closure bolting exposed to air with steam or 

water leakage. The GALL Report recommends GALL Report AMP XI.M18, “Bolting Integrity,” to 

manage loss of material due to general corrosion for this component group. The applicant 

stated that this item is not applicable because there is no steel closure bolting exposed to air 

with steam or water leakage in the steam and power conversion system. The staff evaluated 

the applicant’s claim and notes that the possibility for the steel closure bolts in the steam and 

power conversion system to be exposed to an air with steam or water leakage environment 

during the period of extended operation cannot be eliminated. However, the staff finds that the 

steel closure bolts in the steam and power conversion system will be adequately age managed 

for loss of material due to general corrosion and finds it acceptable because of the following:

• Through LRA Table 3.4.1, item 3.4.1-8, the applicant will use the Bolting Integrity 

program to manage loss of material of all closure bolting in the steam and power 

conversion system.
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• The Bolting Integrity program conducts periodic visual inspections, which are capable of 

detecting loss of material due to general corrosion in closure bolting.

• Use of this program is consistent with GALL Report recommendations.

3.4.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation Is 

Recommended

In LRA Section 3.4.2.2, the applicant further evaluated aging management, as recommended by 

the GALL Report, for the steam and power conversion system components and provided

information concerning how it will manage the following aging effects:

• cumulative fatigue damage

• cracking due to SCC

• loss of material due to pitting and crevice corrosion

• QA for aging management of nonsafety-related components

• ongoing review of operating experience

• loss of material due to recurring internal corrosion

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 

the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.4.2.2. The staff’s review of the applicant’s 

further evaluation follows.

Cumulative Fatigue Damage

LRA Section 3.4.2.2.1 is associated with LRA Table 3.4.1, item 3.4.1-1, that addresses 

cumulative fatigue damage management for the Condenser and Air Removal, Feedwater, Main 

Steam, and Reactor Coolant Pressure Boundary systems. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that fatigue is a TLAA, as defined in 10 CFR 54.3,

“Definitions,” and is required to be evaluated in accordance with 10 CFR 54.21(c). The 

applicant stated that its evaluation of the TLAA is addressed in LRA Section 4.3.

The staff reviewed LRA Section 3.4.2.2.1 against the criteria in SRP-LR Section 3.4.2.2.1, which 

state that cumulative fatigue damage of steam and power conversion system components is a 

TLAA and that these TLAAs are to be evaluated in accordance with the TLAA acceptance 

criteria requirements of 10 CFR 54.21(c). The staff reviewed the applicant’s AMR items and 

determined that the AMR results are consistent with the recommendations of the GALL Report

and SRP-LR for managing cumulative fatigue damage.

LRA Section 3.4.2.2.1 states that TLAAs are evaluated in accordance with 10 CFR 54.21(c)(1) 

and that the evaluation of this TLAA is addressed in LRA Section 4.3. This is consistent with 

SRP-LR Section 3.4.2.2.1 and, therefore, is acceptable. The staff’s evaluation of the TLAA for 

Condenser and Air Removal, Feedwater, Main Steam, and Reactor Coolant Pressure Boundary 

systems components being managed for cumulative fatigue damage is documented in SER 

Section 4.3.
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Cracking Due to Stress Corrosion Cracking

LRA Section 3.4.2.2.2, associated with LRA Table 3.4.1, item 3.4.1-2, addresses cracking due 

to SCC in stainless steel piping, piping components, piping elements, and tanks exposed to 

outdoor air. The criteria in SRP-LR Section 3.4.2.2.2 state that cracking could occur for 

stainless steel components exposed to outdoor air environments containing sufficient halides 

and environments in which condensation or deliquescence is possible. The SRP-LR further 

states that GALL Report AMP XI.M36, “External Surfaces Monitoring of Mechanical 

Components,” is an acceptable method to manage the aging effect. The applicant addressed 

the further evaluation criteria of the SRP-LR and stated that this item is applicable to its units 

and within the scope of license renewal. The applicant also stated that it will implement the 

External Surfaces Monitoring of Mechanical Components program to manage cracking due to 

SCC of stainless steel components exposed to outdoor air in the Condensate System.

The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical

Components program is documented in SER Section 3.0.3.1.12. The staff noted that the 

applicant’s External Surfaces Monitoring of Mechanical Components program, when 

implemented, includes periodic representative inspections of components in which

condensation could occur; therefore, the program will be capable of managing the aging effect. 

In its review of the components associated with item 3.4.1-2, the staff finds that the applicant 

has met the further evaluation criteria and that the applicant’s proposal to manage the effects of 

aging using the External Surfaces Monitoring of Mechanical Components program is acceptable 

because the applicant’s program includes periodic inspections, which can detect cracking due to 

SCC.

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.4.2.2.2 criteria.

For those items associated with LRA Section 3.4.2.2.2, the staff concludes that the LRA is 

consistent with the GALL Report and that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Loss of Material Due to Pitting and Crevice Corrosion

LRA Section 3.4.2.2.3, associated with LRA Table 3.4.1, item 3.4.1-3, addresses loss of 

material due to pitting and crevice corrosion in stainless steel piping, piping components, piping 

elements, and tanks exposed to outdoor air. The criteria in SRP-LR Section 3.4.2.2.3 state that 

loss of material could occur for stainless steel components exposed to outdoor air environments 

containing sufficient halides and environments in which condensation or deliquescence is 

possible. The SRP-LR also states that GALL Report AMP XI.M36, “External Surfaces 

Monitoring of Mechanical Components,” is an acceptable method to manage the aging effect. 

The applicant addressed the further evaluation criteria of the SRP-LR and stated that this item is 

applicable to its units and within the scope of license renewal. The applicant also stated that it 

will implement the External Surfaces Monitoring of Mechanical Components program to manage 

loss of material due to pitting and crevice corrosion in stainless steel piping, piping components, 

and piping elements exposed to outdoor air in the Condensate System.

The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical

Components program is documented in SER Section 3.0.3.1.12. The staff noted that the 

applicant’s External Surfaces Monitoring of Mechanical Components program, when 
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implemented, includes periodic representative inspections of components in which

condensation could occur; therefore, the program will be capable of managing the aging effect. 

In its review of the components associated with item 3.4.1-3, the staff finds that the applicant 

has met the further evaluation criteria and that the applicant’s proposal to manage the effects of 

aging using the External Surfaces Monitoring of Mechanical Components program is acceptable 

because the applicant’s program includes periodic inspections, which can detect loss of material 

due to pitting and crevice corrosion.

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.4.2.2.3 criteria.

For those items associated with LRA Section 3.4.2.2.3, the staff concludes that the LRA is 

consistent with the GALL Report and that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program.

Ongoing Review of Operating Experience

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience of AMPs.

Loss of Material Due to Recurring Internal Corrosion

LRA Section 3.4.2.2.6, associated with LRA Table 3.4.1, item 3.4.1-61, addresses loss of 

material due to recurring internal corrosion in metallic piping, piping components, and tanks 

exposed to raw or waste water. The criteria in SRP-LR Section 3.4.2.2.6 state that AMPs may 

need to be augmented beyond the recommendations in the GALL Report if recurring internal 

corrosion is identified during searches of plant-specific operating experience conducted for the 

development of the LRA. The applicant stated that this item is not applicable because its review 

of operating experience for the steam and power conversion system did not identify instances of 

recurring internal corrosion with the threshold frequency specified in LR-ISG-2012-02. The staff 

evaluated the applicant’s claim and finds it acceptable because, as noted in the Audit Report, 

the staff conducted an independent search of the past 10 years of operating experience reports 

and did not identify repetitive occurrences of internal corrosion in the steam and power 

conversion system with a frequency greater than that given in LR-ISG-2012-02.

3.4.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.4.2-1 through 3.4.2-5, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations that are not consistent with or are not 

addressed in the GALL Report.

In LRA Tables 3.4.2-1 through 3.4.2-5, the applicant indicated, through notes F through J, that 

the combination of component type, material, environment, and AERM does not correspond to 

an item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, note F indicates that the material for the AMR item

component is not evaluated in the GALL Report. Note G indicates that the environment for the 
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AMR item component and material is not evaluated in the GALL Report. Note H indicates that 

the aging effect for the AMR item component, material, and environment combination is not 

evaluated in the GALL Report. Note I indicates that the aging effect identified in the 

GALL Report for the item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the item is evaluated in the GALL Report.

For component type, material, and environment combinations that are not evaluated in the 

GALL Report, the staff reviewed the applicant’s evaluation to determine whether the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections.

Condensate System—Summary of Aging Management Review – LRA Table 3.4.2-1

The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMR evaluations for the 

Condensate System component groups.

Aluminum Alloy Tanks and Piping Exposed to Outdoor Air, Condensation, Concrete, and Soil. 

In LRA Table 3.4.2-1, the applicant stated that, for aluminum alloy tanks and piping exposed to 

outdoor air, condensation, concrete, and soil, cracking is not applicable and that no AMP is 

proposed. The AMR items cite generic note I. The AMR items also cite plant-specific note 3, 

which states that the associated aluminum alloys are not susceptible to cracking due to SCC. 

The plant-specific note states that the alloys of construction are not susceptible to SCC based 

on their elemental composition, and references EPRI Report 1010639, Revision 4, dated 

January 2006 as the technical basis.

The staff reviewed the associated items 3.4.1-31 and 3.4.1-63 in the LRA and confirmed that 

the aging effect of cracking due to SCC is not applicable for this component, material, and 

environment combination. The staff notes that AMR items 3.4.1-31 and 3.4.1-63 also manage 

loss of material using the Aboveground Metallic Tanks program and the External Surfaces 

Monitoring of Mechanical Components program, respectively. The staff’s evaluation of the 

External Surfaces Monitoring of Mechanical Components program and the Aboveground 

Metallic Tanks program is documented in SER Sections 3.0.3.1.12 and 3.0.3.2.11, respectively. 

The latter includes the staff’s basis for concluding that cracking due to SCC is not an AERM for 

the associated aluminum alloys. 

Condenser and Air Removal System – Summary of Aging Management Review –

LRA Table 3.4.2-2

The staff reviewed LRA Table 3.4.2-2, which summarizes the results of AMR evaluations for the 

Condenser and Air Removal System component groups. The staff’s review did not identify any 

AMR items with notes F through J, indicating that the combinations of component type, material,

environment, and AERM for the Condenser and Air Removal System component groups are 

consistent with the GALL Report.

Feedwater System – Summary of Aging Management Review – LRA Table 3.4.2-3

The staff reviewed LRA Table 3.4.2-3, which summarizes the results of AMR evaluations for the 

Feedwater System component groups. The staff’s review did not identify any AMR items with 
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notes F through J, indicating that the combinations of component type, material, environment, 

and AERM for the Feedwater System component groups are consistent with the GALL Report.

Main Steam System – Summary of Aging Management Review – LRA Table 3.4.2-4

The staff reviewed LRA Table 3.4.2-4, which summarizes the results of AMR evaluations for the 

Main Steam System component groups. The staff’s review did not identify any AMR items with 

notes F through J, indicating that the combinations of component type, material, environment, 

and AERM for the Main Steam System component groups are consistent with the GALL Report.

Main Turbine and Auxiliaries System – Summary of Aging Management Review –

LRA Table 3.4.2-5

The staff reviewed LRA Table 3.4.2-5, which summarizes the results of AMR evaluations for the

Main Turbine and Auxiliaries System component groups. The staff’s review did not identify any 

AMR items with notes F through J, indicating that the combinations of component type, material,

environment, and AERM for the Main Turbine and Auxiliaries System component groups are 

consistent with the GALL Report.

3.4.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the steam and power conversion system components within the scope of 

license renewal and subject to an AMR will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

3.5 Aging Management of Structures and Component Supports

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

Structures and Component Supports components and commodity groups of the following:

• Auxiliary Building

• Component Supports Commodity Group

• Cooling Lake

• Diesel Generator Building

• Lake Screen House

• Offgas Building

• Primary Containment

• Radwaste Building

• Reactor Building

• Structural Commodity Group

• Switchyard Structures

• Tank Foundations and Dikes

• Turbine Building

• Yard Structures

The GALL Report organizes safety-related and other structures (other than containments), such 

as those listed above, into nine groups. These nine groups, which are referenced in the LRA 
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and staff’s evaluation as Groups 1 through 9 Structures, are generically defined in GALL Report

Chapter III.A.

3.5.1 Summary of Technical Information in the Application

LRA Section 3.5 provides AMR results for the structures and component supports components 

and component groups. LRA Table 3.5.1, “Summary of Aging Management Evaluations for the 

Structures and Component Supports,” is a summary comparison of the applicant’s AMRs with 

those evaluated in the GALL Report for the structures and component supports components 

and component groups.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report.

3.5.2 Staff Evaluation

The staff reviewed LRA Section 3.5 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the structures and component supports

components within the scope of license renewal and subject to an AMR will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

The staff conducted a review of the applicant’s AMRs to verify the applicant’s claim that certain 

AMRs are consistent with the GALL Report or are not applicable. The staff did not repeat its 

review of the matters described in the GALL Report; however, the staff did verify that the 

material presented in the LRA is applicable and that the applicant identified the appropriate 

GALL Report AMRs. AMRs that the staff confirmed are consistent with the GALL Report are 

noted as such in Table 3.5-1; therefore, no further discussion is required. AMRs that the staff 

confirmed are not applicable to LSCS or require no aging management are noted in Table 3.5-1 

and discussed in SER Section 3.5.2.1.1. Details of the staff’s evaluation of AMRs that the 

applicant claimed are consistent with the GALL Report, but for which a different AMP from the 

program recommended in the GALL Report is used to manage aging, and AMRs for which the 

staff requested additional information, are documented in SER Sections 3.5.2.1.2 

through 3.5.2.1.6.

During its review, the staff also reviewed AMRs consistent with the GALL Report and those for 

which further evaluation is recommended. The staff confirmed that the applicant’s further 

evaluations are consistent with the SRP-LR Section 3.5.2.2 acceptance criteria. The staff’s 

evaluations of AMRs for which the GALL Report recommends further evaluation are 

documented in SER Section 3.5.2.2.

The staff also conducted a technical review of the remaining AMRs that are not consistent with 

or are not addressed in the GALL Report. The technical review evaluated whether all plausible 

aging effects have been identified and whether the aging effects listed are appropriate for the 

material-environment combinations specified. The staff’s evaluations of AMRs that are not 

consistent with or are not addressed in the GALL Report are documented in SER 

Section 3.5.2.3.
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Table 3.5-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.5 and addressed in the GALL Report.

Staff Evaluation for Structures and Component Supports Components in the 

GALL Report

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Concrete: dome; 

wall; basemat; ring 

girders; buttresses, 

concrete elements, 

all (3.5.1-1)

Cracking and 

distortion due to 

increased stress 

levels from 

settlement

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL” or 

Chapter XI.S6, 

“Structure 

Monitoring” If a 

de-watering system 

is relied upon for 

control of settlement, 

then the licensee is 

to ensure proper 

functioning of the 

de-watering system 

through the period of 

extended operation.

Yes, if a 

de-watering 

system is 

relied upon to 

control 

settlement 

Structures 

Monitoring, and

ASME Section 

XI, Subsection 

IWL

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.1)

Concrete: 

foundation; 

subfoundation 

(3.5.1-2)

Reduction of 

foundation 

strength and 

cracking due to 

differential 

settlement and 

erosion of 

porous concrete 

subfoundation

Chapter XI.S6, 

“Structures 

Monitoring” If a 

de-watering system 

is relied upon for 

control of erosion, 

then the licensee is 

to ensure proper 

functioning of the 

de-watering system 

through the period of 

extended operation.

Yes, if a 

de-watering 

system is 

relied upon to 

control 

settlement 

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.2.1)

Concrete: dome; 

wall; basemat; ring 

girders; buttresses; 

Concrete: 

containment; wall; 

basemat; Concrete: 

basemat, concrete 

fill-in annulus 

(3.5.1-3)

Reduction of 

strength and 

modulus due to 

elevated 

temperature 

(>150°F 

general; >200°F 

local)

A plant-specific 

aging management 

program is to be 

evaluated.

Yes, if 

temperature 

limits are 

exceeded 

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.2.1)

Steel elements 

(inaccessible areas): 

drywell shell; drywell 

head; and drywell 

shell (3.5.1-4)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

Yes, if 

corrosion is 

indicated from 

the IWE 

examinations

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.2.1)
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Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel elements 

(inaccessible areas): 

liner; liner anchors; 

integral attachments; 

Steel elements 

(inaccessible areas): 

suppression 

chamber; drywell; 

drywell head; 

embedded shell; 

region shielded by 

diaphragm floor (as 

applicable) (3.5.1-5)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

Yes, if 

corrosion is 

indicated from 

the IWE 

examinations 

ASME Section 

XI, Subsection 

IWE, and

10 CFR Part 50, 

Appendix J

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.1)

Steel elements: 

torus shell (3.5.1-6)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

Yes, if 

corrosion is 

significant.

Recoating of 

the torus is 

recommended

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.2.1)

Steel elements: 

torus ring girders; 

downcomers; Steel 

elements: 

suppression 

chamber shell 

(interior surface) 

(3.5.1-7)

Loss of material 

due to general, 

pitting, and

crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

Yes, if 

corrosion is 

significant 

Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.2.1)

Pre-stressing 

system: tendons 

(3.5.1-8)

Loss of 

prestress due to 

relaxation; 

shrinkage;

creep; elevated 

temperature

Yes, TLAA Yes TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.1)

Penetration sleeves; 

penetration bellows 

Steel elements: 

torus; vent line; vent 

header; vent line 

bellows; 

downcomers, 

suppression pool 

shell; unbraced 

downcomers, Steel 

elements: vent 

header; downcomers 

(3.5.1-9)

Cumulative 

fatigue damage 

due to fatigue 

(Only if CLB 

fatigue analysis 

exists)

Yes, TLAA Yes TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.1)

Penetration sleeves; 

penetration bellows 

(3.5.1-10)

Cracking due to 

stress corrosion 

cracking

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.2.1)
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Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Concrete 

(inaccessible areas): 

dome; wall; 

basemat; ring 

girders; buttresses, 

Concrete 

(inaccessible areas): 

basemat, Concrete 

(inaccessible areas): 

dome; wall; basemat 

(3.5.1-11)

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Further evaluation is 

needed for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering index 

>100 day-inch/yr) 

(NUREG-1557). 

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.2.1)

Concrete 

(inaccessible areas): 

dome; wall; 

basemat; ring 

girders; buttresses, 

Concrete 

(inaccessible areas): 

basemat, Concrete 

(inaccessible areas): 

containment; wall; 

basemat, Concrete 

(inaccessible areas): 

basemat, concrete 

fill-in annulus 

(3.5.1-12)

Cracking due to 

expansion from 

reaction with 

aggregates

Further evaluation is 

required to 

determine if a plantspecific aging 

management 

program is needed. 

Yes Structures 

Monitoring, and

ASME 

Section XI, 

Subsection IWL

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.1)

Concrete 

(inaccessible areas): 

basemat, Concrete 

(inaccessible areas): 

dome; wall; basemat 

(3.5.1-13)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Further evaluation is 

required to 

determine if a plantspecific aging 

management 

program is needed. 

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.2.1)

Concrete 

(inaccessible areas): 

dome; wall; 

basemat; ring 

girders; buttresses, 

Concrete 

(inaccessible areas): 

containment; wall; 

basemat (3.5.1-14)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Further evaluation is 

required to 

determine if a plantspecific aging 

management 

program is needed. 

Yes Structures 

Monitoring

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.1)

Concrete (accessible 

areas): basemat 

(3.5.1-15)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)
3-310

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Concrete (accessible 

areas): basemat, 

Concrete: 

containment; wall; 

basemat (3.5.1-16)

Increase in 

porosity and 

permeability; 

cracking; loss of 

material 

(spalling, 

scaling) due to 

aggressive 

chemical attack

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)

Concrete (accessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses 

(3.5.1-17)

Increase in 

porosity and 

permeability; 

cracking; loss of 

material 

(spalling, 

scaling) due to 

aggressive 

chemical attack

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)

Concrete (accessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses, 

Concrete (accessible 

areas): basemat 

(3.5.1-18)

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No Not Applicable Not Applicable to 

LSCS (see SER

Section 3.5.2.1.1)

Concrete (accessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses, 

Concrete (accessible 

areas): basemat, 

Concrete (accessible 

areas): containment; 

wall; basemat, 

Concrete (accessible 

areas): basemat, 

concrete fill-in 

annulus (3.5.1-19)

Cracking due to 

expansion from 

reaction with 

aggregates

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No ASME Section 

XI, Subsection 

IWL

Consistent with the 

GALL Report

Concrete (accessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses, 

Concrete (accessible 

areas): containment; 

wall; basemat 

(3.5.1-20)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No ASME Section 

XI, Subsection 

IWL

Consistent with the 

GALL Report
3-311

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Concrete (accessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses; 

reinforcing steel, 

Concrete (accessible 

areas): basemat; 

reinforcing steel, 

Concrete (accessible 

areas): dome; wall; 

basemat; reinforcing 

steel (3.5.1-21)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) due to 

corrosion of 

embedded steel

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No ASME Section 

XI, Subsection 

IWL

Consistent with the 

GALL Report

Concrete 

(inaccessible areas): 

basemat; reinforcing 

steel (3.5.1-22)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) due to 

corrosion of 

embedded steel

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Concrete 

(inaccessible areas): 

basemat; reinforcing 

steel, Concrete 

(inaccessible areas): 

dome; wall; 

basemat; reinforcing 

steel (3.5.1-23)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) due to 

corrosion of 

embedded steel

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)

Concrete 

(inaccessible areas): 

dome; wall; 

basemat; ring 

girders; buttresses, 

Concrete 

(inaccessible areas): 

basemat, Concrete 

(accessible areas): 

dome; wall; basemat 

(3.5.1-24)

Increase in 

porosity and 

permeability; 

cracking; loss of 

material 

(spalling, 

scaling) due to 

aggressive 

chemical attack

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Concrete 

(inaccessible areas): 

dome; wall; 

basemat; ring 

girders; buttresses; 

reinforcing steel 

(3.5.1-25)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) due to 

corrosion of 

embedded steel

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No Not Applicable 

(PWRs only)

Not Applicable to 

BWRs (see SER 

Section 3.5.2.1.1)

Moisture barriers 

(caulking, flashing, 

and other sealants) 

(3.5.1-26)

Loss of sealing 

due to wear, 

damage, 

erosion, tear, 

surface cracks, 

or other defects

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)
3-312

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Penetration sleeves; 

penetration bellows, 

Steel elements: 

torus; vent line; vent 

header; vent line 

bellows; 

downcomers, 

suppression pool 

shell (3.5.1-27)

Cracking due to 

cyclic loading 

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)

Personnel airlock, 

equipment hatch, 

CRD hatch 

(3.5.1-28)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No 10 CFR Part 50, 

Appendix J, and 

ASME Section 

XI, Subsection 

IWE

Consistent with the 

GALL Report

Personnel airlock, 

equipment hatch, 

CRD hatch: locks, 

hinges, and closure 

mechanisms 

(3.5.1-29)

Loss of leak 

tightness due to 

mechanical 

wear of locks, 

hinges and 

closure 

mechanisms

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No 10 CFR Part 50, 

Appendix J, and 

ASME Section 

XI, Subsection 

IWE

Consistent with the 

GALL Report

Pressure-retaining 

bolting (3.5.1-30)

Loss of preload 

due to selfloosening

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No 10 CFR Part 50, 

Appendix J, and 

ASME Section 

XI, Subsection 

IWE

Consistent with the 

GALL Report

Pressure-retaining 

bolting, Steel 

elements: 

downcomer pipes 

(3.5.1-31)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

No ASME Section 

XI, Subsection

IWE

Consistent with the 

GALL Report

Prestressing system: 

tendons; anchorage 

components 

(3.5.1-32)

Loss of material 

due to corrosion

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No ASME Section 

XI, Subsection 

IWL

Consistent with the 

GALL Report

Seals and gaskets 

(3.5.1-33)

Loss of sealing 

due to wear, 

damage, 

erosion, tear, 

surface cracks, 

or other defects

Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J “

No 10 CFR Part 50, 

Appendix J

Consistent with the 

GALL Report

Service Level I 

coatings (3.5.1-34)

Loss of coating 

integrity due to 

blistering, 

cracking, 

flaking, peeling, 

delamination, 

rusting, or 

physical 

damage

Chapter XI.S8, 

“Protective Coating 

Monitoring and 

Maintenance”

No Protective 

Coating 

Monitoring and 

Maintenance 

Program

Consistent with the 

GALL Report
3-313

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel elements 

(accessible areas): 

liner; liner anchors; 

integral attachments, 

Penetration sleeves, 

Steel elements 

(accessible areas): 

drywell shell; drywell 

head; drywell shell in 

sand pocket 

regions;, Steel 

elements (accessible 

areas): suppression 

chamber; drywell; 

drywell head; 

embedded shell; 

region shielded by 

diaphragm floor (as 

applicable), Steel 

elements (accessible 

areas): drywell shell; 

drywell head 

(3.5.1-35)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No 10 CFR Part 50, 

Appendix J, and 

ASME Section 

XI, Subsection 

IWE

Consistent with the 

GALL Report

Steel elements: 

drywell head; 

downcomers 

(3.5.1-36)

Fretting or 

lockup due to 

mechanical 

wear

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

No ASME Section 

XI, Subsection 

IWE

Consistent with the 

GALL Report

Steel elements: 

suppression 

chamber (torus) liner 

(interior surface) 

(3.5.1-37)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No 10 CFR Part 50, 

Appendix J, 

ASME Section 

XI, Subsection 

IWE, and 

Structures 

Monitoring

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.2)

Steel elements: 

suppression 

chamber shell 

(interior surface) 

(3.5.1-38)

Cracking due to 

stress corrosion 

cracking

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)

Steel elements: vent 

line bellows 

(3.5.1-39)

Cracking due to 

stress corrosion 

cracking

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)

Unbraced 

downcomers, Steel 

elements: vent 

header; downcomers 

(3.5.1-40)

Cracking due to 

cyclic loading 

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)
3-314

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel elements: 

drywell support skirt, 

Steel elements 

(inaccessible areas): 

support skirt 

(3.5.1-41)

None None NA - No AEM 

or AMP

Consistent with 

the 

GALL Report

Consistent with the 

GALL Report

Groups 1-3, 5, 7-9:

concrete 

(inaccessible areas): 

foundation (3.5.1-42)

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Further evaluation is 

required for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering index 

>100 day-inch/yr) 

(NUREG-1557)

Yes Structures 

Monitoring

Consistent with the 

GALL Report (see 

SER Section 

3.5.2.2.2)

All Groups except 

Group 6: concrete 

(inaccessible areas): 

all (3.5.1-43)

Cracking due to 

expansion from 

reaction with 

aggregates

Further evaluation is 

required to 

determine if a plantspecific aging 

management 

program is needed.

Yes Structures 

Monitoring

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2)

All Groups: concrete: 

all (3.5.1-44)

Cracking and 

distortion due to 

increased stress 

levels from 

settlement

Chapter XI.S6, 

“Structures 

Monitoring” If a 

de-watering system 

is relied upon for 

control of settlement, 

then the licensee is 

to ensure proper 

functioning of the dewatering system 

through the period of 

extended operation.

Yes Structures 

Monitoring

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2)

Groups 1-3, 5-9: 

concrete: foundation; 

subfoundation 

(3.5.1-45)

Reduction in 

foundation 

strength, 

cracking due to 

differential 

settlement, 

erosion of 

porous concrete 

subfoundation

Chapter XI.S6, 

“Structures 

Monitoring” If a 

de-watering system 

is relied upon for 

control of settlement, 

then the licensee is 

to ensure proper 

functioning of the dewatering system 

through the period of 

extended operation.

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.2.2)
3-315

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Groups 1-3, 5-9: 

concrete: foundation; 

subfoundation 

(3.5.1-46)

Reduction of 

foundation 

strength and 

cracking due to 

differential 

settlement and 

erosion of 

porous concrete 

subfoundation

Chapter XI.S6,

“Structures 

Monitoring” If a dewatering system is 

relied upon for 

control of settlement, 

then the licensee is 

to ensure proper 

functioning of the dewatering system 

through the period of 

extended operation.

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.2.2)

Groups 1-5, 7-9: 

concrete 

(inaccessible areas): 

exterior above- and 

below-grade; 

foundation (3.5.1-47)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Further evaluation is 

required to 

determine if a plantspecific aging 

management 

program is needed.

Yes, Structures 

Monitoring

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2)

Groups 1-5: 

concrete: all 

(3.5.1-48)

Reduction of 

strength and 

modulus due to 

elevated 

temperature 

(>150°F 

general; >200°F 

local)

A plant-specific 

aging management 

program is to be 

evaluated.

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.2.2)

Groups 6 - concrete 

(inaccessible areas): 

exterior above- and 

below-grade; 

foundation; interior 

slab (3.5.1-49)

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Further evaluation is 

required for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering index 

>100 day-inch/yr) 

(NUREG-1557)

Yes RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2)

Groups 6: concrete 

(inaccessible areas): 

all (3.5.1-50)

Cracking due to 

expansion from 

reaction with 

aggregates

Further evaluation is 

required to 

determine if a plantspecific aging 

management 

program is needed.

Yes RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants, and 

Structures 

Monitoring

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2)

Groups 6: concrete 

(inaccessible areas): 

exterior above- and 

below-grade; 

foundation; interior 

slab (3.5.1-51)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Further evaluation is 

required to 

determine if a plantspecific aging 

management 

program is needed.

Yes Structures 

Monitoring

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2)
3-316

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Groups 7, 8 - steel 

components: tank 

liner (3.5.1-52)

Cracking due to 

stress corrosion 

cracking; Loss 

of material due 

to pitting and 

crevice 

corrosion

A plant-specific 

aging management 

program is to be 

evaluated.

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.2.2)

Support members; 

welds; bolted 

connections; support

anchorage to 

building structure 

(3.5.1-53)

Cumulative 

fatigue damage 

due to fatigue 

(Only if CLB 

fatigue analysis 

exists)

Yes, TLAA Yes, Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.2.2)

All groups except 6: 

concrete (accessible 

areas): all (3.5.1-54)

Cracking due to 

expansion from 

reaction with 

aggregates

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Building concrete at 

locations of 

expansion and 

grouted anchors; 

grout pads for 

support base plates 

(3.5.1-55)

Reduction in 

concrete anchor 

capacity due to 

local concrete 

degradation/ 

service-induced 

cracking or 

other concrete 

aging 

mechanisms

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Concrete: exterior 

above- and belowgrade; foundation; 

interior slab 

(3.5.1-56)

Loss of material 

due to abrasion; 

cavitation

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report

Constant and 

variable load spring 

hangers; guides; 

stops (3.5.1-57)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

overload, 

fatigue due to 

vibratory and 

cyclic thermal 

loads

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No ASME Section 

XI, Subsection 

IWF

Consistent with the 

GALL Report
3-317

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Earthen watercontrol structures: 

dams; 

embankments; 

reservoirs; channels; 

canals and ponds 

(3.5.1-58)

Loss of material; 

loss of form due 

to erosion, 

settlement, 

sedimentation, 

frost action, 

waves, currents, 

surface runoff, 

seepage

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report

Group 6: concrete 

(accessible areas): 

all (3.5.1-59)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) due to 

corrosion of 

embedded steel

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report

Group 6: concrete 

(accessible areas): 

exterior above- and 

below-grade; 

foundation (3.5.1-60)

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report

Group 6: concrete 

(accessible areas): 

exterior above- and 

below-grade; 

foundation; interior 

slab (3.5.1-61)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report
3-318

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Group 6: wooden 

piles; sheeting 

(3.5.1-62)

Loss of material; 

change in 

material 

properties due 

to weathering, 

chemical 

degradation, 

and insect 

infestation 

repeated 

wetting and 

drying, fungal 

decay

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)

Groups 1-3, 5, 7-9: 

concrete (accessible 

areas): exterior 

above- and belowgrade; foundation 

(3.5.1-63)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Groups 1-3, 5, 7-9: 

concrete (accessible 

areas): exterior 

above- and belowgrade; foundation 

(3.5.1-64)

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Groups 1-3, 5, 7-9: 

concrete 

(inaccessible areas): 

below-grade 

exterior; foundation, 

Groups 1-3, 5, 7-9: 

concrete (accessible 

areas): below-grade 

exterior; foundation, 

Groups 6: concrete 

(inaccessible areas): 

all (3.5.1-65)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) due to 

corrosion of 

embedded steel

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Groups 1-5, 7, 9: 

concrete (accessible 

areas): interior and 

above-grade exterior 

(3.5.1-66)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) due to 

corrosion of 

embedded steel

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report
3-319

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Groups 1-5, 7, 9: 

concrete: interior; 

above-grade 

exterior, Groups 1-3, 

5, 7-9 - concrete 

(inaccessible areas): 

below-grade 

exterior; foundation, 

Group 6: concrete 

(inaccessible areas): 

all (3.5.1-67)

Increase in 

porosity and 

permeability; 

cracking; loss of 

material 

(spalling, 

scaling) due to 

aggressive 

chemical attack

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

High-strength 

structural bolting 

(3.5.1-68)

Cracking due to 

stress corrosion 

cracking

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)

High-strength 

structural bolting 

(3.5.1-69)

Cracking due to 

stress corrosion 

cracking

Chapter XI.S6, 

“Structures 

Monitoring” Note: 

ASTM A 325, F 

1852, and ASTM A 

490 bolts used in 

civil structures have 

not shown to be 

prone to SCC. SCC 

potential need not be 

evaluated for these 

bolts.

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)

Masonry walls: all 

(3.5.1-70)

Cracking due to 

restraint 

shrinkage, 

creep, and 

aggressive 

environment

Chapter XI.S5, 

“Masonry Walls”

No Masonry Walls, 

and

Structures 

Monitoring

Consistent with the 

GALL Report

Masonry walls: all 

(3.5.1-71)

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Chapter XI.S5, 

“Masonry Walls”

No Masonry Walls, 

and 

Structures 

Monitoring

Consistent with the 

GALL Report

Seals; gasket; 

moisture barriers 

(caulking, flashing, 

and other sealants) 

(3.5.1-72)

Loss of sealing 

due to 

deterioration of 

seals, gaskets, 

and moisture 

barriers 

(caulking, 

flashing, and 

other sealants)

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring,

Aboveground 

Metallic Tanks, 

and 

ASME Section 

XI, Subsection 

IWL

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.3)

Service Level I 

coatings (3.5.1-73)

Loss of coating 

integrity due to 

blistering, 

cracking, 

flaking, peeling, 

delamination, 

rusting, or 

physical 

damage

Chapter XI.S8, 

“Protective Coating 

Monitoring and 

Maintenance”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)
3-320

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Sliding support 

bearings; sliding 

support surfaces 

(3.5.1-74)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

debris, 

overload, wear

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Sliding surfaces 

(3.5.1-75)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

debris, 

overload, wear

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No ASME Section 

XI, Subsection 

IWF

Consistent with the 

GALL Report

Sliding surfaces: 

radial beam seats in 

BWR drywell 

(3.5.1-76)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

overload, wear

Chapter XI.S6, 

“Structures 

Monitoring”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)

Steel components: 

all structural steel 

(3.5.1-77)

Loss of material 

due to corrosion

Chapter XI.S6, 

“Structures 

Monitoring” If 

protective coatings 

are relied upon to 

manage the effects 

of aging, the 

structures monitoring 

program is to include 

provisions to 

address protective 

coating monitoring 

and maintenance.

No Structures 

Monitoring

Consistent with the 

GALL Report

Steel components: 

fuel pool liner 

(3.5.1-78)

Cracking due to 

stress corrosion 

cracking; Loss 

of material due 

to pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Monitoring of 

the spent fuel pool 

water level in 

accordance with 

technical 

specifications and 

leakage from the 

leak chase channels.

No, unless 

leakages have 

been detected 

through the 

SFP liner that 

cannot be 

accounted for 

from the leak 

chase 

channels

Water 

Chemistry

An exception 

applies to the 

Water 

Chemistry 

program

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.4)

Steel components: 

piles (3.5.1-79)

Loss of material 

due to corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report
3-321

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Structural bolting 

(3.5.1-80)

Loss of material 

due to general, 

pitting and 

crevice 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring, 

Inspection of 

Overhead 

Heavy and Light 

Load (Related 

to Refueling) 

Handling 

Systems, and 

ASME Section 

XI, Subsection 

IWL

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.2)

Structural bolting 

(3.5.1-81)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No ASME Section 

XI, Subsection 

IWF

Consistent with the 

GALL Report

Structural bolting 

(3.5.1-82)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Structural bolting 

(3.5.1-83)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report

Structural bolting 

(3.5.1-84)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)
3-322

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Structural bolting 

(3.5.1-85)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

for BWR water, and 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No ASME Section 

XI, Subsection 

IWF,

Water 

Chemistry,

Inspection of 

Overhead 

Heavy and Light 

Load (Related 

to Refueling) 

Handling 

Systems

An exception 

applies to the 

Water 

Chemistry 

program

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.5)

Structural bolting 

(3.5.1-86)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)

Structural bolting

(3.5.1-87)

Loss of preload 

due to selfloosening

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No ASME Section 

XI, Subsection 

IWF

Consistent with the 

GALL Report

Structural bolting 

(3.5.1-88)

Loss of preload 

due to selfloosening

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring,

Inspection of 

Overhead 

Heavy and Light 

Load (Related 

to Refueling) 

Handling 

Systems, and

ASME Section 

XI, Subsection 

IWL

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.6)

Support members; 

welds; bolted 

connections; support 

anchorage to 

building structure 

(3.5.1-89)

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Not Applicable 

(PWR only)

Not Applicable to 

BWRs (see SER 

Section 3.5.2.1.1)

Support members; 

welds; bolted 

connections; support 

anchorage to 

building structure 

(3.5.1-90)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

for BWR water, and 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No ASME Section 

XI, Subsection 

IWF, and 

Water 

Chemistry

An exception 

applies to the 

Water 

Chemistry 

program

Consistent with the 

GALL Report
3-323

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Support members; 

welds; bolted 

connections; support 

anchorage to 

building structure 

(3.5.1-91)

Loss of material 

due to general 

and pitting 

corrosion

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No ASME Section 

XI, Subsection 

IWF

Consistent with the 

GALL Report

Support members; 

welds; bolted 

connections; support 

anchorage to 

building structure 

(3.5.1-92)

Loss of material

due to general 

and pitting 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Support members; 

welds; bolted 

connections; support 

anchorage to 

building structure 

(3.5.1-93)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring, and 

Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.5)

Vibration isolation 

elements (3.5.1-94)

Reduction or 

loss of isolation 

function due to 

radiation 

hardening, 

temperature, 

humidity, 

sustained 

vibratory loading

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.5.2.1.1)

Aluminum, 

galvanized steel and 

stainless steel 

Support members; 

welds; bolted 

connections; support 

anchorage to 

building structure 

exposed to air –

indoor, uncontrolled 

(3.5.1-95)

None None NA - No AEM 

or AMP

Consistent with 

the 

GALL Report

Consistent with the 

GALL Report

3.5.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.5.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the Structures and Component Supports components:

• 10 CFR Part 50, Appendix J

• Aboveground Metallic Tanks

• ASME Section XI, Subsection IWE

• ASME Section XI, Subsection IWF

• ASME Section XI, Subsection IWL

• External Surfaces Monitoring of Mechanical Components

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

• Masonry Walls
3-324

• One-Time Inspection

• Protective Coating Monitoring and Maintenance Program

• RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants

• Structures Monitoring

• TLAA

• Water Chemistry

LRA Tables 3.5.2-1 through 3.5.2-14 summarize the AMR results for the Structures and 

Component Supports components and indicate AMRs claimed to be consistent with the 

GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components in these 

GALL Report component groups were bounded by the GALL Report evaluation. The applicant 

provided a note for each AMR item. The notes describe how the information in the tables aligns 

with the information in the GALL Report. The staff audited those AMRs with Notes A through E, 

which indicate how the AMR was consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these AMR items to confirm consistency with the GALL Report and the validity 

of the AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff audited these AMR items to confirm consistency with 

the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to 

the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant 

was consistent with the AMP identified in the GALL Report and whether the AMR was valid for 

the site-specific conditions.

Note C indicates that the component for the AMR item, although different from that in the 

GALL Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP is consistent with the AMP identified by the GALL Report. Note C indicates 

that the applicant was unable to find a listing of some system components in the GALL Report; 

however, the applicant identified a different component in the GALL Report that had the same 

material, environment, aging effect, and AMP as those of the component under review. The 

staff audited these AMR items to confirm consistency with the GALL Report. The staff also 

determined whether the AMR item of the different component applied to the component under 

review and whether the AMR was valid for the site-specific conditions.

Note D indicates that the component for the AMR item, although different from that in the 

GALL Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff 

audited these AMR items to confirm consistency with the GALL Report and confirmed whether 

the AMR item of the different component was applicable to the component under review. The 

staff confirmed whether it had reviewed and accepted the exceptions to the GALL Report AMPs. 

The staff also determined whether the AMP identified by the applicant was consistent with the 

AMP identified in the GALL Report and whether the AMR was valid for the site-specific 

conditions.
3-325

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect; however, a different AMP is credited. The staff audited these 

AMR items to confirm consistency with the GALL Report and determined whether the identified 

AMP would manage the aging effect consistent with the AMP identified in the GALL Report and 

whether the AMR was valid for the site-specific conditions.

The staff did not repeat its review of the matters described in the GALL Report; however, it did 

confirm that the material presented in the LRA was applicable and that the applicant identified 

the appropriate GALL Report AMRs. The staff’s evaluation is discussed below.

AMR Results Identified as Not Applicable or Not Used

For LRA Table 3.5.1, items 3.5.1-25 and 3.5.1-89, the applicant claimed that the corresponding 

AMR items in the GALL Report are not applicable because the associated items are only 

applicable to PWRs. The staff reviewed the SRP-LR; confirmed that these items only apply to 

PWRs; and finds that these items are not applicable to LSCS, which is a BWR.

For LRA Table 3.5.1, items 3.5.1-15 through 3.5.1-18, 3.5.1-23, 3.5.1-26, 3.5.1-27, 3.5.1-38 

through 3.5.1-40, 3.5.1-62, 3.5.1-68, 3.5.1-69, 3.5.1-73, 3.5.1-76, 3.5.1-84, 3.5.1-86, 

and 3.5.1-94, the applicant claimed that the corresponding items in the GALL Report are not 

applicable because the component, material, and environment combination described in the 

SRP-LR does not exist for in-scope SCs at LSCS. The staff reviewed the LRA and UFSAR and 

confirmed that the applicant’s LRA does not have any AMR results applicable for these items.

For LRA Table 3.5.1 items discussed below, the applicant claimed that the corresponding AMR 

items in the GALL Report are not applicable. For these items, the staff reviewed sources 

beyond the LRA and UFSAR or issued one or more RAIs, or both, in order to verify the 

applicant’s claim of non-applicability.

LRA Table 3.5.1, item 3.5.1-16, addresses accessible concrete exposed to uncontrolled indoor 

air or outdoor air. The GALL Report recommends GALL Report AMP XI.S2, “ASME Section XI, 

Subsection IWL,” or AMP XI.S6, “Structures Monitoring,” to manage increases in porosity and 

permeability, cracking, or loss of material due to aggressive chemical attack for this component 

group. The applicant stated that this item is not applicable because the Primary Containment is 

completely enclosed and is not exposed to an outdoor air environment. In addition, the indoor 

environment lacks aggressive chemicals that could contact the concrete. The staff evaluated 

the applicant’s claim and noted that the indoor environment reduces the likelihood of this aging 

effect, but it does not agree that the indoor environment completely eliminates the possibility of 

the aging effect occurring. However, the staff also noted that this concrete is included within the 

applicant’s ASME Section XI, Subsection IWL program, which conducts appropriate inspections 

for identifying this aging effect if it were to occur. Therefore, the staff finds this item acceptable 

because the environment reduces the chances of this aging effect occurring and because the 

concrete is within the scope of an AMP that would identify the aging effect if it were to occur.

LRA Table 3.5.1, item 3.5.1-27, addresses steel, stainless steel, and dissimilar metal welds 

exposed to air-indoor, uncontrolled, or treated water. The GALL Report recommends 

GALL Report AMP XI.S1, “ASME Section XI, Subsection IWE,” and AMP XI.S4, 

“10 CFR Part 50, Appendix J,” to manage cracking due to cyclic loading for components for 

which a CLB fatigue analysis does not exist. The applicant stated that this item is not applicable 

because LSCS does have a CLB fatigue analysis associated with penetration sleeves and 

downcomers; therefore, this aging effect and mechanism is addressed under item 3.5.1-9. The 
3-326

staff evaluated the applicant’s claim and finds it acceptable because this item only applies to 

components that do not have a fatigue-based analysis in the CLB. The applicant addresses the 

containment liner and penetration sleeve, refueling bellows, and downcomers (i.e., components 

that have a fatigue analysis in the CLB) as a TLAA. The staff’s evaluation of the TLAA to 

address these components is documented in SER Section 4.6.

LRA Table 3.5.1, item 3.5.1-36, addresses the steel elements of the drywell head and the 

downcomers exposed to an uncontrolled indoor air environment. The GALL Report

recommends GALL Report AMP XI.S1, “ASME Section XI, Subsection IWE,” to manage fretting 

or lockup due to mechanical wear for this component group. The applicant stated that this item 

will be managed by the ASME Section XI, Subsection IWE program for the steel elements of the 

drywell head, which aligns with the GALL recommendation. The applicant further stated that the 

portion of the item associated with the downcomers does not apply to the LSCS Mark II 

containment design. The staff evaluated the applicant’s claim and finds it acceptable because 

the LSCS downcomers are stainless steel, whereas the GALL Report items only apply to steel 

components, and the downcomers are anchored in the drywell floor, which prevents relative 

motion and precludes mechanical wear.

LRA Table 3.5.1, item 3.5.1-38, addresses the stainless steel suppression chamber liner 

exposed to an uncontrolled indoor air environment. The GALL Report recommends 

GALL Report AMP XI.S1, “ASME Section XI, Subsection IWE,” and AMP XI.S4, 

“10 CFR Part 50, Appendix J,” to manage cracking due to SCC for this component group. The 

applicant stated that this item is not applicable because this item is only applicable to Mark III 

containments and LCSC is a Mark II containment design. The staff evaluated the applicant’s 

claim and finds it acceptable because all of the GALL Report items associated with SRP-LR

Table 3.5.1, item 3.5.1-38, address Mark III containments. Item 3.5.1-37 addresses the aging 

management of the stainless steel suppression chamber liner for Mark II containments.

LRA Table 3.5.1, item 3.5.1-40, addresses steel elements, including vent header and 

downcomers exposed to air-indoor, uncontrolled, or treated water. The GALL Report

recommends GALL Report AMP XI.S1, “ASME Section XI, Subsection IWE,” and AMP XI.S4, 

“10 CFR Part 50, Appendix J,” to manage cracking due to cyclic loading for components for 

which a CLB fatigue analysis does not exist. The applicant stated that this item is not applicable 

because LSCS has braced downcomers and because a CLB fatigue analysis does exist for the 

downcomers. The staff evaluated the applicant’s claim and finds it acceptable because this 

item only applies to components that do not have a fatigue-based analysis in the CLB. The 

applicant addresses cyclic loading for downcomers as a TLAA. The staff’s evaluation of the 

TLAA to address these components is documented in SER Section 4.6. The applicant also 

stated that the LSCS primary containment design does not use a vent line header. The staff 

reviewed UFSAR Section 3.8 and noted that LSCS does not use a torus and/or torus vent line 

for pressure suppression and, therefore, does not have a corresponding vent line header. 

Therefore, the staff finds that the determination that the item is not applicable is acceptable.

Loss of Material Due to General, Pitting, and Crevice Corrosion

LRA Table 3.5.1, item 3.5.1-37, addresses stainless steel components of the containment 

suppression chamber exposed to uncontrolled indoor air and/or treated water environments, 

which will be managed for loss of material due to corrosion. For the AMR items in LRA 

Table 3.5.2-7 that cite generic note E and plant-specific note 5, the LRA credits the ASME 

Section XI, Subsection IWE program to manage the aging effect for the drywell floor liner, the 

cavity slab liner, the drywell floor penetrations, and the downcomers. The GALL Report
3-327

recommends GALL Report AMP XI.S1, “ASME Section XI, Subsection IWE,” and AMP XI.S4, 

“10 CFR Part 50, Appendix J,” to ensure that this aging effect is adequately managed. The 

GALL Report AMPs recommend using visual inspections and 10 CFR Part 50, Appendix J,

pressure testing to manage the effects of aging.

The staff’s evaluation of the applicant’s ASME Section XI, Subsection IWE program is 

documented in SER Section 3.0.3.2.15. The staff noted that the applicant’s ASME Section XI, 

Subsection IWE program proposes to manage the effects of aging for stainless steel 

components through the use of acceptable visual inspections. LRA Table 3.5.2-7 plant-specific 

note 5 states, in part, that “10 CFR 50 Appendix J pressure testing is not applicable to the 

drywell floor liner, cavity slab liner, drywell floor penetrations, downcomers, and pedestal liner.” 

The staff noted that these components are not required to be within the scope of the 

10 CFR Part 50, Appendix J program and that pressure testing would not be an appropriate 

aging management approach for these items because they are not primary containment 

pressure-retaining components. Based on its review of components associated with 

item 3.5.1-37 for which the applicant cited generic note E and plant-specific note 5, the staff 

finds the applicant’s proposal to manage the effects of aging using only the ASME Section XI, 

Subsection IWE program acceptable because the program includes appropriate visual 

inspections and because the additional pressure testing recommended by the 10 CFR Part 50, 

Appendix J program would be ineffective for detecting degradation in these components.

LRA Table 3.5.1, item 3.5.1-37, addresses stainless steel liners of concrete columns in the 

containment suppression chamber exposed to uncontrolled indoor air and/or treated water 

environments, which will be managed for loss of material due to corrosion. For the AMR items 

in LRA Table 3.5.2-7 that cite generic note E and plant-specific note 8, the LRA credits the 

Structures Monitoring program to manage the aging effect for the non-pressure-retaining liners 

of the concrete columns. The GALL Report recommends GALL Report AMP XI.S1, “ASME 

Section XI, Subsection IWE,” and AMP XI.S4, “10 CFR Part 50, Appendix J,” to ensure that this 

aging effect is adequately managed. The GALL Report AMPs recommend using visual 

inspections and 10 CFR Part 50, Appendix J pressure testing to manage the effects of aging.

The staff’s evaluation of the applicant’s Structures Monitoring program is documented in SER 

Section 3.0.3.2.19. The staff noted that the applicant’s Structures Monitoring program proposes 

to manage the effects of aging for stainless steel components through the use of acceptable 

visual inspections. The staff noted that the referenced components are not required to be within 

the scope of the ASME Section XI, Subsection IWE or 10 CFR Part 50, Appendix J programs 

because they are not primary containment pressure-retaining components. Furthermore, 

pressure testing would not be an effective aging management technique for these items 

because they are not pressure-retaining components. Based on its review of components 

associated with item 3.5.1-37, for which the applicant cited generic note E and plant-specific 

note 8, the staff finds the applicant’s proposal to manage the effects of aging using the 

Structures Monitoring program acceptable because the program includes appropriate visual 

inspections.

The staff concludes that, for LRA item 3.5.1-37, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

LRA Table 3.5.1, item 3.5.1-80, addresses steel structural bolting exposed to air-indoor 

uncontrolled environment, which will be managed for loss of material due to general, pitting, and 
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crevice corrosion. For the AMR items that cite generic note E, the LRA credits the Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems program to 

manage the aging effect for bolting in cranes, hoists, and refueling equipment systems and the 

ASME Section XI, Subsection IWL program to manage the aging effect for steel grease cap at 

tendon anchorage. The GALL Report recommends GALL Report AMP XI.S6, “Structures 

Monitoring,” to ensure that this aging effect is adequately managed. GALL Report AMP XI.S6 

recommends using visual inspections at a frequency not to exceed 5 years to manage the 

effects of aging. GALL Report AMP XI.S6 states that other structural bolting and anchor bolts 

are monitored for loss of material, loose or missing nuts, and cracking of concrete around the 

anchor bolts.

The staff’s evaluation of the applicant’s Inspection of Overhead Heavy Load and Light Load 

(Related to Refueling) Handling Systems program and ASME Section XI, Subsection IWL 

program are documented in SER Sections 3.0.3.2.7 and 3.0.3.2.16, respectively. The staff 

noted that the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) 

Handling Systems program proposes to manage the effects of aging loss of material due to 

corrosion for associated bolted connections through the use of periodic visual inspections 

(Commitment No. 14). The staff also noted that the ASME Section XI, Subsection IWL program 

proposes to manage the effects of aging for the unbonded post-tensioning system through the

use of visual inspections at 5-year intervals. The staff reviewed UFSAR Section 3.8.1.7.3.1 and 

verified that tendon anchorage hardware and grease caps are visually inspected for compliance 

with ASME Section XI, Subsection IWL. The staff notes that paragraph IWL-2524.1(b) of ASME 

Code Section XI, Subsection IWL, requires an examination of tendon anchorage hardware for 

corrosion, broken or protruding wires, missing buttonheads, broken strands, and cracks. Based 

on its review of components associated with item 3.5.1-80 for which the applicant cited generic 

note E, the staff finds the applicant’s proposal to manage the effects of aging using the 

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems 

program and the ASME Section XI, Subsection IWL program acceptable because the AMPs use 

periodic visual examination to detect loss of material due to corrosion before the loss of 

intended functions, consistent with the GALL Report recommendations.

The staff concludes that, for LRA item 3.5.1-80, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

Loss of Sealing Due to Deterioration of Seals, Gaskets, and Moisture Barriers 

(Caulking, Flashing, and Other Sealants)

LRA Table 3.5.1, item 3.5.1-72 addresses seals, gasket, and moisture barriers (caulking, 

flashing, and other sealants) exposed to various environments, which will be managed for loss 

of sealing due to deterioration. For the AMR items that cite generic note E, the LRA credits the 

Aboveground Metallic Tanks program to manage the aging effect for elastomer sealants and 

moisture barriers in tank foundations and dikes and the ASME Section XI, Subsection IWL 

program to manage the aging effect for elastomeric gaskets for grease caps at prestressing 

tendon anchorages. The GALL Report recommends GALL Report AMP XI.S6, “Structures 

Monitoring,” to ensure that this aging effect is adequately managed. GALL Report AMP XI.S6 

recommends using visual inspections at a frequency not to exceed 5 years to manage the 

effects of aging.
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The staff’s evaluation of the applicant’s Aboveground Metallic Tanks program and ASME 

Section XI, Subsection IWL program are documented in SER Sections 3.0.3.2.11 

and 3.0.3.2.16, respectively. The staff noted that the Aboveground Metallic Tanks program, as 

revised by the applicant’s response to RAI B.2.1.18-2, dated August 6, 2015, proposes to 

manage the effects of aging loss of sealing for caulking at the perimeter of the cycled 

condensate storage tank bases through the use of periodic visual inspections supplemented 

with physical manipulation for the caulking (Commitment No. 18, item 4). The staff also noted 

that the ASME Section XI, Subsection IWL program proposes to manage the effects of aging for 

unbonded post-tensioning systems through the use of visual inspections at 5-year intervals. 

The staff reviewed UFSAR Section 3.8.1.7.3.1 and verified that tendon anchorage hardware 

and grease caps are visually inspected for compliance with ASME Section XI, Subsection IWL. 

The staff notes that paragraph IWL-2510(c) in ASME Code Section XI, Subsection IWL,

requires an examination of the concrete surfaces and tendon end anchorage areas for corrosion 

protection medium leakage and an examination of the tendon end caps for deformation. Based 

on its review of components associated with item 3.5.1-72 for which the applicant cited generic 

note E, the staff finds the applicant’s proposal to manage the effects of aging using the 

Aboveground Metallic Tanks program and the ASME Section XI, Subsection IWL program 

acceptable because the AMPs use periodic visual examination to detect loss of sealing and 

leakage before the loss of intended functions, consistent with the GALL Report

recommendations.

The staff concludes that, for LRA item 3.5.1-72, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

Cracking Due to Stress Corrosion Cracking and Loss of Material Due to Pitting and 

Crevice Corrosion

LRA Table 3.5.1, item 3.5.1-78, addresses steel components for the fuel pool liner exposed to 

treated water, which will be managed for cracking due to SCC and for loss of material. The 

GALL Report recommends GALL Report AMP XI.M2, “Water Chemistry,” and monitoring of the 

spent fuel pool water level in accordance with technical specifications and leakage from leak 

chase channels to ensure that this aging effect is adequately managed.

During its review of components associated with item 3.5.1-78 for which the applicant cited 

generic note B, the staff noted that the LRA credits the Water Chemistry program to manage the 

aging effect for loss of material and cracking of stainless steel components of the fuel pool liner 

and additional components, such as stainless steel gates, liner anchors, and integral 

attachments. However, LRA Table 3.5.2-9 does not address cracking for stainless steel 

components exposed to treated water that are associated with item 3.5.1-78. The staff 

recognizes that treated water less than 140 °F is not an environment that is conducive to SCC; 

however, the UFSAR states that the spent fuel pool can exceed 140 °F. By letter dated 

July 27, 2015, the staff issued RAI 3.5.1.78-1, requesting that the applicant justify why the spent 

fuel pool components were not being managed for cracking.

In its response dated August 26, 2015, the applicant stated that it reviewed spent fuel pool 

temperatures since January 2000 and confirmed that temperatures have been maintained well 

below 140 °F, with the highest recorded temperature at less than 114 °F and the average 

normal temperature at 95 °F. The applicant discussed the portions of SRP-LR Section A.1.2.1.7

that state that aging effects from abnormal events need not be postulated unless such an event 
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has occurred at the particular plant. The applicant stated that the discussion in the UFSAR 

relating to spent fuel pool temperatures above 140 °F is only applicable for an “emergency” full 

core offload and that no such offload has occurred nor is it expected to occur. Based on this, 

the applicant determined that cracking was not an AERM for items that reference item 3.5.1-78;

consequently, no clarification on how the effectiveness of the Water Chemistry program is being 

verified is necessary.

The staff finds the response acceptable because the applicant verified that spent fuel pool 

temperatures have not exceed the 140 °F criterion and because it is reasonable to consider the 

temperatures discussed in the UFSAR for an “emergency” full core offload as an abnormal 

event that does not need to be postulated. The staff’s concern described in RAI 3.5.1.78-1 is 

resolved.

The staff concludes that, for LRA item 3.5.1-78, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.5.1, item 3.5.1-85, addresses stainless steel structural bolting exposed to treated 

water, which will be managed for loss of material due to pitting and crevice corrosion. For the 

AMR item that cites generic note E, the LRA credits the Inspection of Overhead Heavy Load 

and Light Load (Related to Refueling) Handling Systems program in LRA Section B.2.1.14 and 

the Water Chemistry program in LRA Section B.2.1.2 to manage the aging effect of loss of 

material due to corrosion for stainless steel structural bolting. The GALL Report recommends 

GALL Report AMP XI.S3, “ASME Section XI, Subsection IWF,” and AMP XI.M2, “Water 

Chemistry,” to ensure that this aging effect is adequately managed. GALL Report AMP XI.S3 

recommends using VT-3 visual inspections on a prescribed sample of supports at an interval of 

10 years to manage the effects of aging.

The staff’s evaluation of the applicant’s Inspection of Overhead Heavy Load and Light Load 

(Related to Refueling) Handling Systems program and the Water Chemistry program is 

documented in SER Sections 3.0.3.2.7 and 3.0.3.2.1, respectively. Because both the LRA and 

GALL Report AMR items use the Water Chemistry program as one of the AMPs to manage the 

aging effect, the acceptability of the use of the Overhead Heavy Load and Light Load (Related 

to Refueling) Handling Systems program in lieu of the ASME Section XI, Subsection IWF 

program as the other AMP to manage the aging effect is only discussed here. The staff noted 

that the applicant’s Inspection of Overhead Heavy Load and Light Load (Related to Refueling) 

Handling Systems program, with enhancement, is consistent with GALL Report AMP XI.M23.

The staff also noted that the enhanced Inspection of Overhead Heavy Load and Light Load 

(Related to Refueling) Handling Systems program proposes to manage the effects of aging of 

loss of material due to corrosion for components under its scope, including stainless steel 

bolting in cranes, hoists, and refueling equipment through the use of periodic visual inspections 

by qualified personnel and at a frequency consistent with the recommendations of the 

ASME Code B30 series standards for all cranes, hoists, and handling equipment systems. 

Accordingly, periodic inspections are performed annually. For handling systems that are 

infrequently in service, such as those only used during refueling outages, periodic inspections 

may be deferred until just prior to use.
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Based on its review of components associated with item 3.5.1-85 for which the applicant cited 

generic note E, the staff finds the applicant’s proposal to manage the effects of aging using the 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems program 

acceptable because (1) the enhanced program includes, under its scope, the aging effect of 

loss of material due to corrosion of stainless steel bolting in a treated water environment and 

(2) the program includes periodic visual inspections using qualified personnel annually or at 

least just before use to detect loss of material on cranes and/or hoist components, including 

bolting, which is more frequent than visual inspections in the GALL Report-recommended 

AMP XI.S3 and, therefore, is at least as effective in managing the aging effect.

The staff concludes that, for LRA item 3.5.1-85, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

LRA Table 3.5.1, item 3.5.1-93 addresses support members, welds, bolted connections, and 

support anchorage to building structures exposed to an air-outdoor environment, which will be 

managed for loss of material due to pitting and crevice corrosion. For the AMR item that cites 

generic note E, the LRA credits the Open-Cycle Cooling Water System program to manage the 

aging effect for stainless steel shad net fish barrier filters in the Essential Cooling Water System. 

The GALL Report recommends GALL Report AMP XI.S6, “Structures Monitoring,” to ensure 

that this aging effect is adequately managed. GALL Report AMP XI.S6 recommends using 

visual inspections at a frequency not to exceed 5 years to manage the effects of aging.

The staff’s evaluation of the applicant’s Open-Cycle Cooling Water System program is 

documented in SER Section 3.0.3.2.5. The staff noted that the Open-Cycle Cooling Water 

System program proposes to manage the effects of aging, loss of material, and reduction of

heat transfer for heat exchangers, piping, piping elements, and piping components in 

safety-related and nonsafety-related systems. The staff also noted that the AMP manages the 

effects of aging through the use of visual inspections, testing, nondestructive examinations, and 

biocide and chemical treatment. LRA Section B.2.1.12 states that activities for this program are 

consistent with commitments to the requirements of GL 89-13, which recommends visual 

inspection at a frequency of once per refueling cycle for intake structures. Also, as documented 

in the Open-Cycle Cooling Water System program Audit Report, polymeric portions of the shad 

net are periodically replaced, providing other opportunities for inspections. Based on its review 

of components associated with item 3.5.1-93 for which the applicant cited generic note E, the 

staff finds the applicant’s proposal to manage the effects of aging using the Open-Cycle Cooling 

Water System program acceptable because the AMP uses periodic visual examination, at a 

frequency not to exceed 5 years, to detect loss of material before the loss of intended functions, 

consistent with the GALL Report recommendations.

The staff concludes that, for LRA item 3.5.1-93, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

Loss of Preload Due to Self-Loosening

LRA Table 3.5.1, item 3.5.1-88, addresses steel structural bolting exposed to any environment, 

which will be managed for loss of preload due to self-loosening. For the AMR items that cite 

generic note E, the LRA credits the Inspection of Overhead Heavy Load and Light Load 
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(Related to Refueling) Handling Systems program to manage the aging effect for steel bolting in 

cranes, hoists, and refueling equipment and the ASME Section XI, Subsection IWL program to 

manage the aging effect for grease caps in tendon anchorage. The GALL Report recommends 

GALL Report AMP XI.S6, “Structures Monitoring,” to ensure that this aging effect is adequately 

managed. GALL Report AMP XI.S6 recommends using visual inspections at a frequency not to 

exceed 5 years to manage the effects of aging. GALL Report AMP XI.S6 states that structural 

bolting is monitored for loose bolts, missing or loose nuts, and other conditions indicative of loss 

of preload.

The staff’s evaluation of the applicant’s Inspection of Overhead Heavy Load and Light Load 

(Related to Refueling) Handling Systems program and the ASME Section XI, Subsection IWL 

program are documented in SER Sections 3.0.3.2.7 and 3.0.3.2.16, respectively. The staff 

noted that the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) 

Handling Systems program proposes to manage the effects of aging loss of preload for 

associated bolted connections through the use of periodic visual inspections (LRA Commitment 

No. 14). Per LRA Section B.2.1.14, inspections are performed annually or just before use.

The staff also noted that the ASME Section XI, Subsection IWL program proposes to manage 

the effects of aging for unbonded post-tensioning system through the use of visual inspections 

at 5-year intervals. The staff reviewed UFSAR Section 3.8.1.7.3.1 and verified that tendon 

anchorage hardware and grease caps are visually inspected for compliance with ASME Code

Section XI, Subsection IWL. The staff notes that paragraph IWL-2524.1 of ASME Code 

Section XI, Subsection IWL, requires the tendon anchorage hardware to be examined, in part, 

for corrosion, broken or protruding wires, missing buttonheads, broken strands, cracks, and 

detached buttonheads. Based on its review of components associated with items 3.5.1-88 for 

which the applicant cited generic note E, the staff finds the applicant’s proposal to manage the 

effects of aging using the Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems program and the ASME Section XI, Subsection IWL program 

acceptable because the AMPs use periodic visual examination to detect conditions indicative of 

loss of preload before the loss of intended functions, consistent with the GALL Report

recommendations.

The staff concludes that, for LRA item 3.5.1-88, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation Is 

Recommended

In LRA Section 3.5.2.2, the applicant further evaluated aging management, as recommended by 

the GALL Report, for the structures and component supports components and provided

information concerning how it will manage aging effects in the following four areas:

(1) PWR and BWR containments

− cracking and distortion due to increased stress levels from settlement, reduction of 

foundation strength, and cracking due to differential settlement and erosion of 

porous concrete subfoundations

− reduction of strength and modulus due to elevated temperature

− loss of material due to general, pitting, and crevice corrosion
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− loss of prestress due to relaxation, shrinkage, creep, and elevated temperature

− cumulative fatigue damage

− cracking due to SCC

− loss of material (scaling, spalling) and cracking due to freeze-thaw

− cracking due to expansion and reaction with aggregates

− increase in porosity and permeability due to leaching of calcium hydroxide and 

carbonation

(2) safety-related and other structures and component supports

− aging management of inaccessible areas

− reduction of strength and modulus due to elevated temperature

− aging management of inaccessible areas for Group 6 structures

− cracking due to SCC and loss of material due to pitting and crevice corrosion

− cumulative fatigue damage due to fatigue

(3) QA for aging management of nonsafety-related components

(4) ongoing review of operating experience

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 

the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.5.2.2. The staff’s review of the applicant’s 

further evaluation follows.

PWR and BWR Containments

The staff reviewed LRA Section 3.5.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.1, which 

address the following areas:

Cracking and Distortion Due to Increased Stress Levels from Settlement, Reduction of 

Foundation Strength, and Cracking Due to Differential Settlement and Erosion of Porous 

Concrete Subfoundations. LRA Section 3.5.2.2.1.1, associated with LRA Table 3.5.1, 

item 3.5.1-1, addresses cracking and distortion due to increased stress levels from settlement in 

the concrete dome, wall, basemat, ring girders, and buttresses exposed to soil. LRA 

Section 3.5.2.2.1.1 is also associated with LRA Table 3.5.1, item 3.5.1-2, which addresses 

reduction of foundation strength and cracking due to differential settlement and erosion of 

porous concrete subfoundation in concrete foundation and subfoundation exposed to flowing 

water. The criteria in SRP-LR Section 3.5.2.2.1.1 state that for PWR and BWR containments 

the GALL Report recommends further evaluation for aging management of (1) cracking and 

distortion due to settlement and (2) reduction of foundation strength and cracking, if a 

dewatering system is used to control settlement. The SRP-LR also states that, when a 

dewatering system used to control settlement is in place, its functionality should be monitored 

through the ASME Section XI, Subsection IWL program or the Structures Monitoring program.
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The applicant addressed the further evaluation criteria of the SRP-LR by stating that the LSCS 

primary containment structures are founded on soil and, therefore, could be subject to cracking 

and distortion due to increased stress levels from settlement. The applicant stated that, 

although cracking and distortion have not been observed in LSCS concrete structures, the 

ASME Section XI, Subsection IWL and Structures Monitoring programs include provisions to 

monitor the primary containment structures for cracking. The applicant further stated that it 

would use indications from above-grade portions of the containment building and the enclosing 

reactor building to detect cracking of below-grade areas. In addition, the applicant stated that 

cracks extending into accessible areas, including buttresses of the Primary Containment, if any, 

would be managed by the ASME Section XI, Subsection IWL program. The applicant stated 

that procedures require an extent of condition evaluation and additional inspections or 

evaluations to address inaccessible and below-grade portions of the structure. In addition, the 

applicant stated that it does not rely on a dewatering system to control settlement.

The staff’s evaluation of the applicant’s ASME Section XI, Subsection IWL and Structures 

Monitoring programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.2.19, respectively. 

The staff noted that this item is associated with GALL Report item II.B2.2.CP-105, which 

recommends that these programs be used to manage aging of accessible and inaccessible 

areas of the containment concrete. The staff also noted that both programs use periodic visual 

inspections and that these visual inspections identify cracking due to any mechanism. The 

programs include provisions for evaluation of inaccessible areas if indications of degradation are 

found in accessible areas of structural concrete.

In its review of components associated with item 3.5.1-1, the staff finds that the applicant has 

met the further evaluation criteria and finds the applicant’s proposal to manage the effects of 

aging using the ASME Section XI, Subsection IWL and Structures Monitoring programs 

acceptable because (1) the applicant has no operating experience to indicate that there has 

been settlement cracking of primary containment to date, (2) the applicant will manage cracking 

due to distortion and settlement using accessible areas as indicators of degradation to drive 

evaluation of inaccessible areas, and any cracking that would affect the ability of primary 

containment to perform its safety functions would propagate to areas of the containment that are 

accessible and are subject to periodic visual examinations before a loss of those safety 

functions occurs, and (3) no additional actions or evaluations are necessary to manage the 

function of a dewatering system to control settlement because the applicant does not control 

settlement with such a system.

For item 3.5.1-2, the applicant stated that this item is not applicable because LSCS 

containments do not have any porous concrete subfoundations; therefore, this aging effect and 

mechanism is not applicable. The staff evaluated the applicant’s claim and finds it acceptable 

because the GALL Report recommendation to manage the aging effect of reduction of 

foundation strength and cracking due to differential settlement and erosion of porous concrete 

subfoundation only applies to porous subfoundations, which do not exist at LSCS.

Reduction of Strength and Modulus Due to Elevated Temperature. LRA Section 3.5.2.2.1.2, 

associated with LRA Table 3.5.1, item 3.5.1-3, addresses reduction of strength and modulus of 

concrete due to elevated temperatures in concrete, including the dome, wall, basemat, ring 

girders, buttresses, containment, and fill-in annulus exposed to an air-indoor uncontrolled or 

air-outdoor environment. The criteria in SRP-LR Section 3.5.2.2.1.2 state that the GALL Report 

recommends further evaluation of a plant-specific program if any portion of the concrete 

containment components exceeds specified temperature limits (i.e., general area temperature 

greater than 150 °F and local area temperature greater than 200 °F). The SRP-LR also states 
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that the implementation of 10 CFR 50.55a and the ASME Section XI, Subsection IWL program

would not be able to identify this aging effect; however, higher temperatures may be allowed if 

tests and/or calculations are provided to evaluate the reduction in strength and modulus of 

elasticity and if these reductions are applied to the design calculations. The applicant stated 

that this item is not applicable because (1) the average temperature inside the primary 

containment structure is maintained less than 135 °F by the primary containment ventilation 

system in accordance with LSCS Technical Specification limits, (2) a cooling coil system is used 

between hot pipes and primary containment penetration sleeves as an added feature to reduce 

local concrete temperatures, and (3) localized concrete temperatures exceeding 200 °F have 

not been reported. The staff evaluated the applicant’s claim and finds it acceptable because the 

staff reviewed UFSAR Subsections 6.2.1.1.2, 7.8.2.2.2.4, and 3.8.1.1.3.5.2 and confirmed that 

(1) a primary containment ventilation system maintains the general area temperatures below the 

threshold from the GALL Report, (2) the design of the primary containment penetration sleeves

provides insulation, air gaps, and a cooling coil system to reduce thermal stress in the

containment during normal operations, and (3) site operating experiences have not identify plant 

conditions in which local area temperatures have exceeded the threshold limit in the 

GALL Report.

Loss of Material Due to General, Pitting, and Crevice Corrosion.

Item 1. LRA Section 3.5.2.2.1.3 is associated with LRA Table 3.5.1, items 3.5.1-4 and 3.5.1-5. 

Item 3.5.1-4 addresses steel elements (inaccessible areas), including a steel drywell shell and 

drywell head exposed to air-indoor, uncontrolled, or concrete. This item is associated with 

Mark III containments and is not applicable to LSCS, which uses a Mark II containment design. 

Item 3.5.1-5 addresses steel elements (inaccessible areas), including a drywell liner, liner 

anchors, integral attachments, and the region shielded by the diaphragm floor exposed to an

air-indoor uncontrolled environment, which will be managed for loss of material by the 

10 CFR Part 50, Appendix J and ASME Section XI, Subsection IWE programs. The LRA states 

that the LSCS suppression chamber is lined with stainless steel; therefore, it is not applicable to 

this item. The criteria in SRP-LR Section 3.5.2.2.1.3, item 1, state that loss of material due to 

general, pitting, and crevice corrosion could occur for steel elements of inaccessible areas for all 

types of PWR and BWR containments. The existing program relies on ASME Section XI, 

Subsection IWE, and 10 CFR Part 50, Appendix J, to manage this aging effect. The SRP-LR 

also states that the GALL Report recommends further evaluation of plant-specific programs to 

manage this aging effect if corrosion is indicated from the IWE examinations.

The applicant addressed the further evaluation criteria of the SRP-LR by stating that the ASME 

Section XI, Subsection IWE program and the 10 CFR Part 50, Appendix J program will be used 

to manage loss of material of steel elements in inaccessible areas of the drywell and integral 

attachments. The applicant stated several ways that the configuration of the LSCS containment 

is such that there are few inaccessible areas for which steel corrosion could be an issue. The 

LRA states that the LSCS concrete containment drywell and suppression pool design does not 

use a liner that is inaccessible for inspection and that the majority of the IWE surfaces, including 

the drywell head, is accessible. There is no air gap between the drywell liner and the concrete 

containment. Additionally, corrosive materials, such as borated water or brackish service water,

do not come into contact with the containment. The LRA states that “[t]here are limited areas 

that are inaccessible for inspection which include the thickened embedded steel section covered 

by the outer edges of the concrete drywell floor, and also the suppression pool floor liner areas 

covered by the suppression pool columns and areas behind the suction strainers.” The 

applicant stated that the concrete drywell floor, which is inspected as part of the ASME 

Section XI, Subsection IWL program, has not shown any indication of cracking near the junction 
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of the concrete and liner and has not shown cracking of the concrete floor or any indication of 

corrosion in the inaccessible portion of the liner. The suppression chamber walls, floor, and 

ceiling are lined with stainless steel, and the applicant noted that no signs of general, pitting,

and crevice corrosion have been indicated from IWE examinations of these areas. The LRA 

states that the coated areas of the carbon steel liner are inspected for indications, such as 

blisters, that could indicate corrosion of the drywell liner. The applicant stated that areas of light 

general corrosion have been identified in the drywell during IWE examinations but that the 

corrosion has not been significant. These areas have been recoated or identified for coating 

maintenance. The applicant concluded that no additional plant-specific activities are warranted 

to manage loss of material due to general, pitting, and crevice corrosion for inaccessible steel 

areas of containment and that the continued monitoring of the containment liner in accordance 

with the ASME Section XI, Subsection IWE and 10 CFR Part 50 Appendix J programs will 

provide reasonable assurance that the containment liner will remain functional through the 

period of extended operation.

The staff notes that the applicant’s operating experience and IWE inspections suggest that there 

is no significant loss of material of the LSCS containment liner due to general, pitting, or crevice 

corrosion in accessible and inaccessible areas to necessitate a plant-specific program to 

manage the aging effect. The staff’s evaluation of the applicant’s ASME Section XI, 

Subsection IWE program and the 10 CFR Part 50, Appendix J program are documented in SER 

Sections 3.0.3.2.15 and 3.0.3.1.15, respectively. The staff noted that the programs ensure that 

corrosion of the carbon steel containment liner and components is detected and that corrective 

actions are taken before there is a loss of material that affects its ability to perform intended 

functions by using visual examinations of all accessible drywell and suppression chamber 

areas. These inspections are performed at frequencies required by ASME Code Section XI, 

Subsection IWE, and applicable regulations, and periodic leak rate testing is performed in 

accordance with 10 CFR Part 50, Appendix J. Augmented examinations, including 

examinations of inaccessible areas, are required if there are indications in accessible areas that 

degradation of inaccessible areas could also be occurring. The staff finds that the applicant has 

met the further evaluation criteria and that the applicant’s proposal to manage the effects of 

aging using the ASME Section XI, Subsection IWE program and the 10 CFR Part 50, 

Appendix J program is acceptable because the plant-specific operating experience from IWE 

examinations indicates no significant loss of material due to corrosion in inaccessible areas of 

the containment and because the applicant’s approach to managing the aging effect is 

consistent with the recommendations in GALL Report item II.B2.2.CP-63, which corresponds to 

LRA Table 3.5.1, item 3.5.1-5.

Based on the programs identified, the staff determines that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.1.3, item 1, criteria. The staff concludes that the LRA is consistent with 

the GALL Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Item 2. LRA Section 3.5.2.2.1.3.2, associated with LRA Table 3.5.1, item 3.5.1-6, addresses 

steel elements, including the torus shell exposed to an air-indoor, uncontrolled, or treated water 

environment, which will be managed for loss of material due to general, pitting, and crevice 

corrosion by the ASME Section XI, Subsection IWE and 10 CFR Part 50, Appendix J programs. 

The criteria in SRP-LR Section 3.5.2.2.1.3, item 2, state that loss of material due to general, 

pitting, and crevice corrosion could occur in steel torus shell of Mark I containments. LSCS 

uses a Mark II concrete containment where the primary containment drywell is steel-lined 
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prestressed concrete and the suppression pool is stainless steel lined prestressed concrete; 

therefore, this item is not applicable for LSCS.

Item 3. LRA Section 3.5.2.2.1.3.3, associated with LRA Table 3.5.1, item 3.5.1-7, addresses 

steel elements, including torus ring girders, downcomers, suppression chamber shell (interior 

surface) exposed to an air-indoor, uncontrolled, or treated water environment, which will be 

managed for loss of material due to general, pitting, and crevice corrosion by the ASME 

Section XI, Subsection IWE and 10 CFR Part 50, Appendix J programs. The criteria in SRP-LR 

Section 3.5.2.2.1.3, item 3, state that loss of material due to general, pitting, and crevice 

corrosion could occur in the steel torus ring girders and downcomers of Mark I containments, 

downcomers of Mark II containments, and interior surface of suppression chamber shell of 

Mark III containments. The SRP-LR also states that the existing program relies on the ASME 

Section XI, Subsection IWE program to manage this aging effect. The applicant stated that this 

item is not applicable to the LSCS Mark II concrete containment because LSCS uses stainless 

steel, not carbon steel, downcomers. The applicant stated that general, pitting, and crevice 

corrosion have not been identified from the IWE examinations of the downcomers and that the 

ASME Section XI, Subsection IWE program is used to manage loss of material of these 

components. The staff reviewed sections of the UFSAR, including Table 6.1-1, and verified that 

the downcomers are stainless steel. Therefore, the staff finds that this item, which is associated 

with further evaluation of carbon steel containment components, does not apply to LSCS. 

Further, the staff noted that the stainless steel downcomers are managed by the ASME 

Section XI, Subsection IWE program for this aging effect under LRA Table 3.5.1, item 3.5.1-37.

Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature. LRA 

Section 3.5.2.2.1.4, associated with LRA Table 3.5.1, item 3.5.1-8, states that loss of prestress 

forces due to relaxation, shrinkage, creep, and elevated temperature for the prestressed 

concrete primary containment structures is an aging effect evaluated by a TLAA in accordance 

with 10 CFR 54.21(c)(1) and that the evaluation of this TLAA is addressed in LRA Section 4.5. 

This is consistent with SRP-LR Section 3.5.2.2.1.4 and, therefore, is acceptable. The staff’s 

evaluation of the TLAA for concrete containment tendon prestress analyses is documented in 

SER Section 4.5.

Cumulative Fatigue Damage. LRA Section 3.5.2.2.1.5, associated with LRA Table 3.5.1,

item 3.5.1-9, addresses penetration sleeves, penetration bellows, torus and vent header steel 

elements, vent line, vent header, vent line bellows, downcomers, suppression pool shell, 

unbraced downcomers, and downcomers exposed to either an air-indoor uncontrolled or treated 

water environment, which will be managed for cumulative fatigue damage by the TLAAs. The 

criteria in SRP-LR Section 3.5.2.2.1.5 state that fatigue analyses included in the CLB are TLAAs 

as defined in 10 CFR 54.3, “Definitions,” and that they are required to be evaluated in 

accordance with 10 CFR 54.21(c). The applicant stated that LSCS does not have penetration 

bellows, torus vent line, vent line header, vent line bellows, unbraced downcomers, or vent 

headers. The applicant addressed the further evaluation criteria of the SRP-LR by stating that 

TLAAs are evaluated in accordance with 10 CFR 54.21(c)(1) and that the evaluation of this 

TLAA is addressed in LRA Section 4.6, “Primary Containment Fatigue Analyses.” This is 

consistent with SRP-LR Section 3.5.2.2.1.5 and, therefore, is acceptable.

In its review of components associated with item 3.5.1-9, the staff noted that the corresponding 

LRA Table 3.5.2-7 AMR results items address electrical penetration assemblies, mechanical 

penetration assemblies, penetration sleeves, refueling bellows assembly, and downcomer 

components, which will be managed for cumulative fatigue damage aging effects by the TLAAs. 

However, the staff noted that LRA Table 3.5.2-7 does not identify any AMR results items 
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corresponding to Table 3.5.1, item 3.5.1-9, for the primary containment liner. The LRA does not 

clarify how these components are being adequately managed for cumulative fatigue damage 

aging effects for the period of extended operation.

By letter dated July 27, 2015, the staff issued RAI 3.5.2.2.1.5-1, requesting that the applicant 

describe how the primary containment liner is adequately managed for the cumulative fatigue 

damage aging effect through the period of extended operation and provide the technical basis 

for not addressing containment liner components in the LRA Table 3.5.2-7 for AMR results.

In its response dated August 26, 2015, the applicant stated that the cumulative fatigue damage 

aging effect for primary containment components will be adequately managed through the 

period of extended operation by its Fatigue Monitoring program. The applicant revised LRA 

Table 3.5.2-7 and Section 3.5.2.2.1.5 to include the cumulative fatigue damage aging effect 

items for the primary containment liner and associated components.

The staff finds the applicant’s response acceptable because the cumulative fatigue damage 

aging effect for the primary containment liner and associated components will be managed by 

the Fatigue Monitoring program based on disposition of the associated TLAA in LRA 

Section 4.6.1 pursuant to 10 CFR 54.21(c)(1)(iii) and because the applicant revised LRA 

Table 3.5.2-7 to identify the AMR results items associated with this aging effect. The staff’s 

concern described in RAI 3.5.2.2.1.5-1 is resolved.

The staff’s evaluation of the applicant’s TLAAs for the primary containment liner and 

penetrations, refueling bellows, and downcomer vents are documented in SER 

Sections 4.6.1, 4.6.2, and 4.6.3, respectively. The staff notes that the aging effects for 

containment liner and penetrations will be managed using the Fatigue Monitoring program 

through the period of extended operation. The staff finds that the applicant has met the further 

evaluation criteria and that the applicant’s plan to manage the effects of aging using TLAAs and 

the Fatigue Monitoring program is acceptable because the required TLAAs have been 

evaluated in accordance with 10 CFR 54.21(c)(1).

For those items associated with LRA Section 3.5.2.2.1.5, the staff concludes that the LRA is 

consistent with the GALL Report and that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended functions will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Cracking Due to Stress Corrosion Cracking. LRA Section 3.5.2.2.1.6, associated with LRA 

Table 3.5.1, item 3.5.1-10, addresses cracking due to SCC in containment bellows and 

penetrations fabricated with stainless steel that are exposed to uncontrolled air-indoor (external) 

or treated water (internal). The acceptance criteria in SRP-LR Section 3.5.2.2.1.6 state that 

cracking due to SCC of stainless steel penetration bellows and dissimilar metal welds could 

occur in all types of PWR and BWR containments. The SRP-LR also states that the existing 

program relies on ASME Code Section XI, Subsection IWE, and 10 CFR Part 50, Appendix J, to 

manage this aging effect. In addition, the SRP-LR states that the GALL Report recommends 

further evaluation of additional appropriate examinations or evaluations implemented to detect 

these aging effects for stainless steel penetration bellows and dissimilar metal welds.

LRA Section 3.5.2.2.1.6 states that the primary containment design does not use penetration 

bellows. The LRA also states that AMR item 3.5.1-10 is not applicable to the LSCS stainless 

steel penetration sleeves and dissimilar metal welds because the environment is not corrosive 

enough to cause SCC. The LRA further states that inspections of these stainless steel 
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penetration components are conducted in accordance with the ASME Section XI, 

Subsection IWE program and the 10 CFR Part 50, Appendix J program. The LRA states that no 

further evaluation is required because LSCS and industry operating experience has not 

identified cracking due to SCC as an applicable aging effect for BWR Mark II containment 

stainless steel penetration components.

In its review, the staff finds the applicant’s claim acceptable because (1) the LSCS units do not 

use containment penetration bellows, consistent with the staff’s review of the UFSAR that did 

not identify any containment penetration bellows, (2) the plant-specific and industry operating 

experience has not identified cracking due to SCC of Mark II containment stainless steel 

penetration components, and (3) LSCS containment penetrations are not exposed to a 

corrosive environment that could cause SCC. The staff finds that the applicant’s use of the 

existing ASME Section XI, Subsection IWE program and 10 CFR Part 50, Appendix J program 

is acceptable to ensure that cracking due to SCC does not affect the integrity of the stainless 

steel penetration components.

Based on the programs identified, the staff determines that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.1.6 criteria. For those items associated with LRA Section 3.5.2.2.1.6, 

the staff concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

Loss of Material (Scaling, Spalling) and Cracking Due to Freeze-Thaw. LRA 

Section 3.5.2.2.1.7, associated with LRA Table 3.5.1, item 3.5.1-11, addresses loss of material 

(spalling, scaling) and cracking due to freeze-thaw in inaccessible areas of concrete, including 

the dome, wall, basemat, ring girders, and buttresses exposed to an air-outdoor or 

groundwater/soil environment. The criteria in SRP-LR Section 3.5.2.2.1.7 state that the 

GALL Report recommends further evaluation of this aging effect for plants located in moderate 

to severe weathering conditions. The SRP-LR also states that a plant-specific program is not 

required if documented evidence confirms that the existing concrete has an air content of 3 to 

8 percent and that subsequent inspection of accessible areas did not exhibit degradation related 

to freeze-thaw. The applicant stated that this item is not applicable because the primary 

containment is completely enclosed and sheltered by the air-indoor environment of the reactor 

building (secondary containment); therefore, the primary containment is not subject to the

freezing temperature environment necessary for this aging effect to occur. The staff evaluated 

the applicant’s claim and finds it acceptable because the staff reviewed UFSAR 

Sections 3.8.1.1.1, 3.8.4.1.1, and 3.8.5.1.1 and confirmed that the primary containment is 

enclosed by the reactor building; therefore, these concrete elements are not exposed to the 

environment required for this aging effect to occur. The staff notes that this aging effect for 

inaccessible below-grade areas of the common basemat foundation is addressed by LRA 

Table 3.5.1, item 3.5.1-42, and SER Section 3.5.2.2.2, item 1.

Cracking Due to Expansion and Reaction with Aggregates. LRA Section 3.5.2.2.1.8, associated 

with LRA Table 3.5.1, item 3.5.1-12, addresses inaccessible areas of concrete elements 

exposed to an air-indoor uncontrolled or groundwater/soil environment, which will be managed 

for cracking due to expansion from reaction with aggregates by the ASME Section XI, 

Subsection IWL program and the Structures Monitoring program. The criteria in SRP-LR 

Section 3.5.2.2.1.8 state that the GALL Report recommends further evaluation to determine 

whether a plant-specific AMP is required to manage this aging effect. The GALL Report states 

that a plant-specific AMP is not necessary if (1) investigations, tests, and petrographic 
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examinations of aggregates performed in accordance with ASTM C295 and other ASTM 

reactivity tests, as required, can demonstrate that those aggregates do not adversely react 

within concrete or (2) for potentially reactive aggregates, aggregate concrete reaction is not 

significant if the structure was constructed in accordance with ACI 318. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that (1) petrographic 

examinations of aggregates and ASTM reactivity tests were performed in accordance with 

ASTM C227 at the time of construction to prevent use of reactive aggregates in concrete, 

(2) concrete structures were constructed in accordance with ACI 318 per UFSAR Appendix E, 

and (3) previous ASME Section XI, Subsection IWL program examinations have not identified 

the pattern cracking typical of expansion from reaction with aggregates in the primary 

containment or in accessible areas of the reactor building or other structures exposed to 

sources of moisture. Noting that NRC IN 2011-20, “Concrete Degradation by Alkali-Silica 

Reaction,” dated November 18, 2011, indicates that the ASTM tests may not always be effective 

in screening reactive aggregates, the applicant further stated that the ASME Section XI, 

Subsection IWL program will continue to monitor the primary containment concrete for cracking 

and pattern cracking typical of expansion from reaction with aggregates or from cracking due to 

any mechanism and that the Structures Monitoring program will also examine exposed portions 

of below-grade concrete when it is excavated for any reason.

The staff’s evaluation of the applicant’s ASME Section XI, Subsection IWL program and 

Structures Monitoring program are documented in SER Sections 3.0.3.2.16 and 3.0.3.2.19,

respectively. In its review of components associated with item 3.5.1-12, the staff finds that the 

applicant has met the further evaluation criteria and that the applicant’s proposal to manage the 

effects of aging using the ASME Section XI, Subsection IWL program and the Structures 

Monitoring program is acceptable because (1) the staff reviewed Section E.1 of UFSAR 

Appendix E and confirmed that concrete structures were constructed in accordance with 

ACI 318-71, (2) site operating experience has not identified degradation due to expansion from 

reaction with aggregates, and (3) ongoing periodic visual inspections by the ASME Section XI, 

Subsection IWL program and the Structures Monitoring program to detect cracking patterns

typical for this aging mechanism in accessible areas and from exposed portions of below-grade 

concrete, when it is excavated for any reason, will require the evaluation of the acceptability of 

inaccessible areas when conditions exist in accessible areas that could indicate the presence 

of, or could result in, degradation to such inaccessible areas.

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.5.2.2.1.8 criteria. For those items associated with LRA Section 3.5.2.2.1.8, 

the staff concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

Increase in Porosity and Permeability Due to Leaching of Calcium Hydroxide and Carbonation. 

LRA Section 3.5.2.2.1.9, associated with LRA Table 3.5.1, items 3.5.1-13 and 3.5.1-14, 

addresses inaccessible areas of concrete, including a wall, basemat, and buttress exposed to a 

water-flowing environment, which will be managed for increase in porosity and permeability and 

loss of strength due to leaching of calcium hydroxide and carbonation by the Structures 

Monitoring program. The criteria in SRP-LR Section 3.5.2.2.1.9 state that the GALL Report

recommends further evaluation if leaching is observed in accessible areas that impact the 

intended functions. The GALL Report states that a plant-specific AMP is not required if (1) there 

is evidence in the accessible areas that the flowing water has not caused leaching and 

carbonation or (2) an evaluation determined that the observed leaching of calcium hydroxide 
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and carbonation in accessible areas has no impact on the intended function of the concrete 

structure. The applicant addressed the further evaluation criteria of the SRP-LR by stating that 

no leaching has been observed in accessible areas of the primary containment that could have 

an impact on the intended function.

The applicant stated that item 3.5.1-13 is not applicable because the corresponding 

GALL Report items are not associated with the applicant’s BWR Mark II concrete containment 

structure type. The staff reviewed UFSAR Section 1.1 and confirmed that the applicant’s 

primary containments are designed as a BWR Mark II concrete containment. The staff 

evaluated the applicant’s claim and finds it acceptable because this aging effect is applicable to 

PWR steel containments, Mark II steel containments, or Mark III concrete containments in 

accordance with the GALL Report recommendations and because LSCS primary containments 

are a BWR Mark II concrete containment structure type.

The applicant stated that item 3.5.1-14 is applicable to the concrete wall, basemat, and 

buttresses in inaccessible areas of the Mark II primary containment exposed to a water-flowing 

environment. The applicant stated that LSCS has not observed any indication of significant 

leaching in accessible areas of the primary containment wall or basemat that could impact 

intended functions; therefore, a plant-specific program is not necessary.

The staff’s evaluation of the applicant’s Structures Monitoring program is documented in SER 

Section 3.0.3.2.19. The staff noted that the Structures Monitoring program is enhanced (license 

renewal Commitment No. 34, item 6) to include the monitoring for increase in porosity and 

permeability in concrete structures. The staff also noted that items in LRA Table 3.5.2-7,

associated with Table 1 item 3.5.1-20, addresses the accessible areas of concrete for this 

component, which will be managed for increase in porosity and permeability and loss of strength 

due to leaching of calcium hydroxide and carbonation by the ASME Section XI, Subsection IWL 

program. The staff notes that a plant-specific AMP is unnecessary because the LSCS operating 

experience did not identify any leaching in accessible areas of the primary containment that 

could have a significant impact on the intended function. In its review of components 

associated with item 3.5.1-14, the staff finds that the applicant has met the further evaluation 

criteria and that the applicant’s proposal to manage the effects of aging using the Structures 

Monitoring program is acceptable because periodic visual inspections by qualified personnel will 

detect indications of leaching and carbonation in accessible areas and because either the 

Structures Monitoring program or the ASME Section XI, Subsection IWL program will require 

the evaluation of the acceptability of inaccessible areas when conditions exist in accessible 

areas that could indicate the presence of, or could result in, degradation to such inaccessible 

areas.

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.5.2.2.1.9 criteria. For those items associated with LRA Section 3.5.2.2.1.9, 

the staff concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

Safety-Related and Other Structures and Component Supports

The staff reviewed LRA Section 3.5.2.2.2 against the criteria in SRP-LR Section 3.5.2.2.2, which 

address the following areas:
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Aging Management of Inaccessible Areas. The staff reviewed LRA Section 3.5.2.2.2.1, which 

addresses further evaluations recommended by SRP-LR Section 3.5.2.2.2.1 related to aging 

management of below-grade inaccessible areas of Groups 1 through 3, 5, and 7 through 9 

structures for aging effects as discussed below.

Item 1. LRA Section 3.5.2.2.2.1.1, associated with LRA Table 3.5.1, item 3.5.1-42, addresses 

below-grade inaccessible concrete areas of Groups 1 through 3 structures exposed to an

air-outdoor environment for plants located in moderate to severe weathering conditions, which 

will be managed for loss of material (spalling, scaling) and cracking due to freeze-thaw by the 

Structures Monitoring program. The LRA states that LSCS does not have Groups 5 and 7

through 9 structures with concrete inaccessible areas exposed to this environment. The criteria 

in SRP-LR Section 3.5.2.2.2.1, item 1, state that loss of material (spalling, scaling) and cracking 

due to freeze-thaw could occur for below-grade inaccessible concrete areas of Groups 1

through 3, 5, and 7 through 9 exposed to outdoor air and that the GALL Report recommends 

further evaluation to determine whether a plant-specific AMP is needed for plants located in 

moderate to severe weathering conditions. The SRP-LR also states that a plant-specific AMP is 

not required if documented evidence confirms that the existing concrete had air entrainment 

content between 3 and 8 percent and if subsequent inspection of accessible areas did not 

exhibit degradation related to freeze-thaw. The applicant addressed the further evaluation 

criteria of the SRP-LR by stating that the LSCS concrete requiring freeze-thaw resistance had 

air entrainment of 3 to 5 percent, which meets the GALL Report recommended air content 

requirement of between 3 and 8 percent, and the plant operating experience has not exhibited 

signs of aging effects related to freeze-thaw in accessible areas of Groups 1 through 3 concrete 

structures. The applicant further stated that the Structures Monitoring program will be used to 

manage this aging effect in both accessible and inaccessible areas by performing inspections of 

accessible areas and by using the condition of accessible and above-grade concrete as an 

indicator for the condition of inaccessible and below-grade concrete. The applicant further 

stated that, if degradation of concrete due to freeze-thaw is identified in accessible areas of the 

structures, the extent of condition will be determined and additional inspections or evaluations 

will be initiated to evaluate acceptability of inaccessible portions of structures. In addition, 

exposed portions of below-grade concrete will be examined by the enhanced Structures 

Monitoring program when it is excavated for any reason.

The staff’s evaluation of the applicant’s Structures Monitoring program is documented in SER 

Section 3.0.3.2.19. The staff reviewed UFSAR Section 3.8.4.6 and Appendix E, Section E.1, 

which indicate that concrete was specified in accordance with ACI 318-71 and ACI 301-72, and 

verified that appropriate air entrainment was used in the concrete mix design. The staff’s review 

of the operating experience did not identify any significant freeze-thaw-related concrete 

degradation for Groups 1 through 3 structures at LSCS; therefore, a plant-specific program to 

manage this aging effect is not necessary. Further, the staff noted that the applicant will use the 

enhanced Structures Monitoring program to monitor aging effects due to freeze-thaw for 

Groups 1 through 3 structures, which is the GALL Report-recommended program to manage 

this aging effect in accessible areas as indicated by SRP-LR Table 3.5-1, item 64, and LRA 

Table 3.5.1, item 3.5.1-64. In its review of components associated with LRA item 3.5.1-42, the 

staff finds that the applicant has met the further evaluation criteria and that the applicant’s 

proposal to manage the effects of aging using the enhanced Structures Monitoring program is 

acceptable because (1) the program is capable of monitoring and managing aging effects due to 

freeze-thaw by performing periodic visual inspections of accessible areas of Groups 1 through 

3 structures by qualified personnel at intervals not to exceed 5 years, (2) the program will use 

significant freeze-thaw degradation identified in accessible areas as the leading indicator to 
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evaluate the acceptability of the aging effect in inaccessible areas of affected structures in the 

corrective action program, and (3) a plant-specific program is not necessary.

Based on the evaluation provided and on the program identified, the staff determines that the 

applicant’s program meets the SRP-LR Section 3.5.2.2.2.1, item 1, criteria. For those items 

associated with LRA Section 3.5.2.2.2.1.1, the staff concludes that the LRA is consistent with 

the GALL Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended functions will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Item 2. LRA Section 3.5.2.2.2.1.2, associated with LRA Table 3.5.1, item 3.5.1-43, addresses 

cracking due to expansion from reaction with aggregates in inaccessible concrete areas 

exposed to any environment for structures of all groups, except for Group 6 structures. The 

criteria in SRP-LR Section 3.5.2.2.2.1, item 2, state that further evaluation is recommended to 

determine whether a plant-specific AMP is required to manage this aging effect. The SRP-LR 

also states that a plant-specific program is not required if (1) investigations, tests, and 

petrographic examination of aggregates performed in accordance with ASTM C295 and other 

ASTM reactivity tests, as required, can demonstrate that those aggregates do not adversely 

react within reinforced concrete or (2) for potentially reactive aggregates, aggregate concrete 

reaction is not significant if it can be demonstrated that the in-place concrete can perform its 

intended function. The applicant addressed the further evaluation criteria by stating that a

plant-specific program is not necessary to manage the aging effect and mechanism because the 

fine and coarse aggregates used in the concrete conform to ASTM C33, aggregates were 

screened for reactivity by tests performed in accordance with ASTM C227, and the aging 

effect/mechanism has not been observed on accessible portions of LSCS concrete structures. 

The applicant further stated that, nevertheless, the aging effect and mechanism is applicable to 

LSCS concrete structures because industry operating experience described in NRC IN 2011-20 

indicates that the older ASTM standards used during construction may not always be effective 

in identifying reactive aggregates and that these structures will be monitored by the Structures 

Monitoring program for cracking due to any mechanism, which includes expansion from reaction 

with aggregates, and by using conditions observed in accessible areas as the indicator of 

conditions at inaccessible areas. Additionally, the applicant stated that the program will also 

examine exposed portions of below-grade concrete when it is excavated for any reason.

The staff’s evaluation of the applicant’s Structures Monitoring program, which, with 

enhancements, will be consistent with GALL Report AMP XI.S6, is documented in SER 

Section 3.0.3.2.19. The staff noted that this enhanced AMP, as amended by the applicant’s 

response to RAI B.2.1.34-1, dated July 15, 2015, requires evaluation of the acceptability of 

inaccessible areas when conditions exist in accessible areas that could indicate the presence 

of, or could result in, degradation to such inaccessible areas. The staff noted that a 

plant-specific AMP is not necessary because the LSCS concrete structures were constructed to 

recommended ACI and ASTM standards that minimize the possibility of cracking due to 

alkali-aggregate reaction and because a review of the operating experience did not identify the 

aging effect/mechanism in accessible portions of LSCS concrete structures. The staff noted 

that the applicant proposed to use the Structures Monitoring program to effectively manage the 

aging effect, which is consistent with the GALL Report recommendation for this aging effect in 

accessible areas, as indicated in SRP-LR Table 3.5-1, item 54, and LRA Table 3.5.1, 

item 3.5.1-54. GALL Report AMP XI.S6 recommends using periodic visual inspections by 

qualified personnel, at an interval not to exceed 5 years, to manage the effects of aging. The 

staff finds that the applicant has met the further evaluation criteria and that the applicant’s 

proposal to manage the effects of aging using the Structures Monitoring program is acceptable 
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because (1) the program will manage cracking from expansion due to reaction with aggregates 

by performing periodic visual inspections of accessible areas of structures of all groups at 

intervals not to exceed 5 years, (2) the program will use conditions identified in accessible areas 

as the leading indicator to evaluate the acceptability of the aging effect in inaccessible areas of 

affected structures in the corrective action program, and (3) a plant-specific program is 

unnecessary.

Based on the evaluation provided and program identified, the staff determines that the 

applicant’s programs meet the SRP-LR Section 3.5.2.2.2.1, item 2, criteria. For those items 

associated with LRA Section 3.5.2.2.2.1.2, the staff concludes that the LRA is consistent with 

the GALL Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended functions will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Item 3. LRA Section 3.5.2.2.2.1.3, associated with LRA Table 3.5.1, item 3.5.1-44, addresses 

below-grade inaccessible concrete areas of structures of all groups of concrete founded on, and 

exposed to, groundwater and soil, which will be managed for cracking and distortion due to 

increased stress levels from settlement by the Structures Monitoring program. In addition, LRA 

Section 3.5.2.2.2.1.3, associated with LRA Table 3.5.1, items 3.5.1-45 and 3.5.1-46, addresses 

below-grade inaccessible concrete areas of Groups 1 through 3 and 5 through 9 structures 

exposed to water flowing under foundation, which will be managed for reduction of foundation 

strength and cracking due to differential settlement and erosion of porous concrete 

subfoundation. The criteria in SRP-LR Section 3.5.2.2.2.1, item 3, state that cracking and 

distortion due to increased stress levels from settlement could occur in below-grade 

inaccessible concrete areas of structures of all groups (exposed to soil), and reduction of 

foundation strength and cracking due to differential settlement and erosion of porous concrete 

subfoundations could occur in below-grade inaccessible concrete areas of Groups 1 through 3 

and 5 through 9 structures (exposed to water flowing under foundation). The SRP-LR states 

that the existing program relies on the Structures Monitoring program to manage these aging 

effects and that further evaluation is necessary if a dewatering system is relied on to control 

settlement to verify continued functioning of the dewatering system through the period of 

extended operation. The applicant addressed the further evaluation criteria of the SRP-LR for 

LRA item 3.5.1-44 by stating that LSCS structures do not rely on a dewatering system to control 

settlement and that, even though the aging effect has not been observed at LSCS, the 

Structures Monitoring program will be used to manage cracking and distortion due to any 

mechanism, including settlement, for structures founded on soil by evaluating the aging effects 

in inaccessible areas based on conditions found from inspection of accessible areas as the 

leading indicator. The applicant also stated that LSCS will examine exposed portions of 

below-grade concrete when it is excavated for any reason. The applicant also addressed the 

further evaluation criteria of the SRP-LR for LRA items 3.5.1-45 and 3.5.1-46 by stating that the 

aging effect is not applicable because LSCS structures are not founded on porous concrete 

subfoundations and do not rely on a dewatering system to control settlement.

The staff’s evaluation of the applicant’s Structures Monitoring program, which with 

enhancements will be consistent with GALL Report AMP XI.S6, is documented in SER 

Section 3.0.3.2.19. The staff reviewed UFSAR Sections 2.4.13, 2.5.4, and 3.8.5 and verified 

that dewatering systems are not relied on to control settlement; therefore, LRA Table 3.5.1, 

items 3.5.1-44 through 3.5.1-46, do not need further evaluation. The staff also noted that the 

LSCS structures are not founded on porous concrete subfoundations but are generally founded 

on silty clay. The staff evaluated the applicant’s claim that the aging effect for LRA Table 3.5.1, 

items 3.5.1-45 and 3.5.1-46, is not applicable and finds it acceptable because the staff verified 
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that the LSCS concrete structures are not founded on porous concrete subfoundation and do 

not rely on a dewatering system to control settlement. The staff also noted that the applicant’s 

proposal to continue use of the enhanced Structures Monitoring program to manage cracking 

and distortion due to increased stress levels from settlement, based on evaluating the aging 

effects in inaccessible concrete areas using conditions observed from visual inspections of 

accessible areas, is consistent with the GALL Report recommendation and, therefore, is

acceptable. In its review of components associated with LRA item 3.5.1-44, the staff finds that 

the applicant has met the further evaluation criteria and that the applicant’s proposal to manage 

the effects of aging using the Structures Monitoring program is acceptable because the staff 

verified that the LSCS structures do not rely on a dewatering system to control settlement and 

because the enhanced Structures Monitoring program proposed to manage the aging effect of 

cracking and distortion due to settlement is consistent with the GALL Report.

Based on the program identified, the staff determines that the applicant’s program meets the 

SRP-LR Section 3.5.2.2.2.1, item 3, criteria. For those items associated with LRA 

Section 3.5.2.2.2.1.3, the staff concludes that the LRA is consistent with the GALL Report and 

that the applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

Item 4. LRA Section 3.5.2.2.2.1.4 associated with LRA Table 3.5.1, item 3.5.1-47, addresses 

inaccessible concrete areas of Groups 1 through 3 and 5 structures (Groups 7 through 9 

structures not applicable to LSCS) that are exposed to flowing water, which will be managed for 

increase in porosity and permeability and loss of strength due to leaching of calcium hydroxide 

and carbonation by the Structures Monitoring program. The criteria in SRP-LR 

Section 3.5.2.2.2.1, item 4, state that increases in porosity and permeability and loss of strength 

due to leaching of calcium hydroxide and carbonation could occur in below-grade inaccessible 

areas of Group 1 through 5 and 7 through 9 concrete structures exposed to a water-flowing 

environment. The SRP-LR also states that further evaluation is required to determine whether a 

plant-specific AMP is needed to manage increases in porosity and permeability due to leaching 

of calcium hydroxide and carbonation of inaccessible concrete areas and that a plant-specific 

AMP is not required if (1) there is evidence in the accessible areas that the flowing water has 

not caused leaching and carbonation or (2) an evaluation determined that the observed leaching 

of calcium hydroxide and carbonation in accessible areas has no impact on the intended 

function of the concrete structure. The applicant addressed the further evaluation criteria of the 

SRP-LR by stating that LSCS concrete structures are designed and constructed in accordance 

with ACI standards to produce durable concrete that is resistant to leaching. The applicant also 

stated that the effects of carbonation have not been observed on LSCS concrete, although 

some leaching has been observed in the accessible areas; that they are not significant; and that 

they have not impacted the intended functions. The applicant concluded that increases in 

porosity and permeability and loss of strength due to leaching and carbonation are adequately 

managed by the Structures Monitoring program by visual inspection of accessible areas and 

exposed portions of inaccessible areas when these areas are excavated for any reason, by 

periodic groundwater testing, and by evaluation of aging effects in inaccessible areas based on 

conditions found in accessible areas.

The staff’s evaluation of the applicant’s Structures Monitoring program, which, with 

enhancements, will be consistent with GALL Report AMP XI.S6, is documented in SER 

Section 3.0.3.2.19. The staff noted that the applicant’s proposal to continue use of the 

enhanced Structures Monitoring program to manage the aging effect, based on evaluating the 

aging effects in inaccessible concrete areas using conditions observed from visual inspections 
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of accessible areas, is consistent with the GALL Report recommendation for accessible areas 

(LRA Table 3.5.1, item 3.5.1-63) and, therefore, is acceptable. In its review of components 

associated with item 3.5.1-47, the staff finds that the applicant has met the further evaluation 

criteria and that the applicant’s proposal to manage the effects of aging using the Structures 

Monitoring program is acceptable because this program is the GALL Report-recommended 

program for managing the aging effects by visual inspection of accessible areas and by 

evaluation of inaccessible concrete areas based on conditions found in accessible areas, and 

because LSCS does not have operating experience of significant leaching or carbonation that 

would affect the intended function of the structure, an additional plant-specific program is not 

necessary.

Based on the evaluation provided and the program identified, the staff determines that the 

applicant’s program meets the SRP-LR Section 3.5.2.2.2.1, item 4, criteria. For those items 

associated with LRA Section 3.5.2.2.2.1.4, the staff concludes that the LRA is consistent with 

the GALL Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended functions will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Reduction of Strength and Modulus Due to Elevated Temperature. LRA Section 3.5.2.2.2.2,

associated with LRA Table 3.5.1, item 3.5.1-48, addresses reduction of strength and modulus of 

concrete due to elevated temperatures in Groups 1 through 5 concrete structures exposed to an 

air-indoor uncontrolled environment. The criteria in SRP-LR Section 3.5.2.2.2.2 state that the 

GALL Report recommends further evaluation of a plant-specific program if any portion of the 

safety-related and other concrete structures exceeds specified temperature limits (i.e., general 

area temperature greater than 150 °F and local area temperature greater than 200 °F). The 

GALL Report states that higher temperatures may be allowed if tests and/or calculations are 

provided to evaluate the reduction in strength and modulus of elasticity and if these reductions 

are applied to the design calculations. The applicant stated that this item is not applicable 

because the average temperature for these groups of structures does not exceed 135 oF and 

because local temperatures in excess of 200 oF have not been reported at LSCS. The applicant 

also stated that process piping that operates at temperatures greater than 200 oF is insulated 

through penetrations and is combined with compartment air circulation to reduce concrete local

temperature to less than 200 oF. The staff evaluated the applicant’s claim and finds it 

acceptable because the staff reviewed UFSAR Subsections 6.2.1.1.2, 3.8.1.1.3.5, and 9.4 and 

confirmed that (1) a primary containment ventilation system maintains the general area 

temperatures for Group 4 structures below the threshold from the GALL Report during normal 

operation, (2) other groups of structures maintain their general area temperatures below the 

threshold from the GALL Report using other normal ventilation systems, and (3) the design of 

the penetration sleeves provides insulation, air gaps, and cooling coil systems to reduce thermal 

stress in the concrete during normal operations. Additionally, the staff’s review of site operating 

experiences during the AMP audit did not identify plant conditions where general or local areas

temperatures have exceeded the threshold from the GALL Report. Therefore, a plant-specific 

AMP is not required, and further evaluation of this aging effect is not necessary.

Aging Management of Inaccessible Areas for Group 6 Structures

Item 1. LRA Section 3.5.2.2.2.3.1 associated with LRA Table 3.5.1, item 3.5.1-49, addresses 

inaccessible concrete areas of Group 6 structures exposed to an air-outdoor environment for 

plants located in moderate to severe weathering conditions, which will be managed for loss of 

material and cracking due to freeze-thaw by the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants program. The criteria in SRP-LR 
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Section 3.5.2.2.2.3, item 1, state that loss of material (spalling, scaling) and cracking due to 

freeze-thaw could occur for below-grade inaccessible concrete areas of Group 6 structures and 

recommends further evaluation to determine the need for a plant-specific program for plants 

located in moderate to severe weathering conditions. The SRP-LR also states that a 

plant-specific program is not required if documented evidence confirms that the existing 

concrete had air entrainment content between 3 and 8 percent and if subsequent inspection of 

accessible areas did not exhibit degradation related to freeze-thaw. The applicant addressed 

the further evaluation criteria of the SRP-LR by stating that the LSCS concrete requiring 

freeze-thaw resistance meets the air content requirement of between 3 and 8 percent and that 

plant operating experience has not identified significant aging effects related to freeze-thaw in 

accessible areas of Groups 6 concrete structures. The applicant also stated that the existing 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

program, with enhancements, will be used to manage this aging effect in an air-outdoor 

environment. The applicant further stated that the condition of accessible and above-grade 

concrete will be used as the leading indicator for the condition of inaccessible areas and that, if 

degradation of concrete due to freeze-thaw is identified in accessible areas of the structures, 

corrective action will be initiated to evaluate acceptability of the aging effect in inaccessible 

portions of affected structures in the corrective action program. The applicant also stated that 

exposed portions of the below-grade concrete will be examined when excavated for any reason.

The staff’s evaluation of the applicant’s RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants program, which, with enhancements, will be consistent 

with GALL Report AMP XI.S7, is documented in SER Section 3.0.3.2.20. The staff reviewed 

UFSAR Section 3.8.4.6 and Appendix E, Section E.1, which indicate that concrete was specified 

in accordance with ACI 318-71 and ACI 301-72, and verified that appropriate air entrainment 

was used in the concrete mix design. The staff’s review of the applicant’s operating experience 

did not identify significant freeze-thaw related concrete degradation; therefore, a plant-specific 

program to manage this aging effect is not necessary. The staff noted that the applicant’s 

enhanced RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants program will be used to manage this aging effect for Group 6 concrete structures. In its 

review of components associated with LRA item 3.5.1-49, the staff finds that the applicant has 

met the further evaluation criteria and that the applicant’s proposal to manage the effects of 

aging using the enhanced RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants program is acceptable because (1) the enhanced program will monitor 

and manage aging effects due to freeze-thaw of Group 6 structures by periodic visual 

inspections of accessible areas, (2) the program will use significant freeze-thaw degradation 

identified in accessible areas as the leading indicator to evaluate the acceptability of the aging 

effect in inaccessible areas, and (3) a plant-specific program is not necessary.

Based on the program identified, the staff determines that the applicant’s program meets the 

SRP-LR Section 3.5.2.2.3.1, item 1, criteria. For those items associated with LRA 

Section 3.5.2.2.2.3.1, the staff concludes that the LRA is consistent with the GALL Report and 

that the applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

Item 2. LRA Section 3.5.2.2.2.3.2, associated with LRA Table 3.5.1, item 3.5.1-50, addresses 

cracking due to expansion from reaction with aggregates in below-grade inaccessible concrete 

areas of Group 6 structures exposed to any environment. The criteria in SRP-LR 

Section 3.5.2.2.2.3.2 state that further evaluation is recommended to determine whether a 

plant-specific AMP is required to manage this aging effect. The SRP-LR also states that a 
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plant-specific program is not required if (1) investigations, tests, and petrographic examination 

of aggregates performed in accordance with ASTM C295 and other ASTM reactivity tests, as 

required, can demonstrate that those aggregates do not adversely react within concrete or 

(2) for potentially reactive aggregates, aggregate concrete reaction is not significant if it is 

demonstrated that the in-place concrete can perform its intended function. The applicant 

addressed the further evaluation criteria by stating that a plant-specific program is not 

necessary to manage the aging effect and mechanism because the fine and coarse aggregates 

used in the concrete conform to ASTM C33, aggregates were screened for reactivity by tests 

performed in accordance with ASTM C227, and the aging effect/mechanism has not been 

observed on accessible portions of LSCS Group 6 concrete structures. The applicant further 

stated that, nevertheless, the aging effect and mechanism is applicable to LSCS concrete 

structures because industry operating experience described in NRC IN 2011-20 indicates that 

the older ASTM standards used during construction may not always be effective in identifying 

reactive aggregates and that these structures will be monitored within the RG 1.127, Inspection 

of Water-Control Structures Associated with Nuclear Power Plants program (implemented as 

part of Structures Monitoring program) by monitoring cracking due to any mechanism, which 

includes expansion from reaction with aggregates, and by using conditions observed in 

accessible areas as the indicator of conditions at inaccessible areas. Additionally, the applicant 

stated that the program will also examine exposed portions of below-grade concrete when 

excavated for any reason.

The staff’s evaluation of the applicant’s RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Plants program and Structures Monitoring program, which, with 

enhancements, will be consistent with GALL Report AMP XI.S7 and AMP XI.S6, respectively, is 

documented in SER Sections 3.0.3.2.20 and 3.0.3.2.19, respectively. The staff noted that the 

enhanced RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Plants 

program and the Structures Monitoring program require evaluation of the acceptability of 

inaccessible areas when conditions exist in accessible areas that could indicate the presence 

of, or could result in, degradation to such inaccessible areas. The staff noted that a 

plant-specific AMP is not necessary because the LSCS concrete structures were constructed to 

recommended ACI and ASTM standards that minimize the possibility of cracking due to 

alkali-aggregate reaction and because review of the operating experience did not identify the 

aging effect/mechanism in accessible portions of LSCS Group 6 concrete structures. The staff 

noted that the applicant proposed to use the Structures Monitoring program to manage the 

aging effect in accessible areas for all structures groups, including Group 6 as indicated in LRA 

Table 3.5.1, item 3.5.1-54, which is considered consistent with the GALL Report

recommendation for this aging effect in accessible areas because the GALL Report, 

inadvertently, did not identify an AMP for accessible areas of Group 6 structures. GALL Report

AMP XI.S6 and AMP XI.S7 recommend using periodic visual inspections by qualified personnel, 

at an interval not to exceed 5 years, to manage the effects of aging. The staff finds that the 

applicant has met the further evaluation criteria and that the applicant’s proposal to manage the 

effects of aging in inaccessible areas using the RG 1.127, Inspection of Water-Control

Structures Associated with Nuclear Plants program and Structures Monitoring program is 

acceptable because (1) the program will manage cracking from expansion due to reaction with 

aggregates by performing periodic visual inspections of accessible areas of Group 6 structures 

at intervals not to exceed 5 years, (2) the program will use conditions identified in accessible 

areas as the leading indicator to evaluate the acceptability of the aging effect in inaccessible 

areas of affected structures in the corrective action program, and (3) a plant-specific program is 

not necessary.
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Based on the evaluation provided and on the program identified, the staff determines that the 

applicant’s programs meet the SRP-LR Section 3.5.2.2.2.3, item 2, criteria. For those items 

associated with LRA Section 3.5.2.2.2.3.2, the staff concludes that the LRA is consistent with 

the GALL Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended functions will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Item 3. LRA Section 3.5.2.2.2.3.3, associated with LRA Table 3.5.1, item 3.5.1-51, addresses 

inaccessible concrete areas of Groups 6 structures exposed to a water-flowing environment,

which will be managed for increase in porosity and permeability and loss of strength due to 

leaching of calcium hydroxide and carbonation by the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants program. The criteria in SRP-LR 

Section 3.5.2.2.2.3, item 3, state that increases in porosity and permeability and loss of strength 

due to leaching of calcium hydroxide and carbonation could occur in below-grade inaccessible 

concrete areas of Group 6 concrete structures. The SRP-LR also states that further evaluation 

is required if leaching is observed in accessible areas that impact intended functions. The 

SRP-LR also states that further evaluation is required to determine whether a plant-specific 

AMP is needed to manage the aging effect and that a plant-specific program is not required for 

the concrete exposed to water-flowing environment if (1) there is evidence in the accessible 

areas that the flowing water has not caused leaching and carbonation or (2) an evaluation 

determined that the observed leaching of calcium hydroxide and carbonation in accessible 

areas has no impact on the intended function of the concrete structure. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that LSCS concrete structures 

are designed and constructed in accordance with ACI standards to produce durable concrete

that is resistant to leaching. The applicant stated that the effects of carbonation have not been 

observed on LSCS concrete. The applicant also stated that the groundwater and cooling lake 

water chemistry at the site is not aggressive and that, although some leaching has been 

observed in the accessible areas, it is not significant and has not impacted intended functions. 

The applicant concluded that the operating experience indicates that the observed leaching has 

had no significant impact on the intended function of the concrete structure and that the effects 

of leaching and carbonation are adequately managed by the enhanced RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants program by (1) visual 

inspection of accessible and submerged concrete areas and exposed portions of inaccessible 

areas when these areas are excavated for any reason, (2) periodic testing of groundwater and 

raw water chemistry, and (3) evaluation of aging effects in inaccessible areas based on 

conditions found in accessible areas.

The staff’s evaluation of the applicant’s RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Plants program is documented in SER Section 3.0.3.2.20. This 

program, with enhancements, will be consistent with GALL Report AMP XI.S7. The staff noted 

that the operating experience at LSCS did not identify significant aging effects of degradation 

due to leaching and carbonation; therefore, a plant-specific AMP is not necessary to manage 

this aging effect. Further, the staff noted that the enhanced RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants program, implemented as part 

of the Structures Monitoring program, will be used to manage this aging effect for Group 6 

concrete structures. In its review of components associated with item 3.5.1-51, the staff finds 

that the applicant has met the further evaluation criteria and that the applicant’s proposal to 

manage the effects of aging using the enhanced RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants program is acceptable because this program 

is capable of effectively monitoring and managing these aging effects by (1) performing visual 

inspection of accessible areas every 5 years, and exposed portions of inaccessible areas on an 
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opportunistic basis, and (2) evaluating inaccessible concrete areas based on conditions found in 

accessible areas as the leading indicator. In addition, because LSCS does not have operating 

experience of significant leaching or carbonation that would affect the intended function of the 

structure, an additional plant-specific program is not necessary.

Based on the programs identified, the staff determines that the applicant’s programs meet the 

SRP-LR Section 3.5.2.2.3.3, item 3, criteria. For those items associated with LRA 

Section 3.5.2.2.2.3.3, the staff concludes that the LRA is consistent with the GALL Report and 

that the applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

Cracking Due to Stress Corrosion Cracking and Loss of Material Due to Pitting and Crevice 

Corrosion. LRA Section 3.5.2.2.2.4, associated with LRA Table 3.5.1, item 3.5.1-52, addresses 

cracking due to SCC and loss of material due to pitting and crevice corrosion in stainless steel 

liners of other components, such as the drywell sump, reactor building sump, and turbine 

building sump, exposed to a fluid environment. The criteria in SRP-LR Section 3.5.2.2.2.4 state 

that cracking due to SCC and loss of material due to pitting and crevice corrosion could occur 

for Group 7 and Group 8 stainless steel tank liners exposed to standing water. The SRP-LR

also states that the GALL Report recommends further evaluation of plant-specific programs to 

manage these aging effects for stainless steel tank liners exposed to standing water. The 

applicant stated that this item is not applicable because LSCS does not have Group 7 and 

Group 8 stainless steel tank liners exposed to standing water. The GALL Report recommends a

plant-specific program be evaluated to ensure that these aging effects are adequately managed; 

however, the staff notes that the applicant does not have any tanks with stainless steel liners 

included as structures within the scope of license renewal. Therefore, no plant-specific program 

is needed.

Cumulative Fatigue Damage Due to Fatigue. LRA Section 3.5.2.2.2.5, associated with LRA 

Table 3.5.1, item 3.5.1-53, addresses fatigue in component support members, anchor bolts, and 

welds for Groups B1.1, B1.2, and B1.3 component supports. The criteria in SRP-LR 

Section 3.5.2.2.2.5 state that fatigue of these components is a TLAA only if a CLB fatigue 

analysis exists. The applicant stated that this item is not applicable because the CLB at LSCS

does not contain fatigue analyses for support members, bolted connections, or supported 

anchorage to building structures. The staff evaluated the applicant’s claim and finds it 

acceptable because the staff reviewed the UFSAR and did not identify any fatigue analyses for 

these components.

Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program.

Ongoing Review of Operating Experience

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience of AMPs.
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3.5.2.3 AMR Results Not Consistent with or Not Addressed in the GALL

In LRA Tables 3.5.2-1 through 3.5.2-14, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations that are not consistent with or are not 

addressed in the GALL Report.

In LRA Tables 3.5.2-1 through 3.5.2-14, the applicant indicated, through notes F through J, that 

the combination of the component type, material, environment, and AERM does not correspond 

to an item in the GALL Report. The applicant provided further information on how it will manage 

the aging effects. Specifically, note F indicates that the material for the AMR item component is 

not evaluated in the GALL Report. Note G indicates that the environment for the AMR item

component and material is not evaluated in the GALL Report. Note H indicates that the aging 

effect for the AMR item component, material, and environment combination is not evaluated in 

the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the 

item component, material, and environment combination is not applicable. Note J indicates that 

neither the component nor the material and environment combination for the item is evaluated in 

the GALL Report.

For component type, material, and environment combinations that are not evaluated in the 

GALL Report, the staff reviewed the applicant’s evaluation to determine whether the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. 

The staff’s evaluation is documented in the following sections.

Auxiliary Building – Summary of Aging Management Evaluation –

LRA Table 3.5.2-1

The staff reviewed LRA Table 3.5.2-1, which summarizes the results of AMR evaluations for the 

Auxiliary Building component groups. The staff’s review did not identify any AMR items with 

notes F through J, indicating that the combinations of component type, material, environment, 

and AERM for the Auxiliary Building component groups are consistent with the GALL Report.

Component Supports Commodity Group – Summary of Aging Management 

Evaluation – LRA Table 3.5.2-2

The staff reviewed LRA Table 3.5.2-2, which summarizes the results of AMR evaluations for the 

Component Supports Commodity Group component groups. The staff’s review did not identify 

any AMR items with notes F through J, indicating that the combinations of component type, 

material, environment, and AERM for the Component Supports Commodity Group component 

groups are consistent with the GALL Report.

Cooling Lake – Summary of Aging Management Evaluation – LRA Table 3.5.2-3

The staff reviewed LRA Table 3.5.2-3, which summarizes the results of AMR evaluations for the 

Cooling Lake component groups.

Soil, Rip-Rap, Sand, and Gravel of Earthen Water-Control Structures Exposed to an 

Air-Outdoor Environment. In LRA Table 3.5.2-3, the applicant stated that soil, rip-rap, sand, and 

gravel of earthen water-control structures (i.e., the intake flume and submerged core standby 

cooling system pond) exposed to an air-outdoor environment will be managed for loss of 

material and loss of form by the RG 1.127, Inspection of Water-Control Structures Associated 
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with Nuclear Power Plants program. The AMR items cite generic note G. The AMR items also 

cite plant-specific note 1, which states that the aging effect for this component, material, and 

environment combination is not in the GALL Report; however, the RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants program will be used to 

manage this component’s aging effect.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff reviewed a U.S. Society on Dams report titled,

“The Aging of Embankment Dams,” dated 2010, which states that “erosion on the downstream 

slope and crest may be due to heavy direct rainfall or surface water runoff, brief crest 

overtopping, wave spray over a wave wall or wind driven wave spray,” and that “[surface] 

erosion on the upstream slope may be due to wave action on too small riprap or inadequate 

bedding, breakdown of riprap or freeze-thaw displacement.” Based on its review of this report,

which further states that “surface erosion is readily detected by routine visual inspection,” the 

staff finds that the applicant has identified all credible aging effects for this component, material, 

and environment combination.

The staff’s evaluation of the applicant’s RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants program is documented in SER Section 3.0.3.2.20. The 

staff notes that managing for loss of material and loss of form is equivalent to managing surface 

erosion and that these aging effects are readily detectible by visual inspections. The staff finds 

the applicant’s proposal to manage the effects of aging using the RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants program acceptable because 

the program provides for periodic visual inspections at least once every 5 years and 

immediately following the occurrence of significant natural phenomena, which is consistent with 

the visual inspection frequency recommended in GALL Report AMP XI.S7 and determined to be 

adequate to detect aging effects in earthen water-control structures before the loss of 

component’s intended function.

Diesel Generator Building – Summary of Aging Management Evaluation –

LRA Table 3.5.2-4

The staff reviewed LRA Table 3.5.2-4, which summarizes the results of AMR evaluations for the 

Diesel Generator Building component groups. The staff’s review did not identify any AMR items 

with notes F through J, indicating that the combinations of component type, material,

environment, and AERM for the Diesel Generator Building component groups are consistent 

with the GALL Report.

Lake Screen House – Summary of Aging Management Evaluation –

LRA Table 3.5.2-5

The staff reviewed LRA Table 3.5.2-5, which summarizes the results of AMR evaluations for the 

Lake Screen House component groups.

Reinforced Concrete of Lake Screen House Interior Exposed to a Water-Flowing Environment. 

In LRA Table 3.5.2-5, the applicant stated that reinforced concrete in the Lake Screen House 

interior exposed to a water-flowing environment will be managed for cracking, loss of bond, and 

loss of material (spalling, scaling) by the RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants program. The AMR items cite generic note H. The AMR 

items also cite plant-specific note 2, which states that the aging effect for this component, 
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material, and environment combination is not in the GALL Report; however, the RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants program will be 

used to manage this component’s aging effect.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that concrete exposed to a water-flowing environment is susceptible to increases in 

porosity and permeability, loss of strength due to leaching of calcium hydroxide and 

carbonation, and loss of material due to abrasion or cavitation and recommends GALL Report

AMP XI.S7 to manage the aging effects. However, the applicant has identified cracking and 

loss of bond as additional aging effects. The applicant addressed the GALL Report identified 

aging effects for this component, material, and environment combination in other AMR items in 

LRA Table 3.5.2-5 (i.e., items corresponding to Table 1, items 3.5.1-56 and 3.5.1-61).

The staff’s evaluation of the applicant’s RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants program is documented in SER Section 3.0.3.2.20. The 

staff noted that the applicant implements the RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants program as part of the Structures Monitoring program to 

manage these aging effects for water-control structures by performing periodic visual inspection 

at least once every 5 years. The staff finds the applicant’s proposal to manage cracking, loss of 

bond, and loss of material (spalling, scaling) using the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants program acceptable because the program 

provides for periodic visual inspections at least once every 5 years and immediately following 

the occurrence of significant natural phenomena to manage the aging effects (i.e., increases in 

porosity and permeability, loss of strength, and loss of material) in the GALL Report and 

additional plant-specific aging effects (i.e., cracking and loss of bond) for concrete in 

water-control structures exposed to a water-flowing environment, which is consistent with the 

visual inspection frequency recommended in the GALL Report AMP determined to be adequate 

to detect aging effects before there is a loss of a component’s intended function.

Offgas Building – Summary of Aging Management Evaluation – LRA Table 3.5.2-6

The staff reviewed LRA Table 3.5.2-6, which summarizes the results of AMR evaluations for the 

Offgas Building component groups. The staff’s review did not identify any AMR items with 

notes F through J, indicating that the combinations of component type, material, environment, 

and AERM for the Offgas Building component groups are consistent with the GALL Report.

Primary Containment – Summary of Aging Management Evaluation –

LRA Table 3.5.2-7

The staff reviewed LRA Table 3.5.2-7, which summarizes the results of AMR evaluations for the 

Primary Containment component groups.

Carbon Steel Sliding Surfaces (Support) Exposed to an Air-Indoor Uncontrolled Environment. 

In LRA Table 3.5.2-7, the applicant stated that the carbon steel sliding surfaces support 

exposed to an air-indoor uncontrolled environment will be managed for loss of mechanical 

function by the Structures Monitoring program. The AMR item cites generic note F. The AMR 

item also cites plant-specific note 9, which states that the sliding supports and bearings for 

drywell steel beams do not use Lubrite or a similar material but are instead steel to steel 

connections.
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The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant addressed the loss of 

material aging effect for this component, material, and environment combination in other AMR 

items in LRA Table 3.5.2-7. Based on its review of GALL Report Section IX.E, which states that 

loss of mechanical function in components, such as sliding steel surfaces, can occur through 

the combined influence of a number of aging mechanisms that include corrosion, distortion, dirt, 

overload, fatigue due to vibratory and cyclic thermal loads, or elastomer hardening, the staff 

finds that the applicant has identified all credible aging effects for this component, material, and 

environment combination.

The staff’s evaluation of the applicant’s Structures Monitoring program is documented in SER 

Section 3.0.3.2.19. The staff noted that the Structures Monitoring program proposes to manage 

the effects of aging loss of material due to wear or corrosion, debris, or dirt for sliding surfaces 

through the use of periodic visual inspections (Commitment No. 34). The staff finds the 

applicant’s proposal to manage the effects of aging using the Structures Monitoring program 

acceptable because the AMP will monitor sliding surfaces for excessive loss of material due to 

wear or corrosion, debris, or dirt and, therefore, will manage loss of mechanical function to 

ensure that no debris or dirt could restrict or prevent sliding of the surfaces as required by 

design, consistent with the GALL Report recommendations.

Concrete (Interior) in Primary Containment Components Encased in Steel. In LRA 

Table 3.5.2-7, the applicant stated that, for concrete (interior) in primary containment

components, including the pedestal, suppression pool columns, and reactor shield wall, that are 

encased in steel, there is no aging effect and that no AMP is proposed. The AMR items cite 

generic note G. The AMR items also cite plant-specific note 1, which states that the 

environment “encased in steel” protects concrete from other environments that promote 

age-related degradation.

The staff reviewed the associated items in the LRA to confirm that no credible aging effects are 

applicable for this component, material, and environmental combination. The staff finds the 

applicant’s proposal acceptable because (1) the concrete component is protected by the steel 

encasement from the environments that could cause age-related degradation to occur in the 

concrete and, therefore, exhibits no AERMs and (2) periodic visual inspections to detect loss of 

material of the steel components that encase the pedestal, suppression pool columns, and 

reactor shield wall are performed by the Structures Monitoring program and the ASME

Section XI, Subsection IWE program per the LRA Table 3.5.2-7 items corresponding to Table 1, 

items 3.5.1-37 and 3.5.1-77.

Fiberglass Components of Permanent Drywell Shielding Exposed to an Air-Indoor Uncontrolled 

Environment. In LRA Table 3.5.2-7, the applicant stated that the fiberglass components of 

permanent drywell shielding exposed to an air-indoor uncontrolled environment will be managed 

for changes in material properties (defined by the applicant as rips and tears by plant-specific 

note 3, as described below) by the Structures Monitoring program. The AMR item cites generic 

note J. The AMR item also cites plant-specific note 3, which states that lead shielding in an 

air-indoor uncontrolled environment has no applicable AERMs; however, the fiberglass blanket 

covers will be inspected by the Structures Monitoring program for rips and tears.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment (air-indoor environment subject to radiation and thermal exposure) 
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description. The staff notes that the fiberglass covers used in the nuclear industry for lead 

shielding blankets are made of silicon-impregnated fiberglass fabric designed for the 

high-temperature environment in the drywell. Visual inspections are used to ensure that the 

function of the lead shielding blankets are maintained by identifying breaches in the fiberglass 

covers. The staff finds that the applicant has identified all credible aging effects for this 

component, material, and environment combination.

The staff’s evaluation of the applicant’s Structures Monitoring program is documented in SER 

Section 3.0.3.2.19. The staff noted that the Structures Monitoring program proposes to manage 

the effects of aging through the use of periodic visual inspections at intervals not to exceed 

5 years. The staff also noted that enhancement 10 (Commitment No. 34, item 10), as amended 

by the applicant’s response letter dated July 15, 2015, to RAI B.2.1.34-2, states that the 

Structures Monitoring program will be enhanced to inspect the fiberglass outer covering for the 

permanent drywell shielding for signs of rips and tears; if a rip or tear is found, the permanent 

drywell shielding will be repaired or replaced. The staff finds the applicant’s proposal to manage 

the effects of aging using the Structures Monitoring program acceptable because the program’s 

visual inspections are capable of detecting rips and tears and, therefore, will adequately identify 

and manage degradation in fiberglass covers of the permanent drywell shielding before the loss 

of its intended function.

Lead Shielding Exposed to Uncontrolled Indoor Air. In LRA Tables 3.5.2-7, 3.5.2-9, 

and 3.5.2-10, the applicant stated that, for lead shielding exposed to an uncontrolled indoor air 

environment, there is no aging effect and that no AMP is proposed. The AMR items cite generic 

note J.

The staff reviewed the associated items in the LRA to confirm that no credible aging effects are 

applicable for this component, material, and environmental combination. The staff finds the 

applicant’s proposal acceptable based on its review of the Handbook of Corrosion Data, dated 

1989, which states that “lead is highly resistant [to corrosion] in atmospheric exposures ... lead 

exhibits consistent durability in all types of atmospheres, including rural, industrial and marine.”

Service Level I Coating (Containment Boundary and Internal Structures) Exposed to Treated 

Water. In LRA Table 3.5.2-7, the applicant stated that Service Level I coating exposed to 

treated water will be managed for loss of coating integrity by the Protective Coating Monitoring 

and Maintenance Program. The AMR items cite generic note G. The AMR items cite 

plant-specific note 6, which states that the Protective Coating Monitoring and Maintenance 

Program is the applicable AMP for this component, material, environment, and aging effect 

combination.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant addressed loss of 

coating integrity for this component, material, and environment combination in other AMR items 

in LRA Table 3.5.2-7. Based on its review of GALL Report AMP XI.S8, which states that all 

readily accessible Service Level I coatings should be periodically inspected to prevent loss of 

material, the staff finds that the applicant has identified all credible aging effects for this 

component, material, and environment combination.

The staff’s evaluation of the applicant’s Protective Coating Monitoring and Maintenance 

Program is documented in SER Section 3.0.3.1.16. The staff finds the applicant’s proposal to 

manage the effects of aging using the Protective Coating Monitoring and Maintenance Program
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acceptable because the program includes coating system selection, application, inspection, 

assessment, maintenance, and repair for any condition that adversely affects the ability of 

Service Level I coatings to function as intended.

Radwaste Building – Summary of Aging Management Evaluation –

LRA Table 3.5.2-8

The staff reviewed LRA Table 3.5.2-8, which summarizes the results of AMR evaluations for the 

Radwaste Building component groups. The staff’s review did not identify any AMR items with 

notes F through J, indicating that the combinations of component type, material, environment, 

and AERM for the Radwaste Building component groups are consistent with the GALL Report.

Reactor Building – Summary of Aging Management Evaluation – LRA Table 3.5.2-9

The staff reviewed LRA Table 3.5.2-9, which summarizes the results of AMR evaluations for the 

Reactor Building component groups.

Lead Shielding Exposed to Uncontrolled Indoor Air. The staff’s evaluation for lead shielding 

exposed to an uncontrolled indoor air environment, with no aging effect and associated with 

generic note J, is documented in SER Section 3.5.2.3.7.

Structural Commodity Group – Summary of Aging Management Evaluation –

LRA Table 3.5.2-10

The staff reviewed LRA Table 3.5.2-10, which summarizes the results of AMR evaluations for 

the Structural Commodity Group.

Elastomers Exposed to Condensation. In LRA Table 3.5.2-10, the applicant stated that foamed 

plastic and polymer thermal insulation exposed to uncontrolled indoor air is subject to reduced 

thermal insulation resistance. The AMR items cite generic note F, and plant-specific note 1, 

which states that foamed plastic, polymer, and other insulation and insulation sealant materials 

are potentially subject to reduced thermal insulation resistance due to moisture intrusion. 

Plant-specific note 1 further states that the potential aging effect will be managed by the 

External Surfaces Monitoring of Mechanical Components program.

The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical 

Components program is documented in SER Section 3.0.3.1.12. The staff finds the applicant’s 

proposal to monitor any potential aging effect using the External Surfaces Monitoring of 

Mechanical Components program acceptable because the periodic visual inspections 

conducted by the program are capable of detecting moisture intrusion on the subject 

components.

Lead Shielding Exposed to Uncontrolled Indoor Air. The staff’s evaluation for lead shielding 

exposed to an uncontrolled indoor air environment, with no aging effect and associated with 

generic note J, is documented in SER Section 3.5.2.3.7.

Switchyard Structures – Summary of Aging Management Evaluation –

LRA Table 3.5.2-11

The staff reviewed LRA Table 3.5.2-11, which summarizes the results of AMR evaluations for 

the Switchyard Structures component groups. The staff’s review did not identify any AMR items 
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with notes F through J, indicating that the combinations of component type, material,

environment, and AERM for the Switchyard Structures component groups are consistent with 

the GALL Report.

Tank Foundations and Dikes – Summary of Aging Management Evaluation –

LRA Table 3.5.2-12

The staff reviewed LRA Table 3.5.2-12, which summarizes the results of AMR evaluations for 

the Tank Foundations and Dikes component groups. The staff’s review did not identify any

AMR items with notes F through J, indicating that the combinations of component type, material,

environment, and AERM for the Tank Foundations and Dikes component groups are consistent 

with the GALL Report.

Turbine Building – Summary of Aging Management Evaluation –

LRA Table 3.5.2-13

The staff reviewed LRA Table 3.5.2-13, which summarizes the results of AMR evaluations for 

the Turbine Building component groups. The staff’s review did not identify any AMR items with 

notes F through J, indicating that the combinations of component type, material, environment, 

and AERM for the Turbine Building component groups are consistent with the GALL Report.

Yard Structures – Summary of Aging Management Evaluation – LRA Table 3.5.2-14

The staff reviewed LRA Table 3.5.2-14, which summarizes the results of AMR evaluations for 

the Yard Structures component groups. The staff’s review did not identify any AMR items with 

notes F through J, indicating that the combinations of component type, material, environment, 

and AERM for the Yard Structures component groups are consistent with the GALL Report.

3.5.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the structures and component supports components and commodity 

groups within the scope of license renewal and subject to an AMR will be adequately managed 

so that the intended function(s) will be maintained consistent with the CLB for the period of 

extended operation, as required by 10 CFR 54.21(a)(3).

3.6 Aging Management of Electrical Components

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

following Electrical commodity groups:

• Cable Connections (Metallic Parts)

• Electric Penetrations

• High Voltage Insulators

• Insulation Material for Electrical Cables and Connections

• Metal Enclosed Bus

• Switchyard Bus and Connections, Transmission Conductors, and Transmission 

Connectors
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3.6.1 Summary of Technical Information in the Application

LRA Section 3.6 provides AMR results for the electrical components commodity groups. LRA 

Table 3.6.1, “Summary of Aging Management Evaluations for the Electrical Components,” is a 

summary comparison of the applicant’s AMRs with those evaluated in the GALL Report for 

electrical components.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report.

3.6.2 Staff Evaluation

The staff reviewed LRA Section 3.6 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the electrical components within the 

scope of license renewal and subject to an AMR will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

The staff conducted a review of the applicant’s AMRs to verify the applicant’s claim that certain 

AMRs are consistent with the GALL Report or are not applicable. The staff did not repeat its 

review of the matters described in the GALL Report; however, the staff did verify that the 

material presented in the LRA is applicable and that the applicant identified the appropriate 

GALL Report AMRs. AMRs that the staff confirmed are consistent with the GALL Report are 

noted as such in Table 3.6-1; therefore, no further discussion is required. AMRs that the staff 

confirmed are not applicable to LSCS or require no aging management are noted in Table 3.6-1 

and are discussed in SER Section 3.6.2.1.1.

During its review, the staff also reviewed AMRs consistent with the GALL Report and those for 

which further evaluation is recommended. The staff confirmed that the applicant’s further 

evaluations are consistent with the SRP-LR Section 3.6.2.2 acceptance criteria. The staff’s 

evaluations of AMRs for which the GALL Report recommends further evaluation are 

documented in SER Section 3.6.2.2.

The staff also conducted a technical review of the remaining AMRs that are not consistent with 

or are not addressed in the GALL Report. The technical review evaluated whether all plausible 

aging effects have been identified and whether the aging effects listed are appropriate for the 

material-environment combinations specified. The staff’s evaluations of AMRs that are not 

consistent with or are not addressed in the GALL Report are documented in SER 

Section 3.6.2.3.

Table 3.6-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.6 and addressed in the GALL Report.
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Staff Evaluation for Electrical Components in the GALL Report

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended AMP 

in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or Amendments

Staff Evaluation

Electrical equipment 

subject to 

10 CFR 50.49 EQ 

requirements 

composed of various 

polymeric and 

metallic materials 

exposed to adverse 

localized 

environment caused 

by heat, radiation, 

oxygen, moisture, or 

voltage (3.6.1-1)

Various aging 

effects due to 

various 

mechanisms in 

accordance with 

10 CFR 50.49

EQ is a time-limited 

aging analysis (TLAA) 

to be evaluated for the 

period of extended 

operation. See the 

Standard Review Plan, 

Section 4.4, 

“Environmental 

Qualification (EQ) of 

Electrical Equipment,”

for acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1)(i) 

and (ii). See Chapter 

X.E1, “Environmental 

Qualification (EQ) of 

Electric Components,”

of this report for 

meeting the 

requirements of 

10 CFR 54.21(c)(1)(iii).

Yes TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.6.2.2.1)

High-voltage 

insulators composed 

of porcelain; 

malleable iron; 

aluminum; 

galvanized steel; 

cement exposed to 

air – outdoor 

(3.6.1-2)

Loss of material 

due to 

mechanical 

wear caused by 

wind blowing on 

transmission 

conductors

A plant-specific aging 

management program 

is to be evaluated

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.6.2.2.2)

High-voltage 

insulators composed 

of porcelain; 

malleable iron; 

aluminum; 

galvanized steel; 

cement exposed to 

air – outdoor 

(3.6.1-3)

Reduced 

insulation 

resistance due 

to presence of 

salt deposits or 

surface 

contamination

A plant-specific aging 

management program 

is to be evaluated for 

plants located such 

that the potential exists 

for salt deposits or 

surface contamination 

(e.g., in the vicinity of 

salt water bodies or 

industrial pollution)

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.6.2.2.2)

Transmission 

conductors 

composed of 

aluminum; steel 

exposed to air –

outdoor (3.6.1-4)

Loss of 

conductor 

strength due to 

corrosion

A plant-specific aging 

management program 

is to be evaluated for 

ACSR

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.6.2.2.3)

Transmission 

connectors 

composed of 

aluminum; steel 

exposed to air –

outdoor (3.6.1-5)

Increased 

resistance of 

connection due 

to oxidation or 

loss of pre-load

A plant-specific aging 

management program 

is to be evaluated

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.6.2.2.3)
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Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended AMP 

in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or Amendments

Staff Evaluation

Switchyard bus and 

connections 

composed of 

aluminum; copper; 

bronze; stainless 

steel; galvanized 

steel exposed to 

air – outdoor 

(3.6.1-6)

Loss of material 

due to windinduced 

abrasion; 

Increased 

resistance of 

connection due 

to oxidation or 

loss of pre-load

A plant-specific aging 

management program 

is to be evaluated

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.6.2.2.3)

Transmission 

conductors 

composed of 

aluminum; steel 

exposed to air –

outdoor (3.6.1-7)

Loss of material 

due to windinduced 

abrasion

A plant-specific aging 

management program 

is to be evaluated for 

ACAR and ACSR

Yes Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.6.2.2.3)

Insulation material 

for electrical cables 

and connections 

(including terminal 

blocks, fuse holders, 

etc.) composed of 

various organic 

polymers (e.g., EPR, 

SR, EPDM, XLPE) 

exposed to adverse 

localized 

environment caused 

by heat, radiation, or 

moisture (3.6.1-8)

Reduced 

insulation 

resistance due 

to thermal/ 

thermoxidative 

degradation of 

organics, 

radiolysis, and 

photolysis (UV 

sensitive 

materials only) 

of organics; 

radiationinduced 

oxidation; 

moisture 

intrusion

Chapter XI.E1, 

“Insulation Material for 

Electrical Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements”

No Insulation 

Material for 

Electrical Cables 

and Connections 

Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

Consistent with the 

GALL Report

Insulation material 

for electrical cables 

and connections 

used in 

instrumentation 

circuits that are 

sensitive to 

reduction in 

conductor insulation 

resistance (IR) 

composed of various 

organic polymers 

(e.g., EPR, SR, 

EPDM, XLPE) 

exposed to adverse 

localized 

environment caused 

by heat, radiation, or 

moisture (3.6.1-9)

Reduced 

insulation 

resistance due 

to 

thermal/thermox

idative 

degradation of 

organics, 

radiolysis, and 

photolysis (UV 

sensitive 

materials only) 

of organics; 

radiationinduced 

oxidation; 

moisture 

intrusion

Chapter XI.E2, 

“Insulation Material for 

Electrical Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements Used in 

Instrumentation 

Circuits”

No Insulation 

Material for 

Electrical Cables 

and Connections 

Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements 

Used in 

Instrumentation 

Circuits

Consistent with the 

GALL Report
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Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended AMP 

in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or Amendments

Staff Evaluation

Conductor insulation 

for inaccessible 

power cables greater 

than or equal to 400 

volts (e.g., installed 

in conduit or direct 

buried) composed of 

various organic 

polymers (e.g., EPR, 

SR, EPDM, XLPE) 

exposed to adverse 

localized 

environment caused 

by significant 

moisture (3.6.1-10)

Reduced 

insulation 

resistance due 

to moisture

Chapter XI.E3, 

“Inaccessible Power 

Cables Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements”

No Inaccessible 

Power Cables 

Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

Consistent with the 

GALL Report

Metal enclosed bus: 

enclosure 

assemblies 

composed of 

elastomers exposed 

to air – indoor, 

controlled or 

uncontrolled or air –

outdoor (3.6.1-11)

Surface 

cracking, 

crazing, 

scuffing, 

dimensional 

change (e.g.,

“ballooning” and 

“necking”), 

shrinkage, 

discoloration, 

hardening and 

loss of strength 

due to 

elastomer 

degradation

Chapter XI.E4, “Metal 

Enclosed Bus,” or 

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Metal Enclosed 

Bus

Consistent with the 

GALL Report

Metal enclosed bus: 

bus/connections 

composed of various 

metals used for 

electrical bus and 

connections 

exposed to air –

indoor, controlled or 

uncontrolled or air –

outdoor (3.6.1-12)

Increased 

resistance of 

connection due 

to the loosening 

of bolts caused 

by thermal 

cycling and 

ohmic heating

Chapter XI.E4, “Metal 

Enclosed Bus”

No Metal Enclosed 

Bus

Consistent with the 

GALL Report

Metal enclosed bus: 

insulation; insulators 

composed of 

porcelain; xenoy; 

thermo-plastic 

organic polymers 

exposed to air –

indoor, controlled or 

uncontrolled or air –

outdoor (3.6.1-13)

Reduced 

insulation 

resistance due 

to thermal/

thermoxidative 

degradation of 

organics/

thermoplastics, 

radiationinduced 

oxidation, 

moisture/debris 

intrusion, and 

ohmic heating

Chapter XI.E4, “Metal 

Enclosed Bus”

No Metal Enclosed 

Bus

Consistent with the 

GALL Report
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Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended AMP 

in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or Amendments

Staff Evaluation

Metal enclosed bus: 

external surface of 

enclosure 

assemblies 

composed of steel 

exposed to air –

indoor, uncontrolled 

or air – outdoor 

(3.6.1-14)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.E4, “Metal 

Enclosed Bus,” or 

Chapter XI.S6, 

“Structures Monitoring”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.6.2.1.1)

Metal enclosed bus: 

external surface of 

enclosure 

assemblies 

composed of 

galvanized steel; 

aluminum exposed 

to air – outdoor 

(3.6.1-15)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.E4, “Metal 

Enclosed Bus,” or 

Chapter XI.S6, 

“Structures Monitoring”

No Metal Enclosed 

Bus

Consistent with the 

GALL Report

Fuse holders (not 

part of active 

equipment): metallic 

clamps composed of 

various metals used 

for electrical 

connections 

exposed to air –

indoor, uncontrolled 

(3.6.1-16)

Increased 

resistance of 

connection due 

to chemical 

contamination, 

corrosion, and 

oxidation (in an 

air, indoor 

controlled 

environment, 

increased 

resistance of 

connection due 

to chemical 

contamination, 

corrosion and 

oxidation do not 

apply); fatigue 

due to ohmic 

heating, thermal 

cycling, 

electrical 

transients

Chapter XI.E5, “Fuse 

Holders”

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.6.2.1.1)

Fuse holders (not 

part of active 

equipment): metallic 

clamps composed of 

various metals used 

for electrical 

connections 

exposed to air –

indoor, controlled or 

uncontrolled 

(3.6.1-17)

Increased 

resistance of 

connection due 

to fatigue 

caused by 

frequent 

manipulation or 

vibration

Chapter XI.E5, “Fuse 

Holders” No aging 

management program 

is required for those 

applicants who can 

demonstrate these fuse 

holders are located in 

an environment that 

does not subject them 

to environmental aging 

mechanisms or fatigue 

caused by frequent 

manipulation or 

vibration

No Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.6.2.1.1)
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Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended AMP 

in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or Amendments

Staff Evaluation

Cable connections 

(metallic parts) 

composed of various 

metals used for 

electrical contacts 

exposed to air –

indoor, controlled or 

uncontrolled or air –

outdoor (3.6.1-18)

Increased 

resistance of 

connection due 

to thermal 

cycling, ohmic 

heating, 

electrical 

transients, 

vibration, 

chemical 

contamination, 

corrosion, and 

oxidation

Chapter XI.E6, 

“Electrical Cable 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements”

No Electrical Cable 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

Consistent with the 

GALL Report

Connector contacts 

for electrical 

connectors exposed 

to borated water 

leakage composed 

of various metals 

used for electrical 

contacts exposed to 

air with borated 

water leakage 

(3.6.1-19)

Increased 

resistance of 

connection due 

to corrosion of 

connector 

contact surfaces 

caused by 

intrusion of 

borated water

Chapter XI.M10, “Boric 

Acid Corrosion”

No Not Applicable 

(PWR Only)

Not Applicable to 

BWRs (see SER 

Section 3.6.2.1.1)

Transmission 

conductors 

composed of 

aluminum exposed 

to air – outdoor 

(3.6.1-20)

Loss of 

conductor 

strength due to 

corrosion

None - for Aluminum 

Conductor Aluminum 

Alloy Reinforced 

(ACAR)

None Not Applicable Not Applicable to 

LSCS (see SER 

Section 3.6.2.1.1)

Fuse holders (not 

part of active 

equipment): 

insulation material, 

metal enclosed bus: 

external surface of 

enclosure 

assemblies 

composed of 

insulation material: 

bakelite; phenolic 

melamine or 

ceramic; molded 

polycarbonate; 

other, galvanized 

steel; aluminum, 

steel exposed to air 

– indoor, controlled 

or uncontrolled 

(3.6.1-21)

None None NA - No 

AEM or 

AMP

Consistent with 

the GALL Report

Consistent with the 

GALL Report

3.6.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.6.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for electrical components:
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• Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements

• Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements

• Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements

• Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Used in Instrumentation Circuits

• Metal Enclosed Bus

LRA Table 3.6.2-1 summarizes the AMR results for the electrical components and indicates

AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components in these 

GALL Report component groups were bounded by the GALL Report evaluation. The applicant 

provided a note for each AMR item. The notes describe how the information in the tables aligns 

with the information in the GALL Report. The staff audited those AMRs with notes A through E, 

which indicate how the AMR was consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these AMR items to confirm consistency with the GALL Report and the validity 

of the AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff audited these AMR items to confirm consistency with 

the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to 

the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant 

was consistent with the AMP identified in the GALL Report and whether the AMR was valid for 

the site-specific conditions.

Note C indicates that the component for the AMR item, although different from that in the 

GALL Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP is consistent with the AMP identified by the GALL Report. Note C indicates 

that the applicant was unable to find a listing of some system components in the GALL Report; 

however, the applicant identified a different component in the GALL Report that had the same 

material, environment, aging effect, and AMP as those of the component under review. The 

staff audited these AMR items to confirm consistency with the GALL Report. The staff also 

determined whether the AMR item of the different component applied to the component under 

review and whether the AMR was valid for the site-specific conditions.

Note D indicates that the component for the AMR item, although different from that in the 

GALL Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff 

audited these AMR items to confirm consistency with the GALL Report and confirmed whether 

the AMR item of the different component was applicable to the component under review. The 
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staff confirmed whether it had reviewed and accepted the exceptions to the GALL Report AMPs. 

The staff also determined whether the AMP identified by the applicant was consistent with the 

AMP identified in the GALL Report and whether the AMR was valid for the site-specific 

conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect; however, a different AMP is credited. The staff audited these 

AMR items to confirm consistency with the GALL Report and determined whether the identified 

AMP would manage the aging effect consistent with the AMP identified in the GALL Report and 

whether the AMR was valid for the site-specific conditions.

The staff did not repeat its review of the matters described in the GALL Report for those items 

that the staff determined were bounded by the GALL Report evaluation. However, it did confirm 

that the material presented in the LRA was applicable and that the applicant identified the 

appropriate GALL Report AMRs. The staff’s evaluation is discussed below.

AMR Results Identified as Not Applicable or Not Used

For LRA Table 3.6.1, item 3.6.1-19, the applicant claimed that the corresponding AMR items in 

the GALL Report are not applicable because the associated items are only applicable to PWRs. 

The staff reviewed the SRP-LR; confirmed that these items only apply to PWRs; and finds that 

these items are not applicable to LSCS, which is a BWR.

For LRA Table 3.6.1, items 3.6.1-14, 3.6.1-16, 3.6.1-17, and 3.6.1-20, the applicant claimed that 

the corresponding items in the GALL Report are not applicable because the component, 

material, and environment combination described in the SRP-LR does not exist for in-scope 

SCs at LSCS. The staff reviewed the LRA and UFSAR and confirmed that the applicant’s LRA 

does not have any AMR results applicable for these items.

3.6.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation Is 

Recommended

In LRA Section 3.6.2.2, the applicant further evaluated aging management, as recommended by 

the GALL Report, for the electrical commodity group components and provided information 

concerning how it will manage the following aging effects:

• electrical equipment subject to EQ

• reduced insulation resistance due to presence of any salt deposits and surface 

contamination and loss of material due to mechanical wear caused by wind blowing on 

transmission conductors

• loss of material due to wind-induced abrasion and fatigue, loss of conductor strength 

due to corrosion, and increased resistance of connection due to oxidation or loss of 

preload

• QA for aging management of nonsafety-related components

• ongoing review of operating experience

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 
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the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.6.2.2. The staff’s review of the applicant’s 

further evaluation follows.

Electrical Equipment Subject to Environmental Qualification

LRA Section 3.6.2.2.1, associated with LRA Table 1, item 3.6.1-1, states that TLAAs are 

evaluated in accordance with 10 CFR 54.21(c)(1) and that the evaluation of this TLAA is 

addressed in LRA Section 4.4. This is consistent with SRP-LR Section 3.6.2.2.1 and, therefore, 

is acceptable. The staff’s evaluation of the TLAA for electrical equipment subject to EQ is 

documented in SER Section 4.4.

Reduced Insulation Resistance Due to the Presence of Any Salt Deposits and

Surface Contamination and Loss of Material Due to Mechanical Wear Caused by 

Wind Blowing on Transmission Conductors

LRA Section 3.6.2.2.2, associated with LRA Table 3.6.1, items 3.6.1-2 and 3.6.1-3, addresses 

high-voltage insulators composed of porcelain, malleable iron, aluminum, galvanized steel, and 

cement exposed to outdoor air. SRP-LR Section 3.6.2.2.2 states that the GALL Report 

recommends further evaluation of a plant-specific AMP to ensure that this aging effect is 

adequately managed and states that acceptance criteria for this further evaluation are described 

in BTP RLSB-1 (SRP-LR Appendix A.1).

LRA Item 3.6.1-2 addresses the aging effect of loss of material due to mechanical wear caused 

by wind blowing on transmission conductors. LRA Section 3.6.2.2.2 states that, for high-voltage 

insulators, mechanical wear and loss of material due to wind and movement of the associated 

transmission conductor is not a credible aging effect at LSCS and that a plant-specific AMP is 

not required for this aging effect. The applicant noted in its evaluation that high-voltage 

insulator wear has not been apparent during routine inspections. The applicant also stated that 

industry experience has shown that transmission conductors do not normally swing and that 

movement due to substantial wind will subside after a short period.

The staff noted that EPRI 1013475, “Plant Support Engineering: License Renewal Electrical 

Handbook, Revision 1, to EPRI Report 1003057,” dated February 2007, states that “mechanical 

wear is an aging effect for strain and suspension insulators in that they are subject to 

movement.” Movement of insulators can be caused by wind blowing on the supported 

transmission conductor, causing it to swing. If this swing is frequent enough, it could cause 

wear in the metal contact point of the insulator string and between an insulator and supporting 

hardware. EPRI 1013475 indicates that this mechanism is possible but that industry operating 

experience has shown that the transmission conductors are designed not to normally swing, 

and when they do (e.g., due to a substantial wind), transmission conductors do not continue to 

swing for a long period of time once the wind has subsided.

The staff evaluated the applicant’s claim and finds it acceptable because the applicant’s further 

evaluation was performed consistent with SRP-LR Section 3.6.2.2.2 review and acceptance 

criteria demonstrating that mechanical wear due to wind is not an applicable aging effect for 

LSCS.

LRA Item 3.6.1-3 addresses the aging effect of reduced insulation resistance due to presence of 

salt deposits or surface contamination. LRA Section 3.6.2.2.2 states that this item is not 

applicable because airborne materials can contaminate insulator surfaces but that the buildup of 
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contamination is gradual and is usually removed by rain. The applicant also stated that the 

glazed surface of the insulator helps in the removal of dust, salt, and industrial effluent 

contamination. LSCS is not located near the seacoast or near other sources of airborne 

particulates. Therefore, the applicant concluded that reduced insulation resistance due to 

surface contamination is not an applicable aging effect for high-voltage insulators at LSCS and 

that a plant-specific AMP is not required. The applicant cites generic note I and plant-specific 

note 2 for this item. Note 2 states that based on LSCS design and operating experience, 

reduced insulation resistance is not an applicable aging effect for LSCS high-voltage insulators.

The staff reviewed the associated items in the LRA and confirmed that these aging effects are 

not applicable for this component, material, and environmental combination. The staff notes 

that LSCS is not located in the vicinity of salt water bodies or industrial pollution; therefore,

surface contamination of high-voltage insulators is minimized. In addition, rainfall and snow 

periodically wash away minor contamination, and the glazed insulator surface also aids 

contamination removal.

The staff evaluated the applicant’s claim and finds it acceptable because the applicant’s 

evaluation was performed consistent with SRP-LR Section 3.6.2.2.2 review and acceptance 

criteria and because it demonstrated that a reduced insulation resistance aging effect due to salt 

deposits or surface contamination of high-voltage insulators is not an applicable aging 

mechanism requiring management for LSCS.

Loss of Material Due to Wind-Induced Abrasion, Loss of Conductor Strength Due to 

Corrosion, and Increased Resistance of Connection Due to Oxidation or Loss of 

Preload

LRA Section 3.6.2.2.3, associated with LRA Table 1, items 3.6.1-4 through 3.6.1-7, addresses 

loss of material due to wind-induced abrasion, loss of conductor strength due to corrosion, and 

increased resistance of connection due to oxidation or loss of preload in transmission 

conductors and connections and in switchyard bus and connections. The criteria in SRP-LR 

Section 3.6.2.2.3 recommend further evaluation of a plant-specific AMP to ensure that this aging

effect is adequately managed. Acceptance criteria are described in BTP RLSB-1

(SRP-LR Appendix A.1).

LRA Item 3.6.1-4 addresses the aging effect of loss of strength due to corrosion in transmission 

conductors composed of aluminum and steel exposed to outdoor air. LRA Section 3.6.2.2.3 

states that loss of conductor strength is not an applicable aging effect for LSCS transmission 

conductors based on LSCS design and operating experience.

The applicant referenced an Ontario Hydro study that included the results of aluminum 

conductor steel reinforced (ACSR) transmission conductor laboratory and field tests, including 

the evaluation of conductor aging effects due to locations near pollution sources and major 

urban areas. The Ontario Hydro study results indicate acceptable loss of strength due to 

corrosion in areas affected by industrial pollution. The applicant stated that LSCS is located in a 

rural area with low industrial airborne particles and, therefore, is bounded by the Ontario Hydro 

study. The applicant also stated that LSCS transmission conductors are more substantial than 

conductors evaluated in the above study and, therefore, will have ample strength margin 

throughout the period of extended operation.

The staff noted that the LSCS ACSR transmission conductors of the in-scope switchyard 

components are susceptible to loss of strength due to corrosion. However, LSCS is not located 
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in an area affected by industrial airborne particles and is not subject to higher rates of corrosion 

than those observed by the Ontario Hydro study. Therefore, the staff finds that loss of 

conductor strength due to corrosion of ACSR transmission conductors is not an applicable aging 

effect at LSCS requiring an AMP.

LRA Item 3.6.1-5 addresses the aging effect of increased resistance of connection due to 

oxidation or loss of preload in transmission connectors composed of aluminum and steel 

exposed to outdoor air. LRA Section 3.6.2.2.3 states that oxidation and loss of preload are not 

applicable aging effects for LSCS transmission connectors based on LSCS design and 

operating experience.

Transmission connectors can be susceptible to increased resistance due to corrosion. LSCS air 

quality, due to its location being away from any industrial facilities and free from salty moisture, 

is not a contributing factor to aging degradation due to corrosion. At LSCS, transmission 

connector surfaces are coated with corrosion inhibitors providing a corrosion-resistant low 

electrical resistance connection. LSCS transmission connectors are designed and installed 

using stainless steel lock washers and torqued to maintain preload. The design of these 

connections along with operating experience at LSCS indicates that increased resistance due to 

general corrosion and oxidation and loss of preload are not AERMs.

The staff reviewed the associated items in the LRA and confirmed that these aging effects are 

not applicable for this component, material, and environmental combination. The staff finds the 

applicant’s further evaluation acceptable because the LSCS transmission connectors are 

located in an area away from industrial air pollution; therefore, the aluminum bus material is not 

expected to exhibit significant aging effects. In addition, the transmission connectors employ 

corrosion inhibitors and bolting practices using washers that prevent loss of preload and limit 

vibration.

LRA item 3.6.1-6 addresses the aging effects of loss of material due to wind-induced abrasion, 

increased resistance of connection due to oxidation, or loss of preload in switchyard bus and 

connections composed of aluminum, copper, bronze, stainless steel, or galvanized steel 

exposed to outdoor air. LRA Section 3.6.2.2.3 states that loss of material and increased 

resistance of connection are not applicable aging effects for LSCS switchyard bus and 

connections.

Switchyard connections can be susceptible to increased resistance due to corrosion. LSCS air 

quality, due to its location away from industrial facilities, is not a contributing factor to aging 

degradation due to corrosion. At LSCS, switchyard connection surfaces are coated with an 

inhibitor compound providing a corrosion-resistant low electrical resistance connection. 

Absence of operating experience problems with switchyard buses at LSCS indicates that 

increased connection resistance due to general corrosion and oxidation is not an AERM.

The applicant stated that due to the design of the transmission switchyard conductors and bus 

bolted connections, torque relaxation (loss of preload) is precluded. The design calls for use of 

washers and a corrosion inhibitor to preclude connection degradation due to loss of preload. 

The operating experience at LSCS has confirmed the absence of loss of preload. Therefore, 

increased connection resistance due to loss of preload of transmission conductor connections 

and switchyard bus connections is not an AERM at LSCS.

The staff reviewed the associated items in the LRA and confirmed that these aging effects are 

not applicable for this component, material, and environmental combination. The staff finds the 
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applicant’s evaluation acceptable because wind-born particulates have not been shown to be a 

contributor to loss of material at LSCS. The staff also noted that the switchyard bus is 

connected to active components by short sections of flexible conductors, which dampen the 

vibration effects caused by operation of switchyard components.

LRA Item 3.6.1-7 addresses the aging effects of loss of material due to wind-induced abrasion 

in transmission conductors composed of aluminum and steel exposed to outdoor air. LRA 

Section 3.6.2.2.3 states that loss of material is not an applicable aging effect for LSCS 

transmission conductors.

The applicant reviewed loss of material (wear) due to wind particulates and concluded that they 

are not applicable AERMs. The staff noted that wind born particulates have not been shown to 

be a contributor to loss of material. Therefore, the staff finds that the loss of material (wear) due 

to wind-induced abrasion is not an AERM for transmission conductors and connections at 

LSCS.

On the basis of its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.6.2.2.3 criteria. For those items that apply to LRA Section 3.6.2.2.3, the staff finds 

that the LRA is consistent with the GALL Report and that the applicant has demonstrated that 

the effects of aging will be adequately managed so that the intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program.

Ongoing Review of Operating Experience

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience of AMPs.

3.6.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Table 3.6.2-1, the staff reviewed additional details of the AMR results for material, 

environment, AERM, and AMP combinations that are not consistent with or are not addressed in 

the GALL Report.

In LRA Table 3.6.2-1, the applicant indicated, through notes F through J, that the combination of 

component type, material, environment, and AERM does not correspond to an item in the 

GALL Report. The applicant provided further information about how it will manage the aging 

effects. Specifically, note F indicates that the material for the AMR item component is not 

evaluated in the GALL Report. Note G indicates that the environment for the AMR item

component and material is not evaluated in the GALL Report. Note H indicates that the aging 

effect for the AMR item component, material, and environment combination is not evaluated in 

the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the 

item component, material, and environment combination is not applicable. Note J indicates that 

neither the component nor the material and environment combination for the item is evaluated in 

the GALL Report.
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For component type, material, and environment combinations not evaluated in the 

GALL Report, the staff reviewed the applicant’s evaluation to determine whether the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following section.

Electrical Commodities – Summary of Aging Management Evaluation –

LRA Table 3.6.2-1

The staff reviewed LRA Table 3.6.2-1, which summarizes the results of AMR evaluations for the 

Electrical Commodities component groups.

Porcelain, Malleable Iron, Aluminum, Galvanized Steel, and Cement Exposed to Outdoor Air. 

For the LRA Table 3.6.2-1 item corresponding to LRA Table 1, item 3.6.1-2, the applicant stated 

that, for high-voltage insulators, mechanical wear, reduced insulation resistance, and loss of 

material due to wind and movement of the associated transmission conductors is not a credible 

aging effect at LSCS and that a plant-specific AMP is not required for this aging effect. The 

applicant cites generic note I and plant-specific note 1 for this item. Note 1 states that based on 

LSCS design and operating experience, loss of material is not an applicable aging effect for 

LSCS high-voltage insulators. The applicant noted in its evaluation that high-voltage insulator 

wear has not been apparent during routine inspections. The applicant also stated that industry 

experience has shown transmission conductors do not normally swing and movement due to 

substantial wind will subside after a short period.

The staff reviewed the associated Table 3.6.2-1 item in the LRA to confirm that these aging 

effects are not applicable for this component, material, and environmental combination. The 

staff finds that this aging effect is not applicable to LSCS because plant and industry experience 

has shown that the components are not subject to prolonged movement of transmission 

conductors.

For the LRA Table 3.6.2-1 item associated with LRA Table 1, item 3.6.1-3, the applicant stated 

that, for porcelain, malleable iron, aluminum, galvanized steel, and cement exposed to outdoor 

air, there is no AERM and that no AMP is proposed. The AMR item cites generic note I and 

plant-specific note 2, which states that, based on LSCS design and operating experience, 

reduced insulation resistance is not an applicable aging effect for LSCS high-voltage insulators. 

The applicant stated that there is no aging effect because airborne materials can contaminate 

insulator surfaces, but the buildup of contamination is gradual and is usually removed by rain. 

The applicant also stated that the glazed surface of the insulator helps in the removal of dust, 

salt, and industrial effluent contamination. LSCS is not located near the seacoast or near other 

sources of airborne particulates.

The staff reviewed the associated items in the LRA and confirmed that there are no credible 

aging effects for this component, material, and environmental combination because LSCS is not 

located in the vicinity of salt water bodies or industrial pollution; therefore, surface contamination 

of high-voltage insulators is minimized. In addition, rainfall and snow periodically wash away 

minor contamination, and the glazed insulator surface also aids contamination removal.

Aluminum and Steel Exposed to Outdoor Air. For the LRA Table 3.6.2-1 item associated with 

Table 1, item 3.6.1-4, the applicant stated that, for transmission conductors composed of 

aluminum and steel exposed to outdoor air, there is no aging effect and that no AMP is 

proposed. The AMR item cites generic note I and plant-specific note 5, which states that loss of 
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conductor strength is not an applicable aging effect for LSCS transmission conductors, based 

on LSCS design and operating experience.

The applicant referenced the Ontario Hydro study that included the results of ACSR 

transmission conductor laboratory and field tests, including the evaluation of conductor aging 

effects due to locations near pollution sources and major urban areas. The Ontario Hydro study 

results indicate acceptable loss of strength due to corrosion in areas affected by industrial 

pollution. The conductors studied were of similar material but were less substantial in size and 

construction than those used at LSCS.

The applicant stated that LSCS is located in a rural area with low industrial airborne particles 

and, therefore, is bounded by the Ontario Hydro study. The applicant also stated that LSCS 

transmission conductors are more substantial than conductors evaluated in the above study 

and, therefore, will have ample strength margin throughout the period of extended operation.

The staff noted that the LSCS ACSR transmission conductors of the in-scope switchyard 

components are susceptible to loss of strength due to corrosion. However, LSCS is not located 

in an area affected by industrial airborne particles and is not subject to higher rates of corrosion 

than that observed by the Ontario Hydro study. The staff also noted that ACSR transmission 

conductors used at LSCS are more substantial than the material for the Ontario Hydro study 

and, therefore, are bound by the results of this study. Therefore, the staff finds that loss of 

conductor strength due to corrosion of ACSR transmission conductors is not an applicable aging 

effect at LSCS requiring an AMP.

For the LRA Table 3.6.2-1 item associated with Table 1, item 3.6.1-7, the applicant stated that, 

for transmission conductors composed of aluminum and steel exposed to outdoor air, there is 

no aging effect and that no AMP is proposed. The AMR item cites generic note I and 

plant-specific note 4, which states that LSCS transmission conductors composed of aluminum 

and steel in an outdoor air environment are not subject to wind-induced abrasion leading to loss 

of material.

The staff reviewed the associated items in the LRA to confirm that this aging effect is not 

applicable for this component, material, and environmental combination. The staff finds the 

applicant’s evaluation acceptable because wind-born particulates have not been shown to be a 

contributor to loss of material. Therefore, the staff finds that the loss of material (wear) due to 

wind-induced abrasion is not a significant AERM for transmission conductors and connections 

at LSCS.

Stainless Steel Exposed to Outdoor Air. For the LRA Table 3.6.2-1 item associated with 

Table 1, item 3.6.1-5, the applicant stated that, for transmission connectors composed of 

stainless steel exposed to outdoor air, there is no aging effect and that no AMP is proposed. 

The AMR item cites generic note I and plant-specific note 6, which states that in-scope LSCS 

transmission connectors composed of stainless steel in an outdoor air environment are not 

subject to oxidation or loss of preload and that increased resistance of connection is not an 

applicable aging effect.

Switchyard connections can be susceptible to increased resistance due to corrosion. LSCS air 

quality, due to its location being away from any industrial facilities and free from salty moisture, 

is not a contributing factor to aging degradation due to corrosion. At LSCS, switchyard 

connection surfaces are coated with corrosion inhibitors, providing a corrosion-resistant low 

electrical resistance connection. LSCS transmission connectors are designed and installed 
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using stainless steel lock washers and torqued to maintain preload. The design of these 

connections along with operating experience at LSCS indicates that increased resistance due to 

general corrosion and oxidation and loss of preload are not AERMs.

The staff reviewed the associated items in the LRA and confirmed that these aging effects are 

not applicable for this component, material, and environmental combination because 

transmission connectors are designed and installed using stainless steel lock washers and are 

torqued to maintain preload and because switchyard connections employ corrosion inhibitors 

and good bolting practices that prevent loss of preload and limit vibration.

Aluminum and Stainless Steel Exposed to Outdoor Air. For the LRA Table 3.6.2-1 item 

associated with Table 1, item 3.6.1-6, the applicant stated that, for switchyard bus and 

connections composed of aluminum and stainless steel exposed to outdoor air, there is no 

aging effect and that no AMP is proposed. The AMR item cites generic note I and plant-specific 

note 3, which states that in-scope switchyard bus and connections composed of aluminum and 

stainless steel in an outdoor air environment are not subject to wind induced abrasion,

oxidation, or loss of preload and that loss of material and increased resistance of connection are 

not applicable aging effects.

Switchyard connections can be susceptible to increased resistance due to corrosion. LSCS air 

quality, due to its location away from industrial facilities, is not a contributing factor to aging 

degradation due to corrosion. At LSCS, switchyard connection surfaces are coated with an 

inhibitor compound, providing a corrosion-resistant low electrical resistance connection. The 

absence of operating experience problems with switchyard buses at LSCS indicates that 

increased connection resistance due to general corrosion and oxidation is not an AERM.

The applicant stated that, due to the design of the transmission switchyard conductors and bus 

bolted connections, torque relaxation (loss of preload) is precluded. The design calls for use of 

washers and corrosion inhibitor to preclude connection degradation due to loss of preload. The 

operating experience at LSCS has confirmed the absence of loss of preload. Therefore, 

increased connection resistance due to loss of preload of transmission conductor connections 

and switchyard bus connections is not an AERM at LSCS.

The staff reviewed the associated items in the LRA and confirmed that these aging effects are 

not applicable for this component, material, and environmental combination. The staff finds the 

applicant’s evaluation acceptable because wind-born particulates have not been shown to be a 

contributor to loss of material at LSCS. The staff also noted that the switchyard bus is 

connected to active components by short sections of flexible conductors, which dampen the 

vibration effects caused by operation of switchyard components. In addition, switchyard 

connections employ corrosion inhibitors and bolting practices using washers that prevent loss of 

preload and limit vibration. Therefore, the staff concludes that abrasion, corrosion, oxidation,

and loss of preload are not considered an applicable aging mechanism for switchyard bus and 

connections at LSCS.

3.6.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the electrical components within the scope of license renewal and 

subject to an AMR will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3).
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3.7 Conclusion for Aging Management Review Results

The staff reviewed the information in LRA Section 3, “Aging Management Review Results,” and 

LRA Appendix B, “Aging Management Programs.” On the basis of its review of the AMR results 

and AMPs, the staff concludes that the applicant has demonstrated that the aging effects will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the applicable UFSAR supplement program summaries and concludes that the 

supplement adequately describes the AMPs credited for managing aging, as required by 

10 CFR 54.21(d).

With regard to these matters, the staff concludes that there is reasonable assurance that the 

applicant will continue to conduct the activities authorized by the renewed licenses in 

accordance with the CLB and that any changes made to the CLB to comply with 

10 CFR 54.21(a)(3) are in accordance with the Atomic Energy Act of 1954, as amended, and 

NRC regulations.

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TIME-LIMITED AGING ANALYSES

4.1 Identification of Time-Limited Aging Analyses

This section of the safety evaluation report (SER) provides the staff’s evaluation of the Exelon 

Generation Company, LLC (Exelon or the applicant) basis for identifying those plant-specific or 

generic analyses that need to be identified as time-limited aging analyses (TLAAs) for the 

applicant’s license renewal application (LRA) and the list of TLAAs for the LRA. The TLAAs are 

certain plant-specific safety analyses that involve time-limited assumptions defined by the 

current operating term. This section of the SER also provides the staff’s evaluation of the 

applicant’s basis for identifying those exemptions that need to be identified in the LRA.

In accordance with the requirements in Title 10 of the Code of Federal Regulations (10 CFR) 

54.21(c)(1)), an applicant for license renewal must list all evaluations, analyses, and 

calculations in the current licensing basis (CLB) that conform to the definition of a TLAA, as 

defined in 10 CFR 54.3, “Definitions.”

The regulation at 10 CFR 54.3 states that a plant-specific or generic evaluation, analysis, or 

calculation is a TLAA if it meets all six of the following TLAA identification criteria:

(1) involves a system, structure, or component (SSC) that is within the scope of a LRA, as 

described in 10 CFR 54.4(a)

(2) considers the effect or effects of aging

(3) involves time-limited assumptions that are defined by the current operating term 

(e.g., 40 years)

(4) was determined to be relevant by the applicant in making a safety determination

(5) involves conclusions, or provides the basis for conclusions, related to the capability of 

the SSC to perform its intended function(s), as described in 10 CFR 54.4(b)

(6) is contained or incorporated by reference in the CLB

For each evaluation, analysis, or calculation that is a TLAA, the applicant must demonstrate that 

the TLAA will be acceptable for the period of extended operation in accordance with one of the 

following three acceptance criteria for TLAAs in 10 CFR 54.21(c)(1):

(i) The analysis will remain valid for the period of extended operation.

(ii) The analysis has been projected to the end of the period of extended operation.

(iii) The effects of aging on the intended function(s) will be adequately managed for the 

period of extended operation.

In addition, pursuant to 10 CFR 54.21(c)(2), applicants must list all plant-specific exemptions in 

the CLB that were granted in accordance with the exemption approval criteria in 10 CFR 50.12, 

“Specific Exemptions,” and that are based on a TLAA. For any such exemptions, the applicant 

must evaluate and justify the continuation of the exemptions for the period of extended 

operation.
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The staff's guidance for reviewing LRA Section 4.1 is provided in NUREG–1800, Revision 2, 

“Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants –

Final Report” (SRP-LR), dated December 2010, Section 4.1, “Identification of Time Limiting 

Aging Analyses.” SRP-LR Section 4.1.1 summarizes the areas of review. SRP-LR 

Section 4.1.2 provides the staff’s “acceptance criteria” for performing TLAA and LRA exemption 

identification reviews. SRP-LR Section 4.1.3 provides the staff’s “review procedures” for 

performing the TLAA and LRA exemption identification reviews.

SPR-LR Table 4.1-1 provides some case-by-case examples on whether a given analysis 

category would be required to be identified as a TLAA for an LRA. SPR-LR Table 4.1-2 

provides a list of those analyses or calculations that are normally part of an applicant’s CLB and 

that are normally identified as TLAAs (i.e., generic TLAAs). SPR-LR Table 4.1-3 provides a list 

of those analyses or calculations that may be identified as plant-specific TLAAs.

4.1.1 Summary of Technical Information in the Application

4.1.1.1 Identification of TLAAs

LRA Section 4.1 states that the applicant reviewed and evaluated the evaluations, analyses, 

and calculations in the CLB for LaSalle County Station, Units 1 and 2 (LSCS), against the six 

criteria for TLAAs in 10 CFR 54.3. The applicant stated that it used the following guidance 

documents as part of the bases for its TLAA identification methodology: (1) SRP-LR, 

(2) NUREG-1801, Revision 2, “Generic Aging Lessons Learned (GALL) Report,” dated 

December 2010, (3) NEI 95-10, “Industry Guideline for Implementing the Requirements of 

10 CFR Part 54 – The License Renewal Rule,” (4) the NRC’s Statement of Consideration on 

10 CFR Part 54, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants,” 

and (5) prior LRAs, including NRC requests for additional information (RAIs) and SER inputs 

that have been issued for these applications.

The applicant stated that its review of the CLB included a review of the following plant-specific 

or generic sources (documents or records): (1) updated final safety analysis report (UFSAR),

(2) Technical Specifications (TS) and Bases, (3) docketed licensing correspondence, (4) NRC 

SERs, (5) applicable reports or design analyses, including those developed by Combustion 

Engineering (CE), Chicago Bridge and Iron Co. (CB&I), General Electric (GE), General 

Electric-Hitachi (GEH), Sargent and Lundy, and other vendors, (6) Passport records, 

(7) environmental qualification (EQ) binders, (8) applicable specifications, (9) engineering 

change requests, (10) corrective action program reports, (11) self-assessment reports, 

(12) 10 CFR 50.12 exemption requests, and (13) inspection relief requests.

The applicant provides its list of TLAAs in LRA Table 4.1-2, “Summary of Results – LSCS 

Time-Limited Aging Analyses”:

• Reactor Vessel and Internals Neutron Embrittlement Analyses in LRA Section 4.2, 

including those in the following subsections:

− LRA Section 4.2.1, Neutron Fluence Analyses

− LRA Section 4.2.2, Upper-Shelf Energy Analyses

− LRA Section 4.2.3, Adjusted Reference Temperature Analyses

− LRA Section 4.2.4, Pressure-Temperature Limits

− LRA Section 4.2.5, Axial Weld Failure Probability Assessment Analyses
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− LRA Section 4.2.6, Circumferential Weld Failure Probability Assessment Analyses

− LRA Section 4.2.7, Reactor Pressure Vessel Reflood Thermal Shock Analysis

− LRA Section 4.2.8, RPV Core Plate Rim Hold-Down Bolt Loss of Preload Analysis

− LRA Section 4.2.9, Jet Pump Riser Brace Clamp Loss of Preload Analysis

− LRA Section 4.2.10, Jet Pump Slip Joint Repair Clamp Loss of Preload Analysis

• Metal Fatigue Analyses in LRA Section 4.3, including those in the following subsections:

− LRA Section 4.3.1, ASME Section III, Class 1 Fatigue Analyses

− LRA Section 4.3.2, ASME Section III, Class 2 and 3 and ANSI B31.1 Allowable 

Stress Analyses

− LRA Section 4.3.3, Environmental Fatigue Analyses for RPV and Class 1 Piping

− LRA Section 4.3.4, Reactor Vessel Internals Fatigue Analyses

− LRA Section 4.3.5, High-Energy Line Break (HELB) Analyses Based on Fatigue

− LRA Section 4.3.6, Main Steam Relief Valve Discharge Piping Fatigue Analyses

• Environmental Qualification (EQ) for Electrical Components in LRA Section 4.4

• Concrete Containment Tendon Prestress Analyses in LRA Section 4.5

• Primary Containment Fatigue Analyses in LRA Section 4.6, including those in the 

following subsections:

− LRA Section 4.6.1, Primary Containment Liner and Penetrations Fatigue Analyses

− LRA Section 4.6.2, Primary Containment Refueling Bellows Fatigue Analysis

− LRA Section 4.6.3, Primary Containment Downcomer Vents Fatigue Analysis

• Other Plant-Specific TLAAs in LRA Section 4.7, including those in the following 

subsections:

− LRA Section 4.7.1, Reactor Building Crane Cyclic Loading Analysis

− LRA Section 4.7.2, Main Steam Line Flow Restrictors Erosion Analysis

The applicant provides its bases for accepting these TLAAs in accordance with either 

10 CFR 54.21(c)(1)(i), (ii), or (iii) in the applicable subsections of LRA Sections 4.2 through 4.7.

The applicant indicated that the following analysis listed in SRP-LR Table 4.1-2 is not part of the 

LSCS CLB and therefore does not need to be identified as an applicable TLAA for the LRA:

• inservice local metal containment corrosion analyses

The applicant indicates that the following potentially applicable plant-specific evaluations, 

analyses, or calculations listed in SRP-LR Table 4.1-3 are not part of the LSCS CLB and,

therefore, do not need to be identified as applicable TLAAs for the LRA:

• intergranular separation in the heat-affected zone (HAZ) of reactor vessel low-alloy steel 

under austenitic stainless steel cladding (i.e., reactor pressure vessel (RPV) underclad 

cracking analysis)

• low-temperature overpressure [protection] (LTOP) analysis
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• fatigue analysis for main steam supply lines to the auxiliary feedwater (AFW) pumps

• fatigue analysis for reactor coolant pump (RCP) flywheel

• flow-induced vibration endurance limit for the reactor vessel internals

• ductility reduction of fracture toughness analysis for the reactor vessel internals

• leak before break (LBB)

• metal corrosion allowance

• inservice flaw growth analyses that demonstrate structure stability for 40 years

4.1.1.2 Identification of Regulatory Exemptions

The applicant stated that it reviewed the CLB to determine whether there were any exemptions 

for the CLB that were granted in accordance with 10 CFR 50.12 and that are based on a TLAA, 

as required by 10 CFR 54.21(c)(2). The applicant stated that it did not identify any exemptions 

for the CLB that were granted in accordance with 10 CFR 50.12 and that are based on a TLAA.

4.1.2 Staff Evaluation

4.1.2.1 Identification of TLAAs

The staff reviewed the applicant’s methodology for identifying the TLAAs and the TLAA results 

for the LRA against the six criteria for TLAA identification in 10 CFR 54.3 and the list of TLAAs 

in SRP-LR Section 4.1, including the analyses in SRP-LR Table 4.1-2 that are normally generic 

TLAAs for the U.S. nuclear power industry and the list of analyses in SRP-LR Table 4.1-3 that 

may be plant-specific TLAAs. The staff used the “acceptance criteria” in SRP-LR Section 4.1.2 

and the review procedures in SRP-LR Section 4.1.3 as the basis for its review.

To verify the completeness of the applicant’s list of TLAAs, the staff reviewed LRA Appendix C, 

“Response to BWRVIP Applicant Action Items,” which provides the applicant’s responses to 

those applicant action items (AAIs) that were issued by the NRC on the applicant’s bases for 

implementing specific EPRI BWRVIP technical report methodologies during the period of 

extended operation. This review is provided in SER Section 4.1.2.1.2. SER Section 3.0.3.2.3 

provides the staff’s evaluations of the AAI responses that were provided in the LRA for 

non-TLAA-related topics.

Evaluations, Analyses, and Calculations in the CLB Conforming to 10 CFR 54.3 

TLAA Criteria

LRA Table 4.1-1 identifies those generic analyses and plant-specific analyses in the CLB that 

have been identified as TLAAs for the LRA. The staff noted that these are the analyses that 

have been identified as TLAAs in SER Section 4.1.1.1 and that these analyses are in 

conformance with the six criteria for defining TLAAs in 10 CFR 54.3. Based on this review, the 

staff finds that the identification of these TLAAs is acceptable because it is in compliance with 

the requirement in 10 CFR 54.21(c)(1). The staff’s evaluation of the applicant’s basis for 

accepting these TLAAs in accordance with either 10 CFR 54.21(c)(1)(i), (ii), or (iii) is 

documented in SER Sections 4.2 through 4.7 and their subsections.
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Evaluation of Plant Evaluations, Analyses, and Calculations in the CLB that Do Not 

Conform to the Definition of a TLAA in 10 CFR 54.3 or Statements that a Particular 

Analysis Referenced in the SRP-LR Does Not Exist in the CLB (Evaluation of 

“Absence of TLAA” Bases)

Absence of a TLAA – Inservice Local Metal Containment Corrosion Analyses. LRA Table 4.1-1 

identified that the CLB does not include any corrosion analyses for the metallic containment 

liner or other metallic containment components that conform to the definition of a TLAA in 

10 CFR 54.3(a) and that would need to be identified as TLAAs for the LRA in accordance with 

10 CFR 54.21(c)(1).

SRP-LR Table 4.1-2 identifies a local metal containment corrosion analysis as a generic type of 

TLAA that may be generically applicable to an applicant’s plant design. SRP-LR Section 4.7 

provides the staff’s recommended criteria for accepting these types of TLAAs in accordance 

with the TLAA acceptance requirements in 10 CFR 54.21(c)(1)(i), (ii), or (iii).

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff verified that the UFSAR does not rely on localized metal corrosion 

analyses to justify the structural integrity of metallic containment components against the 

consequences of corrosion-induced aging effects. Therefore, the staff concludes that LRA does 

not need to include a localized metal containment corrosion TLAA because the CLB does not 

include a localized metal containment structure corrosion analysis.

Absence of a TLAA –Intergranular Separation in the HAZ of reactor vessel low-alloy steel under 

austenitic SS cladding. LRA Table 4.1-1 identified that the CLB does not include any 

cycle-dependent analysis in evaluation of intergranular separations (underclad cracks/underclad 

cracking) in RPV cladding-to-forging welds.

SRP-LR Table 4.1-3 identifies that the CLB may include a plant-specific RPV underclad 

cracking analysis that qualifies as a TLAA. The recommended guidance in SRP-LR 

Section 3.1.2.2.5 and AMR item 18 in SRP-LR Table 3.1-1 identifies that these types of TLAAs 

are only applicable to SA-508 Class 2 forgings in pressurized water reactor (PWR)-designed 

RPVs that were welded to the RPV cladding using an uncontrolled high heat weld input process, 

and do not apply to boiling water reactors (BWRs).

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that the UFSAR defines the reactors at LSCS as GE-designed 

BWR Model 5 reactors. Therefore, consistent with the evaluation that is given in SER 

Section 3.1.2.2.5, the staff concludes that the LRA does not need to include a plant-specific 

RPV underclad cracking TLAA because the reactors at LSCS are BWRs.

Absence of a TLAA – LTOP Analysis. LRA Table 4.1-1 identified that the CLB does not include 

an LTOP analysis for the RPV and reactor coolant pressure boundary (RCPB).

SRP-LR Table 4.1-3 identifies that the CLB may include a plant-specific LTOP analysis that 

qualifies as a TLAA. The relevant SRP-LR recommendations are only applicable to the LTOP 

systems in PWR designs. The SRP-LR guidance is not applicable to BWR designs because 

BWR plants are not designed with LTOP systems.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that the UFSAR defines the reactors at LSCS as GE-designed 
4-6

BWR Model 5 reactors. Therefore, the staff concludes that the LRA does not need to include a 

plant-specific LTOP TLAA because the reactors at LSCS are BWRs.

Absence of a TLAA – Fatigue Analysis for Main Steam Supply Lines to Steam-Driven Auxiliary 

Feedwater Pumps. LRA Table 4.1-1 identified that the CLB does not include a fatigue analysis 

for main steam lines that supply steam to steam-driven AFW pumps.

SRP-LR Table 4.1-3 identifies that the CLB may include a plant-specific metal fatigue analysis 

for AFW pump main steam supply lines that qualifies as a TLAA. The relevant SRP-LR 

recommendations are only applicable to PWRs with designs that include steam-driven AFW 

pumps. The SRP-LR guidance is not applicable to BWR designs because BWR designs are not 

designed with AFW systems or pumps.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that the UFSAR defines the reactors at LSCS as GE-designed 

BWR Model 5 reactors. Therefore, the staff concludes that the LRA does not need to include a 

plant-specific fatigue TLAA for steam-driven AFW pump steam supply lines because the 

reactors at LSCS are BWRs.

Absence of a TLAA – Fatigue Analysis for the Reactor Coolant Pump Flywheel. LRA

Table 4.1-1 identified that the CLB does not include a fatigue analysis for RCP flywheels.

SRP-LR Table 4.1-3 identifies that the CLB may include a plant-specific cycle-dependent fatigue 

or flaw tolerance analysis for RCP flywheels that qualifies as a TLAA. The SRP-LR 

recommendations are only applicable to RCP flywheels in PWR designs. The relevant SRP-LR 

guidance is not applicable to BWR designs because the analogous pump components in BWR 

designs (i.e., the recirculation pumps) are not designed with flywheels.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that the UFSAR defines the reactors at LSCS as GE-designed 

BWR Model 5 reactors. Therefore, the staff concludes that the LRA does not need to include a 

plant-specific RCP flywheel TLAA because LSCS is a BWR.

Absence of a TLAA – Flow-Induced Vibration Limit for Reactor Vessel Internals. LRA 

Table 4.1-1 identified that the CLB does not include any TLAA associated with a flow-induced 

vibration limit for RVI components at LSCS.

SRP-LR Table 4.1-3 identifies that the CLB may include plant-specific flow-induced vibration 

analyses for the RVI components that qualify as TLAAs.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that UFSAR Section 3.9.2.4 indicates that flow-induced vibrations 

of the RVI components were assessed as part of a preoperational testing program and that the 

results of the program were summarized in GE Report NEDO-24057-P, “Assessment of Reactor 

Internals Vibration in BWR/4 and BWR/5 Plants,” dated November 1977. However, the staff 

noted that the UFSAR did not indicate whether the methodology in GE Report NEDO-24057-P 

included a time-dependent analysis for qualifying the structural integrity of the RVI components 

against the consequences of age-related effects caused by flow-induced vibrations.

By letter dated July 7, 2015, the staff issued RAI 4.1-1, requesting that the applicant clarify 

whether the methodology in GE Report NEDO-24057-P included a time-dependent analysis 
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and, if so, whether the analysis is relied upon to qualify the structural integrity of the RVI 

components against the consequences of flow-induced vibrations. If the analysis is 

time-dependent, the staff asked the applicant to provide justification as to why it would not need 

to be identified as a TLAA when compared to the six criteria for TLAAs in 10 CFR 54.3(a).

The applicant responded to RAI 4.1-1 in a letter dated August 6, 2015. The applicant stated 

that GE Report NEDO-24057-P was the GE licensing report that provides the analytical bases 

for the reactor internals vibration assessment program, including its acceptance criteria. The 

applicant stated that the report uses a combination of pretest analysis of predicted vibrations, 

vibrational monitoring during flow testing, and post-test inspection of the RVI components to 

qualify the components against the consequences of age-related effects that could potentially 

be induced by flow-induced vibrations. The applicant stated that analysis in the report does not 

include any time-dependent vibration assumptions, and instead places a maximum limit on the 

alternating stress amplitude of the flow-induced vibrations as an acceptance criterion for the 

vibration testing.

The staff noted that the applicant’s response to RAI 4.1-1 demonstrates that the analysis in 

GE Report NEDO-24057-P uses a non-time-dependent acceptance criterion (i.e., by 

establishing a maximum limit on the alternating stress amplitude for flow-induced vibrations) as 

the basis for demonstrating that flow-induced vibrations will be less than the endurance limit for 

inducing high cycle fatigue in the RVI components. Therefore, the staff concludes that the 

applicant has provided sufficient demonstration that the analysis in GE Report NEDO-24057-P 

does not need to be identified as a TLAA because the applicant has demonstrated that the 

analysis is not based on time-limited assumptions defined by the current operating term, and 

this demonstrates that the analysis does not conform to Criterion 3 in 10 CFR 54.3(a) for 

defining an analysis as a TLAA. RAI 4.1-1 is resolved.

Absence of a TLAA – Reduction of Ductility Fracture Toughness Analysis for the Reactor Vessel 

Internals. LRA Table 4.1 1 identified that the CLB does not include a reduction of ductility 

fracture toughness analysis for the RVI components at LSCS.

SRP-LR Table 4.1 3 identifies that the CLB may include a plant-specific reduction of ductility 

fracture toughness analysis for the RVI components that qualifies as a TLAA. The SRP-LR 

recommendations are only applicable to RVI components in PWRs designed by the Babcock 

and Wilcox Company (B&W). The relevant SRP-LR guidance is not applicable to RVI 

components in U.S. BWR designs because the components were not designed by B&W.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that the UFSAR defines the reactors at LSCS as GE designed 

BWR Model 5 reactors. Therefore, the staff concludes that the LRA does not need to include a 

reduction of ductility fracture toughness TLAA because LSCS is a BWR.

Absence of a TLAA – Leak before Break Analysis. LRA Table 4.1-1 identified that the CLB 

does not include any TLAA associated with an LBB analysis for the reactor units at LSCS.

SRP-LR Table 4.1-3 identifies that the CLB may include a plant-specific LBB analysis that 

qualifies as a plant-specific TLAA for the applicant’s LRA. The use of LBB technology is only 

applicable to the evaluation of large bore, high-energy piping in the RCPB (i.e., high-energy, 

large bore Class 1 piping) of PWR designs. The use of LBB technology has yet to be approved 

for BWR facilities.
4-8

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that the UFSAR defines the reactors at LSCS as GE-designed 

BWR Model 5 reactors. The staff also verified that LBB technology has not been approved in 

the CLB as the basis for demonstrating compliance with General Design Criterion 4, 

“Environmental and Dynamic Effects Design Bases,” in Appendix A, “General Design Criteria for 

Nuclear Power Plants,” to 10 CFR Part 50, “Domestic Licensing of Production and Utilization 

Facilities.” Instead, the staff verified that the applicant accomplishes this design basis objective 

through performance of the applicant’s HELB analysis for the RCPB system, which is the topic 

of the TLAA in LRA Section 4.3.5.

Therefore, the staff concludes that the LRA does not need to include an LBB TLAA because the 

reactor units at LSCS are BWRs and because LBB technology has not been approved as part 

of the CLB for LSCS. The staff evaluates the TLAA for the LSCS HELB analyses in SER 

Section 4.3.5.

Absence of a TLAA – Metal Corrosion Allowance Analysis. In LRA Table 4.1-1, the applicant 

identified that the CLB does not include any TLAA associated with a metal corrosion allowance 

at LSCS.

SRP-LR Table 4.1-3 identifies that the CLB may include plant-specific metal component 

corrosion allowance analyses that qualify as TLAAs for the applicant’s LRA.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that the UFSAR indicates that corrosion allowances were included 

in the design for carbon steel and low-alloy steel components based on their exposure to water 

or steam environments. The staff also noted that the UFSAR does not identify that these metal 

corrosion allowances (i.e., an additional metal that was included in thickness of the 

components) were included in component designs as a result of a time-dependent analysis. 

Therefore, based on this assessment, the staff concludes that the applicant had provided an 

acceptable basis for concluding that the CLB does not include any corrosion allowance TLAAs 

because the staff has confirmed that the metal corrosion allowances were not included in the 

plant design based on the conclusion of a time-dependent analysis result.

Absence of a TLAA – Inservice Flaw Analyses that Demonstrate Structure Stability for 40 Years. 

LRA Table 4.1-1 states that the CLB does not include any TLAA associated with inservice flaw 

growth analyses that are used to demonstrate structure stability for 40 years of operation.

SRP-LR Table 4.1-3 identifies that the CLB may include inservice inspection flaw analyses that 

are used to demonstrate structural stability over a 40-year licensed life.

During the aging management program audit of March 30, 2015, through April 3, 2015, the staff 

reviewed whether the CLB included any inservice flaw growth or fracture mechanics evaluations 

that would fall into this category. The staff did not identify any time-dependent flaw analyses 

that would qualify as a TLAA in accordance with the definition of a TLAA in 10 CFR 54.3(a). 

Therefore, based on the audit review, the staff concludes the applicant has adequately

demonstrated that the CLB does not include any time-dependent flaw analyses that would need 

to be identified as TLAAs for the LRA.

Potentially Applicable TLAAs Based on the Electric Power Research Institute (EPRI) Boiling 

Water Reactor Vessel and Internals Project (BWRVIP) Applicant Action Items. The staff noted 

that inclusion of LRA Aging Management Program (AMP) B.2.1.9, “BWR Vessel Internals,” 
4-9

confirms that the applicant applies the BWRVIP inspection and flaw evaluation (I&FE) guideline 

reports as part of its basis for managing the aging effects that are applicable to the RVI 

components at LSCS. Therefore, the staff reviewed the NRC-issued safety evaluations (SEs) 

on the BWRVIP reports that are referenced in GALL Report AMPs XI.M4, “BWR Vessel ID 

Attachment Welds”; XI.M8, “BWR Vessel Penetrations”; and XI.M9, “BWR Vessel Internals,” to 

determine whether SEs included applicable TLAA-related AAIs for the specific RVI components 

within the scope of the BWRVIP reports. The staff’s review included the following BWRVIP 

report SEs:

• SE on BWRVIP-18-A (I&FE guidelines for BWR core spray internals)

• SE on BWRVIP-25 (I&FE guidelines for BWR core plates)

• SE on BWRVIP-26-A (I&FE guidelines for BWR top guides)

• SE on BWRVIP-27-A (I&FE guidelines for BWR standby liquid control/core ΔP 

(SLC/core ΔP) nozzles and lines)

• SE on BWRVIP-38 (I&FE guidelines for core shroud supports)

• SE on BWRVIP-41 (I&FE guidelines for jet pump assembly components)

• SE on BWRVIP-42-A (I&FE guidelines for BWR low-pressure coolant injection (LPCI)

couplings)

• SE on BWRVIP-47-A (I&FE guidelines for BWR RVI lower plenum components)

• SE on BWRVIP-48-A (I&FE guidelines for BWR vessel ID attachment welds)

• SE on BWRVIP-49-A (I&FE guidelines for BWR instrument penetrations)

• SE on BWRVIP-74-A (I&FE guidelines for BWR RPV components)

• SE on BWRVIP-76-A (I&FE guidelines for BWR core shrouds)

The staff noted that, of these reports, only BWRVIP-18-A, BWRVIP-25, BWRVIP-26-A, 

BWRVIP-27-A, BWRVIP-42-A, BWRVIP-47-A, BWRVIP-74-A, and BWRVIP-76-A include AAIs 

that relate to the identification of TLAAs.

AAI No. 4 on BWRVIP-18-A (BWRVIP I&FE Guidelines for Internal BWR Core Spray Lines)

In the staff’s SE on EPRI BWRVIP-18-A dated December 7, 2000, the staff issued AAI No. 4, 

requesting that BWR applicants identify any plant-specific TLAAs that may be applicable to the 

evaluation of BWR core spray line (internal portions) and sparger components. Specifically, in 

this AAI, the staff stated that BWR applicants for renewal should identify all TLAAs that are 

applicable to the design of its core spray internal components.

In its response to this AAI, the applicant stated that the evaluation of cumulative fatigue damage 

is a potential TLAA for the core spray system piping and components that are located internal to 

the RPV. The applicant stated that its evaluation of the fatigue analysis for these components is 

given in LRA Section 4.3.4. The staff confirmed that the applicant discusses its metal fatigue 

TLAA (i.e., cumulative usage factor (CUF) analysis) for the internal portion of the core spray line 

and core spray sparger in LRA Section 4.3.4 and in LRA Table 4.3.4-1. The staff also verified 

that the fatigue analysis for the internal portions of the core spray lines and spargers was the 

only analysis for these components that conformed to the definition of a TLAA.
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Based on this review, the staff finds the applicant’s response to this AAI to be acceptable 

because the staff has confirmed that the applicant has included the applicable fatigue TLAA for 

the core spray line and sparger components in the LRA and that the design basis does not 

include any other analysis that needs to be identified as a TLAA for these components. The 

staff evaluates the CUF analysis for the internal portions of the core spray line and the core 

spray sparger in SER Section 4.3.4.2. AAI No. 4 on the BWRVIP-18-A report is resolved with 

respect to the contents of the LRA.

AAI No. 4 on BWRVIP-25 (BWRVIP I&FE Guidelines for BWR Core Plates)

In the staff’s SE on EPRI BWRVIP-25 dated December 7, 2000, the staff issued AAI No. 4, 

requesting that BWR applicants identify any plant-specific TLAAs that may be applicable to the 

evaluation of BWR core plate assemblies or the components in these assemblies. Specifically, 

in this AAI, the staff stated that BWR applicants for license renewal should identify and evaluate 

whether the evaluation of stress relaxation in core plate rim hold-down bolts should be identified

as a TLAA for the components.

In its response to this AAI, the applicant stated that a preload of the rim hold-down bolts is 

required to prevent lateral motion of the core plate for those plants that do not have core plate 

wedges installed in the design of their core plate assemblies. The applicant stated that the CLB 

includes an analysis of loss of preload due to stress relaxation of the core plate rim hold-down 

bolts and that this analysis is identified as a TLAA for the LRA. The applicant stated that the 

applicable TLAA is evaluated in LRA Section 4.2.8.

The staff confirmed that the applicant discusses the applicable TLAA for the core plate rim 

hold-down bolts in LRA Section 4.2.8 and that this TLAA evaluates the percent-drop that will 

occur in the preload levels of these bolts as a result of irradiation-influence stress relaxation. 

The staff also verified that, in addition to this TLAA, the LRA also includes a metal fatigue 

analysis for the core plate assembly, which has been identified as a TLAA in LRA Section 4.3.4.

Based on this review, the staff finds the applicant’s response to this AAI to be acceptable 

because the staff has confirmed that the LRA includes both the TLAA that evaluates loss of 

preload in the core plate rim hold-down bolts and the TLAA that evaluates cracking due to metal 

fatigue in the core plate assembly. The staff verified that, in addition to these TLAAs, there are 

no other analyses for the core plate assembly that would need to be identified as TLAAs for the 

LRA in accordance with 10 CFR 54.21(c)(1). The staff evaluates the TLAA for the core plate 

rim hold-down bolts in SER Section 4.2.8. The staff evaluates the metal fatigue analysis for the 

core plate in SER Section 4.3.4. AAI No. 4 on the BWRVIP-25 report is resolved with respect to 

the contents of the LRA.

AAI No. 4 on BWRVIP-26-A (BWRVIP I&FE Guidelines for BWR Top Guide Assemblies)

In the staff’s SE on EPRI BWRVIP-26-A, dated December 7, 2000, the staff issued AAI No. 4, 

requesting that BWR applicants identify any plant-specific TLAAs that may be applicable to the 

evaluation of BWR top guide components. Specifically in this AAI, the staff stated that BWR 

applicants for license renewal should identify and evaluate the impact of accumulated neutron 

fluence on the potential to initiate irradiation-assisted stress corrosion cracking (IASCC) in BWR 

top guide components and should evaluate the basis for identifying this evaluation as a TLAA

for the top guide components.
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In its response to this AAI, the applicant stated that the Radiation Analysis Modeling Application 

(RAMA) code fluence evaluation for the RVI components determined that the neutron fluence 

threshold for IASCC susceptibility of the top guides has been exceeded. The applicant stated 

that the fluence for RVI components is evaluated as a TLAA in LRA Section 4.2.1. The applicant 

stated that no other TLAA has been identified to manage the effects of aging for the top guides 

and their components. The applicant also stated that, during the period of extended operation, 

the aging of the top guide will be managed by inspections that are conducted as part of the 

BWRVIP (LRA Section B.2.1.9) and that the AMP will implement inspections of the top guide 

assemblies and their components consistent with the guidelines in EPRI BWRVIP-183.

The staff confirmed that the applicant does evaluate the neutron fluence methodology for RPV 

and RVI components in LRA Section 4.2.1. The staff also confirmed that LRA Section 4.3.4 

includes the applicant’s TLAA of fatigue-induced cracking in the top guide assemblies. The staff 

evaluates the TLAA for the neutron fluence methodology in SER Section 4.2.1. The staff 

evaluates the metal fatigue TLAAs for the RVI components (including those for the top guide 

assemblies) in SER Section 4.3.4.

The staff noted, however, that the applicant’s response to AAI No. 4 on the BWRVIP-26-A 

report did not specifically state whether the CLB included any analysis of irradiation-induced or 

irradiation-assisted stress corrosion cracking in the top guide assemblies (or the 

subcomponents in the top guide assemblies) that would need to be identified as a TLAA for the 

LRA. By letter dated July 7, 2015, the staff issued RAI 4.1-2, requesting that the applicant 

address this issue. Specifically, the staff asked the applicant whether the CLB includes an 

analysis or evaluation of irradiation-induced or irradiation-assisted stress corrosion cracking in 

the top guide assemblies of the reactor units or their subcomponents and, if so, whether the 

analysis would need to be identified as a TLAA when compared to the six criteria for defining 

analyses as TLAAs in 10 CFR 54.3(a).

The applicant responded to RAI 4.1-2 in a letter dated August 6, 2015. The applicant stated 

that, because AAI No. 4 for the BWRVIP-26-A report identified top guide IASCC as a potential 

TLAA area, the applicant performed specific searches of the CLB records to identify any 

plant-specific TLAA associated with IASCC of the top guide assemblies. The applicant stated 

that the only analysis of top guide IASCC found was in Appendix A to EPRI BWRVIP-183, “Top 

Guide Grid Beam Inspection and Flaw Evaluation Guidelines.”

The applicant stated that this appendix provides a flaw evaluation of the grid beam locations in 

the top guide of a BWR-5 reactor at another plant site. The applicant stated that, although the 

flaw evaluation was based on time-dependent assumptions, it only assessed the progression of 

IASCC-induced flaws over a 10-year inservice inspection period. Therefore, the applicant 

concluded that the analysis does not conform to the definition of a TLAA because it is not based 

on time-limited assumptions defined by the current operating period (e.g., 40 years).

The staff noted that the applicant’s response to RAI 4.1-2 demonstrates that the one analysis in 

the CLB that applies to the top guide assemblies (i.e., the generic flaw evaluation for top guide 

grid beam locations) is not based on any time-limited assumptions defined by the current 

operating term because the time dependency of the analysis is based on a period that is less 

than a 40-year design life.

Based on this review, the staff concludes that the applicant has provided sufficient 

demonstration that the generic flaw analysis in the BWRVIP-183 report does not need to be 

identified as a TLAA because the applicant has demonstrated that the analysis is not based on 
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time-limited assumptions defined by the current operating term, and this demonstrates that the 

analysis does not conform to Criterion 3 in 10 CFR 54.3(a) for defining an analysis as a TLAA. 

RAI 4.1-2 is resolved. AAI No. 4 on the BWRVIP-26-A report is resolved with respect to the 

contents of the LRA.

AAI No. 4 on BWRVIP-27-A (BWRVIP I&FE Guidelines for SLC/Core ΔP Nozzles and Lines)

In the staff’s SE on EPRI BWRVIP-27-A, dated December 20, 1999, the staff issued AAI No. 4, 

requesting that BWR applicants address those plant-specific TLAAs that may be applicable to 

the evaluation of BWR SLC/core ΔP nozzle components. Specifically, the staff stated that, due 

to the susceptibility of the subject components to fatigue, applicants referencing the

BWRVIP-27-A report for license renewal should identify and evaluate the projected fatigue 

CUFs as a potential TLAA issue.

In its response to this AAI, the applicant stated that cumulative fatigue damage is a potential 

TLAA issue identified for the SLC/core ΔP penetration nozzles (i.e., the RPV No. N-11 nozzles). 

The applicant stated that the TLAAs for cumulative fatigue damage of the SLC/core ΔP 

penetration nozzles are discussed in LRA Sections 4.3.1 and 4.3.3.

The staff verified that the applicant had provided and evaluated the metal fatigue analysis of the 

SLC/core ΔP penetration nozzles, including environmentally assisted fatigue (EAF), in LRA 

Sections 4.3.1 and 4.3.3. The staff also verified that the applicant provided and evaluated the 

metal fatigue analysis of the RPV internal portions of the SLC/core ΔP lines in LRA 

Section 4.3.4.

Based on this review, the staff finds that the applicant has adequately addressed AAI No. 4 on 

EPRI BWRVIP-27-A because the staff has verified that the applicant has included the applicable 

fatigue analyses for both the SLC/core ΔP penetration nozzles and those portions of SLC/core 

ΔP lines that are located internal to the RPVs in LRA Section 4.3. The staff’s evaluation of the 

fatigue analysis for the SLC/core ΔP penetration nozzles is given in SER Section 4.3.1. The 

staff’s evaluation of the EAF analysis for the SLC/core ΔP penetration nozzles is given in SER 

Section 4.3.3. The staff’s evaluation of the fatigue analysis for the portions of SLC/core ΔP lines 

that are located internal to the RPVs is given in SER Section 4.3.4. AAI No. 4 on the 

BWRVIP-27-A report is resolved with respect to the contents of the LRA.

AAI No. 4 on BWRVIP-42-A (BWRVIP I&FE Guidelines for LPCI Couplings)

In the staff’s SE on EPRI BWRVIP-42-A, dated January 9, 2001, the staff issued AAI No. 4, 

requesting that BWR applicants address those plant-specific TLAAs that may be applicable to 

the evaluation of BWR LPCI coupling components.

In its response to this AAI, the applicant stated that cumulative fatigue damage is a potential 

TLAA issue identified for the LPCI couplings. The applicant stated that the TLAA is used to 

manage cumulative fatigue damage for the LPCI coupling and that this TLAA is discussed in 

LRA Section 4.3.4.

The staff verified that the applicant provided the metal fatigue analysis of the LPCI couplings in 

LRA Section 4.3.4. The staff also verified that the CLB does not include any other type of 

analysis for the LPCI couplings that conforms to the definition of a TLAA in 10 CFR 54.3(a) or 

that would need to be identified as a TLAA in accordance with the requirement in 

10 CFR 54.21(c)(1).
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Based on this review, the staff finds that the applicant has adequately addressed AAI No. 4 on 

EPRI BWRVIP-42-A because the staff has verified that the applicant has included the applicable 

fatigue analysis for the LPCI couplings in LRA Section 4.3.4. The staff’s evaluation of the metal 

fatigue TLAA for the LPCI couplings is given in SER Section 4.3.4. AAI No. 4 on the 

BWRVIP-42-A report is resolved with respect to the contents of the LRA.

AAI No. 4 on BWRVIP-47-A (BWRVIP I&FE Guidelines for BWR Lower Plenum Components)

In the staff’s SE on EPRI BWRVIP-47-A, dated December 7, 2000, the staff issued AAI No. 4, 

requesting that BWR applicants address those plant-specific TLAAs that may be applicable to 

the evaluation of BWR lower plenum components. Specifically, in this AAI, the staff stated that, 

due to fatigue of the subject safety-related components, applicants referencing the BWRVIP-47 

report for license renewal should identify and evaluate the projected CUF as a potential TLAA 

issue.

In its response to this AAI, the applicant stated that fatigue usage is considered a TLAA for 

specific RVI lower plenum components that were analyzed in the design basis with a metal 

fatigue analysis. The applicant stated that the fatigue analyses for these components are 

addressed in LRA Section 4.3.4.

The staff verified that the CLB includes fatigue analyses for the RVI lower plenum components, 

which include the control rod drive housings and the access hole covers. The staff verified that 

the applicant identified that these analyses meet the definition of a TLAA in 10 CFR 54.3(a) and 

included the fatigue analyses as TLAAs for the components in LRA Section 4.3.4. The staff 

also verified that the CLB includes fatigue exemption analyses (i.e., fatigue waiver analyses) for 

the following RVI lower plenum components: (a) control rod guide tubes, (b) in-core 

instrumentation housings and guide tubes, and (c) fuel orifice supports.

The staff verified that the CLB does not include any other analyses for RVI lower plenum 

components that conform to the definition of a TLAA in 10 CFR 54.3(a) or that would need to be 

identified as a TLAA in accordance 10 CFR 54.21(c)(1).

Based on this review, the staff finds that the applicant has adequately addressed AAI No. 4 on 

EPRI BWRVIP-47-A because the staff has verified that the applicant has included and 

evaluated the applicable fatigue analyses or fatigue waiver analyses for these lower plenum 

components as TLAAs for LRA Section 4.3.4. The staff’s evaluation of these TLAAs is given in 

SER Section 4.3.4. AAI No. 4 on the BWRVIP-47-A report is resolved with respect to the 

contents of the LRA.

AAI Nos. 8 through 13 on BWRVIP-74-A (BWRVIP I&FE Guidelines for BWR RPV

Components)

In the staff’s SE on EPRI BWRVIP-74-A, dated October 18, 2001, the staff issued AAI Nos. 8 

through 13, which relate to the need for identification of the following TLAAs or assessments 

related to the RCPB function of BWR RPVs:

• AAI No. 8 on the need to identify metal fatigue TLAAs (CUF analyses) for RPV 

components that are part of the RCPB

• AAI No. 9 on the need to identify applicable pressure-temperature (P-T) limit TLAAs for 

the RPV
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• AAI No. 10 on the need to identify applicable upper-shelf energy (USE) TLAAs for the 

RPV

• AAI Nos. 11 and 12 on the need to identify applicable mean reference temperature nil

ductility transition (RTNDT) and probability of failure TLAAs for RPV circumferential and 

axial weld components if the methodology in EPRI BWRVIP-05 was used to request 

relief from augmented inspection requirements for RPV circumferential welds in 

10 CFR 50.55a(g) and if relief was granted in accordance with 10 CFR 50.55a(3) 

requirements for the current operating period

• AAI No. 13 on the need to perform 60-year neutron fluence value assessments for the 

RPV components as input to the TLAAs identified in AAI Nos. 9 through 12

The staff noted that the applicant included its response to these AAIs in LRA Appendix C. The 

staff also verified that the applicant has included all of these assessments as appropriate TLAAs 

for the LRA, as given in following LRA sections:

• LRA Section 4.3.1 for the metal fatigue TLAAs for RPV components

• LRA Sections 4.2.3 and 4.2.4 for the adjusted reference temperature (ART) and P-T 

TLAAs that are needed to ensure that appropriate P-T limits were be developed for the 

period of extended operation

• LRA Section 4.2.2 for the TLAA on USE

• LRA Sections 4.2.5 and 4.2.6 for the mean RTNDT and conditional probability of failure 

analyses of the RPV axial and circumferential weld components

• LRA Section 4.2.1, which provides the 60-year neutron fluence evaluation and TLAA for 

components in the beltline and extended beltline of the RPV

Based on this review, the staff finds the applicant has addressed and resolved the requests in 

AAI Nos. 8 through 13 on the BWRVIP-74-A report because the applicant has included the 

applicable TLAAs in the LRA. The staff’s evaluation of the neutron fluence TLAA for the RPV is 

given in SER Section 4.2.1. The staff’s evaluation of the TLAA on RPV USE is given in SER

Section 4.2.2. The staff’s evaluation of the TLAA on the ART calculations for the RPV 

components is given in SER Section 4.2.3. The staff’s evaluation of the TLAA for the P-T limits 

of the RPV is given in SER Section 4.2.4. The staff’s evaluations of the TLAAs on the mean 

RTNDT and conditional probability of failure analyses for the RPV axial and circumferential weld 

components are given in SER Sections 4.2.5 and 4.2.6. AAI Nos. 8 through 13 on the 

BWRVIP-74-A report are resolved.

AAI No. 6 on BWRVIP-76-A (BWRVIP I&FE Guidelines for BWR Core Shrouds)

In the staff’s SE on EPRI BWRVIP-76-A, dated October 26, 2009, the staff issued AAI No. 6, 

requesting, in part, that BWR applicants address those TLAAs that may be applicable to the 

evaluation of their BWR core shroud components.

In regard to identifying applicable metal fatigue TLAAs for the core shrouds, the applicant 

responded to the AAI request and stated that the core shrouds (including shroud welds) are 

fabricated from either stainless steel or nickel alloy materials. The applicant stated that the CLB 

includes an evaluation of cumulative fatigue damage in the core shroud and that this evaluation 

(i.e., metal fatigue analysis) has been identified as a TLAA for the LRA. The applicant stated 

that the metal fatigue analysis for the core shrouds is assessed in LRA Section 4.3.4.
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The staff verified that the CLB includes the following metal fatigue analyses for the core shrouds 

and associated components: (a) core shroud, (b) core shroud support, and (c) core shroud 

heads and steam separator assemblies. The staff verified that the applicant identified that these 

analyses meet the definition of a TLAA in 10 CFR 54.3(a) and included the fatigue analyses as 

TLAAs for the components in LRA Section 4.3.4.

Therefore, the staff finds that the applicant has adequately addressed AAI No. 4 on EPRI

BWRVIP-76-A because the staff has verified that the applicant has included and evaluated the 

applicable fatigue analyses or fatigue waiver analyses for the core shrouds and associated 

components as TLAAs for LRA Section 4.3.4. The staff’s evaluation of these TLAAs is given in 

SER Section 4.3.4. AAI No. 6 on the BWRVIP-76-A report is resolved with respect to the 

contents of the LRA.

4.1.2.2 Identification of Exemptions in the LRA

As required by 10 CFR 54.21(c)(2), the applicant must identify all exemptions that were granted 

in accordance with the exemption approval criteria in 10 CFR 50.12 and that are based on a 

TLAA. For those exemptions that meet these criteria, the rule requires the applicant to evaluate 

the exemptions and to justify their use during the period of extended operation.

In LRA Section 4.1.2, the applicant stated that it reviewed those exemptions that were granted 

in accordance with the requirements in 10 CFR 50.12 and that were currently in effect for the 

CLBs that apply to LSCS, Units 1 and 2. The applicant stated that none of the exemptions were 

associated with, or supported by, TLAAs. Therefore, the applicant stated that no further 

evaluation of these exemptions is required by the regulation in 10 CFR 54.21(c)(2).

The staff also reviewed the applicant’s CLB to see whether the CLB included any exemptions 

that were granted in accordance with 10 CFR 50.12 and that were based on a TLAA. The 

staff’s review included a review of the current operating licenses and TS for the facility and the 

applicant’s UFSAR. The staff’s review also included an “exemption” keyword search of the 

NRC’s main and legacy libraries in the NRC’s ADAMS Document Control Library. The staff 

reviewed the applicant’s CLB to see if it contained any regulatory exemptions that were based 

on the methods of a TLAA and that might need to be identified for the LRA.

The staff noted that the operating licenses for LSCS, Units 1 and 2, identify that the applicant 

was granted specific exemptions from the requirements in Appendix G, “Fracture Toughness 

Requirements,” to 10 CFR Part 50, which is the rule that applies to the performance of 

mandated time-dependent P-T limit calculations and a USE analysis. Similarly, the staff also 

noted that, in the operating licenses and at specific times during the current operating period, 

the applicant was granted specific exemptions from meeting the requirements for performing 

containment leak rate testing activities, as required in Appendix J, “Primary Reactor 

Containment Leakage Testing for Water-Cooled Power Reactors,” to 10 CFR Part 50. 

However, the staff noted that neither the LRA nor the operating licenses specify what these 

exemptions involved. Therefore, the staff did not have sufficient information to make a 

determination on whether these exemptions (as granted under 10 CFR 50.12) were based on a 

TLAA.

The staff also noted that by letter dated February 29, 2000, the applicant requested exemptions 

to use the methods of analysis in American Society for Mechanical Engineers Boiler and Vessel 

Pressure Code (ASME Code) Cases N-640 and N-588 as bases for departing from the 

methodology requirements for calculating P-T limits, as specified in ASME Code Section XI, 
4-16

Appendix G, and referenced in 10 CFR Part 50, Appendix G. The staff approved these 

exemptions in accordance with the requirements in 10 CFR 50.12 and in an SE, dated 

November 8, 2000.

The staff noted that the applicant had previously identified exemptions for use of ASME Code 

Cases N-640 and N-588 methodologies as exemptions that were previously granted in 

accordance with the requirements in 10 CFR 50.12 and that are based on a TLAA. Therefore, 

the staff noted that the exemption to use the ASME Code Cases N-640 and N-588 for the P-T 

limit calculations of LSCS, Units 1 and 2, might need to be included in the LRA and assessed 

under the requirements of 10 CFR 54.21(c)(2) if the exemption was still in effect and if it had not 

been formally withdrawn from the CLB for the units.

By letter dated July 7, 2015, the staff issued RAI 4.1-3, Parts 1 and 2, requesting that the 

applicant provide additional information regarding the bases for past exemptions that had been 

granted from specific requirements in 10 CFR Part 50, Appendix G or Appendix J. Specifically, 

in RAI 4.1-3, Part 1, the staff asked the applicant to identify all exemptions that were granted in 

accordance with the requirements of 10 CFR Part 50, Appendix G, and 10 CFR Part 50, 

Appendix J. For each exemption, the staff asked the applicant to describe the exemption and to 

clarify whether the exemption basis related to any methodologies for performing TLAA 

calculations or evaluations in the LRA. If so, the staff asked the applicant to justify why the 

specific exemption from the particular requirements in 10 CFR Part 50, Appendix G, or 

10 CFR Part 50, Appendix J, would not need to be identified as an exemption that was granted 

in accordance with 10 CFR 50.12 and that is based on a TLAA, nor evaluated in accordance 

with the exemption evaluation requirements that are specified in 10 CFR 54.21(c)(2).

In RAI 4.1-3, Part 2, the staff asked the applicant to justify why the exemptions to use ASME 

Codes N-640 and N-588 had not been identified as exemptions meeting the criteria in 

10 CFR 54.21(c)(2) when this had been done in another Exelon LRA that was pending staff 

approval.

The applicant responded to RAI 4.1-3, Parts 1 and 2, in a letter dated August 6, 2015. In its 

response to RAI 4.1-3, Part 1, the applicant stated that the exemptions listed in the operating 

licenses and requested in RAI 4.1-3, Part 1, involved the following topics:

• An exemption from the time required to perform 10 CFR Part 50, Appendix J Type A 

containment leak rate tests during the third inservice inspection and testing interval for 

the units. The applicant explained that this exemption was based only on the proposal 

of alternative scheduling criteria from those required by the rule and did not involve any 

time-dependent analysis.

• An exemption that requested alternative leak rate testing of main steam insolation valves 

based on alternative maximum pressure criteria and alternative leak rate acceptance 

criteria. The applicant explained that this exemption was based on use of specific 

alternative criteria and was not based on any time-dependent analysis.

• Exemptions for the requirements in Appendix G and Appendix H, “Reactor Vessel 

Material Surveillance Program Requirements,” to 10 CFR Part 50 that were needed 

because procurement of the reactor vessels for the facilities was based on ASME Code 

editions outside of those specified for use in 10 CFR 50.55a, “Codes and Standards.” 

The applicant explained that these exemptions were based only on the timing of the 

ASME Code editions and were not based on any time-dependent analysis.
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The staff noted that the applicant’s response to RAI 4.1-3, Part 1, adequately explained the 

nature of the exemptions that were included in the operating licenses for the LSCS units and 

provided adequate demonstration that the exemptions were only based on non-time-dependent 

criteria (such as alternative scheduling criteria or other non-time-dependent criteria, such as 

alternative pressure, leak rate, or ASME Code edition criteria) and were not based on any 

time-dependent analysis that would qualify as a TLAA. Therefore, based on this assessment, 

the staff concludes that the applicant adequately demonstrated that these exemptions do not 

conform to the criteria in 10 CFR 54.21(c)(2) because the applicant has adequately

demonstrated that the exemptions were not based on a TLAA. RAI 4.1-3, Part 1, is resolved.

In its response to RAI 4.1-3, Part 2, the applicant addressed the exemptions to use methods of 

analysis in ASME Code Cases N-588 and N-640 for P-T limit calculations. The applicant stated 

that use of ASME Code Case N-588 is not relevant to the P-T limit evaluations of the RPVs at 

LSCS because neither of the RPVs is limited in the beltline region by a circumferential weld. 

Therefore, the applicant explained that, for P-T limit assessments, the Unit 1 RPV is limited by 

the ferritic weld material for an axial weld location and that the Unit 2 RPV is limited by the 

ferritic base metal material for an RPV lower intermediate shell plate location. Therefore, the 

applicant stated that, in the SE of November 8, 2000, the staff determined that the exemption to 

use ASME Code Case N-588 was not necessary for application to the CLB.

The applicant also clarified that, upon further review, the exemption to apply ASME Code 

Case N-640 as part of the basis for performing P-T limit calculations was applicable to the CLB. 

The applicant determined that the exemption to use ASME Code Case N-640 was based on a 

TLAA. Therefore, in the letter of August 6, 2015, the applicant amended the LRA to identify the 

exemption to use ASME Code Case N-640 as an exemption that (a) conformed to the criteria in 

10 CFR 54.21(c)(2) and (b) was granted in accordance with 10 CFR 50.12 and is based on a 

TLAA. The applicant clarified that use of ASME Code Case N-640 will not be necessary for 

calculation of future P-T limits in the future because the methods of analysis in the ASME Code 

Case have been incorporated into editions of the ASME Code Section XI, Appendix G, that are 

incorporated by reference by 10 CFR 50.55a and that the applicant will be using the most recent 

ASME Code Section XI edition of record required by 10 CFR 50.55a as the basis for performing 

the P-T limit calculations in the future.

The staff finds that ASME Code Case N-588 is not applicable to the CLB because the staff has 

verified that the NRC did not add the ASME Code Case to the CLB in the SE of 

November 8, 2000. The staff also finds that the applicant has addressed the issue with use of 

ASME Code Case N-640 because the applicant has amended the application to identify the 

exemption for this ASME Code Case as an exemption that was granted in accordance with 

10 CFR 54.21(c)(2) and that is based on a TLAA, and the applicant has provided an applicable 

analysis that provides adequate demonstration that ASME Code Case N-640 will not be used 

for the calculation of any updated P-T limits that may be necessary for the CLB in the future. 

RAI 4.1-3, Part 2, is resolved.

4.1.3 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has 

provided an acceptable list of TLAAs as defined in 10 CFR 54.3(a). The staff also concludes 

that the applicant has complied with the requirements in 10 CFR 54.21(c)(2) and has 

appropriately identified the exemption related to ASME Code Case N-640 as an exemption that 

was granted in accordance with 10 CFR 50.12 and that is based on a TLAA.
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4.2 Reactor Vessel and Internals Neutron Embrittlement Analyses

LRA Section 4.2 provides the applicant’s analyses of the following areas related to neutron 

fluence:

• LRA Section 4.2.1, Neutron Fluence Analyses

• LRA Section 4.2.2, Upper-Shelf Energy Analyses

• LRA Section 4.2.3, Adjusted Reference Temperature Analyses

• LRA Section 4.2.4, Pressure-Temperature Limits

• LRA Section 4.2.5, Axial Weld Failure Probability Assessment Analyses

• LRA Section 4.2.6, Circumferential Weld Failure Probability Assessment Analyses

• LRA Section 4.2.7, Reactor Pressure Vessel Reflood Thermal Shock Analyses

• LRA Section 4.2.8, RPV Core Plate Rim Hold-Down Bolt Loss of Preload Analysis

• LRA Section 4.2.9, Jet Pump Riser Brace Clamp Loss of Preload Analysis

• LRA Section 4.2.10, Jet Pump Slip Joint Repair Clamp Loss of Preload Analysis

4.2.1 Neutron Fluence Analyses

4.2.1.1 Summary of Technical Information in the Application

LRA Section 4.2.1 describes the applicant’s TLAA for reactor vessel neutron fluence. The LRA 

states that the peak neutron fluences projected for 54 effective full-power years (EFPY) are 

1.06x1018 n/cm2 for LSCS, Unit 1, and 1.22x1018 n/cm2 for LSCS, Unit 2, at the vessel inner 

surface. In addition, the one-quarter thickness (1/4T) peak fluence values (E > 1 MeV) for 

54 EFPY are as follows for LSCS, Unit 1: 2.64x1017 n/cm2 for lower shell assembly plates, 

7.41x1017 n/cm2 for the lower-intermediate shell assembly, 6.28x1017 n/cm2 for the middle shell 

assembly, 2.30x1017 n/cm2 for lower shell axial welds, 7.03x1017 n/cm2 for lower-intermediate 

shell axial welds, 6.04x1017 n/cm2 for middle shell axial welds, 6.28x1017 n/cm2 for the lower 

intermediate-to-lower shell circumferential weld, and 2.64x1017 n/cm2 for the middle-to-lower 

intermediate shell circumferential weld. The 1/4T peak fluence values (E > 1 MeV) for 54 EFPY 

are as follows for LSCS, Unit 2: 7.41x1017 n/cm2 for lower shell assembly plates, 

8.52x1017 n/cm2 for the lower-intermediate shell assembly, 6.50x1017 n/cm2 for lower shell axial 

welds, 8.02x1017 n/cm2 for lower-intermediate shell axial welds, and 7.41x1017 n/cm2 for the 

lower-to-lower-intermediate shell circumferential weld.

The reactor vessel neutron fluence values for LSCS, Units 1 and 2, for 60 years of operation 

(54 EFPY) are calculated using the RAMA methodology documented in EPRI 

BWRVIP-114NP-A, “RAMA Fluence Methodology Theory Manual,” and its companion reports.1

 

The RAMA methodology adheres to the guidance prescribed in the NRC’s Regulatory Guide 

(RG) 1.190, “Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron 

Fluence,” dated March 2001. The neutron fluence calculation results are inputs into the other 

reactor vessel neutron embrittlement TLAAs, such as analyses for adjusted reference 

temperatures and P-T limits.

 1 The companion reports are EPRI BWRVIP-115NP-A, “RAMA Fluence Methodology Benchmark Manual –

Evaluation of Regulatory Guide 1.190 Benchmark Problems”; BWRVIP-117NP-A, “RAMA Fluence Methodology 

Plant Application – Susquehanna Unit 2 Surveillance Capsule Fluence Evaluation for Cycles 1-5”; and 

BWRVIP-121NP-A, “RAMA Fluence Methodology Procedures Manual.”
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The applicant dispositioned the TLAA for reactor vessel neutron fluence in accordance with 

10 CFR 54.21(c)(1)(ii) to demonstrate that the analysis has been projected to the end of the 

period of extended operation.

4.2.1.2 Staff Evaluation

The staff evaluated the applicant’s neutron fluence analysis for the reactor vessel, consistent 

with the review procedures in SRP-LR Section 4.2, which state that the applicant should 

(a) identify the neutron fluence for the reactor vessel at the end of the license renewal period, 

(b) identify the staff-approved methodology used to determine the neutron fluence or submit the 

methodology for staff review, and (c) determine whether the methodology follows the guidance 

in RG 1.190.

The staff noted that the NRC-approved 32-EFPY P-T limits for Unit 1 are based on the use of 

RAMA neutron fluence methodology. The staff also noted that the NRC-approved 32-EFPY P-T 

limits for Unit 2 are based on the use of the GEH method for neutron fluence calculation as 

described in the NRC-approved GE Licensing Topical Report NEDO-32983P-A, “General 

Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluations,” dated 

January 31, 2006. The staff further noted that the fluence calculation uncertainty analysis and 

qualification of these methodologies adhere to the guidance contained in RG 1.190. 

Specifically, the staff’s acceptance of the RAMA methodology is described in the SE, dated 

May 13, 2005, for the BWRVIP-114NP-A report, and the GEH methodology is described in the 

SE, dated November 17, 2005, for NEDO-32982P-A.

In its review, the staff noted that LRA Section 4.2.1 does not clearly discuss the current use of 

the RAMA and GEH methodologies for 40 years of operation. Therefore, the staff found a need 

to confirm whether these two methodologies are also used to calculate the 60-year reactor 

vessel neutron fluence of LSCS, Units 1 and 2.

By letter dated August 18, 2015, the staff issued RAI 4.2.1-1, Part 1, requesting that the 

applicant clarify whether the 54-EFPY neutron fluences described in the LRA are based on the 

GEH methodology, the RAMA methodology, or a combination of the two methodologies.

In the applicant’s response dated September 15, 2015, the applicant confirmed that the 

54-EFPY neutron fluence projections for LSCS, Units 1 and 2, described in LRA Section 4.2 to 

account for reactor vessel exposure from 0 to 54 EFPY are based on the NRC-approved RAMA 

fluence methodology. The applicant also revised LRA Section 4.2.1 to further clarify the 

methodologies that were used to calculate the 40-year and 60-year neutron fluence values for 

Units 1 and 2.

Based on its review, the staff finds the applicant’s response acceptable based on the applicant 

confirming that the 60-year reactor vessel neutron fluence values are calculated using the 

NRC-approved RAMA methodology and revising LRA Section 4.2.1 adequately to provide 

additional background information and clarification regarding the methodology for the 60-year 

reactor vessel neutron fluence calculations. Part 1 of RAI 4.2.1-1 is resolved. Part 2 of 

RAI 4.2.1-1 is discussed in SER Section 4.2.4.2.

Based on its review, the staff determined that the applicant adequately addressed the TLAA on 

the reactor vessel neutron fluence for the period of extended operation because the fluence 

evaluation was performed in accordance with NRC-approved, RG 1.190-adherent methodology, 

and the applicant provided 54-EFPY fluence values to cover the period of extended operation.
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4.2.1.3 UFSAR Supplement

LRA Section A.4.2.1 provides the UFSAR supplement summarizing the TLAA on the reactor 

vessel neutron fluence. The staff reviewed LRA Section A.4.2.1, consistent with the review 

procedures in SRP-LR Section 4.2, which state that the applicant should provide a summary 

description of the evaluation of the reactor vessel neutron embrittlement. Based on the staff’s 

review of the UFSAR supplement, the staff determined that the applicant provided an adequate 

summary description of the actions to address the neutron fluence analysis, as required by 

10 CFR 54.21(d).

4.2.1.4 Conclusion

The staff concluded that the applicant has provided an acceptable demonstration, pursuant to

10 CFR 54.21(c)(1)(ii), that the neutron fluence analysis for the reactor vessel has been 

projected to the end of the period of extended operation. The staff also concludes that the 

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.2.2 Upper-Shelf Energy Analyses

The NRC’s requirements for performing USE analyses of ferritic materials (i.e., steel plate or 

forging components) and ferritic welds in the beltline region of the RPV are specified in 

10 CFR Part 50, Appendix G. The rule requires the USE values for these RPV components to 

be greater than or equal to 50 ft-lb at the end of the licensed operating period. These analyses 

are TLAAs because the analyses meet all six of the criteria in 10 CFR 54.3(a) that define an 

analysis as a TLAA.

4.2.2.1 Summary of Technical Information in the Application

LRA Section 4.2.2, as revised by letter dated September 28, 2015, describes the applicant’s 

TLAA evaluation for the calculation of the USE of the LSCS, Units 1 and 2, RPV beltline 

materials. The LRA states that USE values for the Unit 1 and Unit 2 RPV beltline materials 

have been updated based on 54 EFPY for 60 years of plant operation using the neutron fluence 

values at 1/4T for each location. The LRA also states that the methods used to calculate the 

fluence values at 1/4T for 54 EFPY and to project the USE values are consistent with RG 1.99, 

Revision 2, “Radiation Embrittlement of Reactor Vessel Materials,” dated May 1988. The 

fluence values at 1/4T are determined using the dpa method which replaces the exponential 

attenuation factor in Equation 3 of RG 1.99, Revision 2. The LRA further states that the N12 

water level instrument nozzles and N6 LPCI nozzles are within the RPV beltline. The LRA 

clarifies that the N12 nozzles and welds are nickel alloy 600 and, therefore, do not require 

evaluation. The plates surrounding the N12 nozzles are ferritic and are evaluated at the 1/4T

location along the limiting pressure stress cross-section extraction path, which is shown in LRA 

Figure 4.2.2-1. The N6 LPCI nozzles and welds are ferritic materials and are also evaluated at 

the 1/4T location along the limiting pressure stress cross-section extraction path as shown in 

LRA Figure 4.2.2-2. LRA Table 4.2.2-1 and Table 4.2.2-2, for Unit 1 and Unit 2, respectively, 

provide the USE values calculated for 54 EFPY for each location evaluated, as well as the 

unirradiated values and associated copper content percentages.

The applicant dispositioned the TLAA for the calculation of the USE for the ferritic RPV beltline 

materials in accordance with 10 CFR 54.21(c)(1)(ii) to demonstrate that the analyses have been 

projected to the end of the period of extended operation.
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4.2.2.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the calculation of the USE for the ferritic RPV 

beltline materials and the corresponding disposition of 10 CFR 54.21(c)(1)(ii), consistent with 

the review procedures in SRP-LR Section 4.2.3.1.1.2. These procedures state that the staff is 

to review the documented results of the applicant’s updated USE analysis based on the 

projected neutron fluence at the end of the period of extended operation for compliance with 

10 CFR Part 50, Appendix G. The regulations in 10 CFR Part 50, Appendix G, require that the 

USE values of the ferritic RPV components be greater than or equal to 50 ft-lb at the end of the 

licensed operating period. These procedures also state that the applicant may use RG 1.99, 

Revision 2, to project the USE to the end of the period of extended operation.

The staff reviewed Revision 20 to UFSAR Section 5.2.3.3.1, “Fracture Toughness,” to verify that 

the initial unirradiated Charpy USE values and copper content percentages provided in LRA

Table 4.2.2-1 and Table 4.2.2-2 are consistent with the CLB for LSCS, Units 1 and 2,

respectively. UFSAR Section 5.2.3.3.1.2.2, “Alternative Compliance with 10 CFR 50 

Appendix G,” provides two references by GE Nuclear Energy, dated May 2004, that describe 

the methodologies used to comply with 10 CFR Part 50, Appendix G, and the associated staff 

evaluation, dated April 15, 2011, finding these methods acceptable. The staff verified that the 

unirradiated USE values and copper content percentages provided in LRA Table 4.2.2-1 and

Table 4.2.2-2 are consistent with the CLB, with the exception of the N6 LPCI nozzle welds. The 

relevant information for the N6 LPCI nozzle welds was not included in the references reviewed 

by the staff.

By letter dated August, 28, 2015, the staff issued RAI 4.2.2-1, requesting that the applicant 

provide information associated with the USE and ART analyses. Aspects of RAI 4.2.2-1 

associated with the ART analysis are reviewed in SER Section 4.2.3. Part 1 of RAI 4.2.2-1 

requested that the applicant provide either (a) documentation that confirms that the N6 LPCI 

nozzle weld unirradiated USE values and copper content percentages in LRA Table 4.2.2-1 and

Table 4.2.2-2 are part of the CLB and have been reviewed and accepted by the staff, or (b) the 

source and technical substantiation of the values if the N6 LPCI nozzle welds were added to the 

evaluation for license renewal.

In its response dated September 28, 2015, the applicant revised LRA Tables 4.2.2-2 and 

4.2.2-3 to correct administrative entries that are unrelated to the copper contents, unirradiated 

USE values, or fluence values. The response stated that the percent copper values for the 

LSCS, Units 1 and 2, N6 LPCI nozzle welds are obtained from the certified material test reports 

(CMTRs) for the specific material heats, except the EAIB weld heat for Unit 1. The CMTR for 

the Unit 1 EAIB weld heat did not contain the percent copper value. The applicant also stated 

that the percent copper for the EAIB weld was determined using data from the BWR fleet 

database and the NRC Reactor Vessel Information Database for shielded metal-arc welding 

(SMAW) materials. The databases contained 86 unique data points that were evaluated using a 

mean+2σ statistical methodology to determine the percent copper content. The applicant 

further stated that the percent copper values for the Unit 1 N6 LPCI nozzle welds has been 

previously reviewed and approved by the NRC. Additionally, the applicant stated that the 

unirradiated USE values for the N6 LPCI nozzle welds provided in LRA Tables 4.2.2-1 

and 4.2.2-2 are generic values for low-alloy steel SMAW material.

The staff reviewed the applicant’s response and finds it acceptable because the percent copper 

values for the N6 LPCI nozzle weld material were provided in the applicant’s license 

amendment request to revise the P-T curves for LSCS, Unit 1, which was approved by the NRC 
4-22

in the safety evaluation dated November 25, 2014. In this safety evaluation, the staff noted that 

the copper content for the EAIB weld heat is conservatively estimated. The unirradiated USE 

value used for the N6 LPCI nozzle weld material is 72.8 ft-lb. The staff noted that Section B.3.1 

of EPRI BWRVIP-74-A, “BWR Reactor Pressure Vessel Inspection and Flaw Evaluation 

Guidelines for License Renewal,” provides a generic RPV USE analysis and equivalent margins 

analysis (EMA) that may be applied by applicants owning BWR units. The staff noted that the 

generic methodology in the BWRVIP-74-A report is based on a limiting statistical analysis of 

unirradiated USE data for BWR ferritic materials and was approved by an NRC letter dated 

September 16, 2003. The staff noted that the statistical analysis established a lower bounding 

unirradiated USE value of 84.5 ft-lb for SMAW welds.

In summary, the percent copper values for the Unit 1 and Unit 2 N6 LPCI nozzle welds has 

been previously reviewed and approved by the NRC in a safety evaluation dated 

November 25, 2014. The percent copper values for the Unit 1 and Unit 2 N6 LPCI nozzle welds 

were obtained from the CMTRs for the specific material heats, except the EAIB weld heat for 

Unit 1. The unirradiated USE values for the Unit 1 and Unit 2 N6 LPCI nozzle welds are generic

values for low alloy steel SMAW material which the staff has determined to be conservative 

based on the lower bounding unirradiated USE value in BWRVIP-74-A. The staff’s concerns, 

associated with the USE evaluation, described in Part 1 of RAI 4.2.2 1, are resolved.

The fluence values that are used to project the USE values to the end of the period of extended 

operation (54 EFPY) are provided in LRA Tables 4.2.1-2 through 4.2.1-6. The LRA states that 

the methods used to calculate the fluence values at 1/4T for 54 EFPY are consistent with 

RG 1.99, Revision 2. The staff’s evaluation of the neutron fluence analyses is in SER 

Section 4.2.1.

The staff noted that the guidance in RG 1.99, Revision 2, provides two methods for projecting 

USE values to the end of the licensed operating period. Regulatory Position 1.2 in RG 1.99, 

Revision 2, projects the USE values at the end of the licensed operating period using a 

graphical relationship from Figure 1 of the RG to determine the percent decrease in USE as a 

function of copper content and fluence. Regulatory Position 2.2 in RG 1.99, Revision 2, projects 

the USE values at the end of the licensed operating period using plant surveillance data to 

adjust the graphical relationship in Regulatory Position 1.2. The LRA states that the USE 

values were projected to 54 EFPY based on methods consistent with RG 1.99, Revision 2. The

staff noted that the USE values projected to 54 EFPY are provided in LRA Table 4.2.2-1 and

Table 4.2.2-2; however, it is unclear to the staff if RPV surveillance data were applied to the 

USE value projections. To address this issue, Part 2 of RAI 4.2.2-1 requested that the applicant 

clarify if it used surveillance data to calculate any of the projected USE values and to distinguish 

between USE values that were calculated using Regulatory Position 1.2 and Regulatory 

Position 2.2. Part 3 of RAI 4.2.2-1 requested that the applicant identify any surveillance data 

reports associated with capsule withdrawals and test results obtained from the Integrated 

Surveillance Program (ISP) that are applicable to either LSCS, Units 1 or 2.

In its response dated September 28, 2015, the applicant stated that Regulatory Position 1.2 was 

used to identify the limiting USE values for both LSCS, Units 1 and 2. The applicant stated that 

Unit 1 has credible surveillance data for representative plate and weld material that meet the 

criteria of RG 1.99, Revision 2. The USE values for the representative plate (heat C6345-1) and 

weld material (heat 1P3571) are provided in LRA Table 4.2.2-1, as revised by letter dated 

September 28, 2015, under the heading, “Unit 1 Integrated Surveillance Program Chemistry 

Values from BWRVIP-135 Revision 3.” The applicant stated that these integrated surveillance 

program (ISP) USE values were the only values determined using Regulatory Position 2.2 for 
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Unit 1, although the USE values for RPV beltline components determined using Regulatory 

Position 1.2 (i.e., that are not represented by ISP surveillance data) for the corresponding heats,

are more limiting.

The applicant stated that LSCS, Unit 2, does not have credible surveillance data for 

representative plate and weld material that meet the criteria of RG 1.99, Revision 2. The USE 

values determined using surveillance data are provided in LRA Table 4.2.2-2, as revised by 

letter dated September 28, 2015, under the heading, “Unit 2 Integrated Surveillance Program 

Chemistry Values from BWRVIP-135 Revision 3.” The applicant stated that these ISP USE 

values for plate (heat C3054-2) and weld material (heat 402K9171, 411L3071) were the only 

values determined using Regulatory Position 2.2 for Unit 2. The applicant further stated that 

these values are provided for reference only.

The applicant stated that it previously submitted the following technical summary reports to the 

NRC in accordance with Section IV, “Report of Test Results,” of Appendix H to 10 CFR Part 50:

• EPRI Letter 2011-206, “Project No. 704 – BWRVIP-250NP: BWR Vessel and Internals 

Project, Testing and Evaluation of the LaSalle Unit 1 120° Surveillance Capsule”

• EPRI Letter 2013-188, “Project No. 704 – BWRVIP-275NP: BWR Vessel and Internals 

Project, Testing and Evaluation of the Susquehanna Unit 1 120° Surveillance Capsule”

The staff reviewed the applicant’s response and finds it acceptable because the applicant 

clarified the use of Regulatory Position 1.2 and Regulatory Position 2.2. Regulatory Position 1.2 

was used to determine the limiting 60-year USE values for both LSCS, Units 1 and 2. The 

limiting 60-year USE values for Unit 1 are 68 ft-lb for forgings (heat Q2Q22W) and 62 ft-lb for 

weld material (heat 1P3571). The limiting 60-year USE values for Unit 2 are 53 ft-lb for plate 

(heat C9434–2) and 55 ft-lb for weld material (heat 5P6771). The applicant also provided the 

technical summary reports associated with capsule withdrawals and test results obtained from 

the ISP that are applicable to either Unit 1 or Unit 2. The staff verified that ISP material heats 

referenced for each Unit are consistent with the surveillance capsules identified in BWRVIP-86, 

Revision 1, “Updated BWR Integrated Surveillance Program (ISP) Implementation Plan,” which 

has been approved by the staff. The staff’s concerns, associated with the USE evaluation, 

described in Part 2 of RAI 4.2.2-1 are resolved. The staff’s concerns described in Part 3 of 

RAI 4.2.2-1 are also resolved.

Based on its review, the staff finds that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that the USE analyses for the ferritic materials and ferritic welds in the 

beltline region of the RPV have been projected to the end of the period of extended operation. 

Additionally, it meets the acceptance criteria in SRP-LR Section 4.2.2.1.1 because the USE 

values of the LSCS, Units 1 and 2, ferritic RPV beltline materials comply with the requirements 

in 10 CFR Part 50, Appendix G. Specifically, the USE values that have been projected to the 

end of the extended operating period all exceed 50 ft-lbs.

4.2.2.3 UFSAR Supplement

LRA Section A.4.2.2 provides the UFSAR supplement summarizing the USE analyses for the 

ferritic materials and ferritic welds in the beltline region of the RPV. The staff reviewed LRA 

Section A.4.2.2 consistent with the review procedures in SRP-LR Section 4.2.3.2, which state 

that the reviewer must verify that the applicant has provided a supplement with information that 

is equivalent to the examples in SRP-LR Table 4.2-1.
4-24

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SRP-LR Section 4.2.2.2 and, therefore, is acceptable. Additionally, the staff 

determines that the applicant provided an adequate summary description of its actions to 

address the USE analyses for the ferritic materials and ferritic welds in the beltline region of the 

RPV, as required by 10 CFR 54.21(d).

4.2.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the USE analyses for the ferritic 

materials and ferritic welds in the beltline region of the RPV have been projected to the end of 

the period of extended operation. The staff also concludes that the UFSAR supplement 

contains an appropriate summary description of the TLAA evaluation, as required by 

10 CFR 54.21(d).

4.2.3 Adjusted Reference Temperature Analyses

4.2.3.1 Summary of Technical Information in the Application

LRA Section 4.2.3, as revised by letter dated September 28, 2015, describes the applicant’s 

TLAA evaluation of the ARTs for the ferritic reactor vessel beltline materials (plates, forgings, 

and welds). The LRA states that ART values for LSCS, Units 1 and 2, RPV beltline materials 

have been updated based on 54 EFPY for 60 years of plant operation using the neutron fluence 

values at 1/4T for each location. The LRA also states that the methods used to calculate the 

fluence values at 1/4T for 54 EFPY and to project the ART values are consistent with RG 1.99, 

Revision 2, “Radiation Embrittlement of Reactor Vessel Materials.” The ferritic material within 

the beltline include the shell plates, axial welds, circumferential welds, N6 LPCI nozzle forgings, 

and N6 LPCI welds. The LRA states that the N12 water level instrument nozzles and welds are 

nickel alloy, although the 1/4T location along the limiting pressure stress cross-section is located 

within the surrounding ferritic plate, as shown in LRA Figure 4.2.2-1. The LRA further states 

that the ART values for the N12 water level instrument nozzles and welds were determined 

using the values for the surrounding ferritic plate material.

LRA Table 4.2.3-1 and Table 4.2.3-2 provide the 54-EFPY ART values and associated 

information for each location evaluated for LSCS, Unit 1. The Unit 1 RPV was fabricated by CE, 

and the beltline region is illustrated in LRA Figure 4.2.1-1. LRA Table 4.2.3-3 and Table 4.2.3-4 

provide the 54-EFPY ART values and associated information for each location evaluated for 

Unit 2. The Unit 2 RPV was fabricated by CB&I, and the beltline region is illustrated in LRA 

Figure 4.2.1-2.

The applicant dispositioned the TLAA for the ferritic RPV beltline materials in accordance with 

10 CFR 54.21(c)(1)(ii) to demonstrate that the ART values have been projected to the end of 

the period of extended operation.

4.2.3.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the ferritic RPV beltline materials and the 

corresponding disposition of 10 CFR 54.21(c)(1)(ii), consistent with the review procedures in 

SRP-LR Section 4.7.3.1.2. These procedures state that the staff is to review the results of the 

applicant’s revised analysis to verify that the evaluation period has been extended such that the 

analysis is valid for the period of extended operation. SRP-LR Section 4.7.3.1.2 also states that 
4-25

the applicant may recalculate the analysis using a 60-year period to show that the acceptance 

criteria continue to be satisfied for the period of extended operation.

The staff reviewed Revision 20 to UFSAR Section 5.2.3.3.1, “Fracture Toughness,” and

Section 5.2.3.3.1.2.2, “Alternative Compliance with 10 CFR 50 Appendix G,” and the applicable 

reference documents to verify that the initial unirradiated RTNDT values, copper content 

percentages, and nickel content percentages provided in LRA Section 4.2.3-1, Table 4.2.3-2, 

Table 4.2.3-3, and Table 4.2.3-4 are consistent with the CLB. The specific reference 

documents reviewed are described in SER Section 4.2.2.2. The staff verified that the initial 

RTNDT values and composition percentages provided in these LRA Section 4.2.3 tables are 

consistent with the CLB, with the exception of the N6 LPCI nozzle welds.

By letter dated August 28, 2015, the staff issued RAI 4.2.2-1, requesting that the applicant 

provide information associated with the USE and ART analyses. Aspects of RAI 4.2.2-1 

associated with the USE analysis are reviewed in SER Section 4.2.2. Part 1 of RAI 4.2.2-1 

requested that the applicant provide either (a) documentation that confirms the N6 LPCI nozzle 

weld initial RTNDT values and composition percentages in LRA Table 4.2.3-2 and Table 4.2.3-4

are part of the CLB and have been reviewed and accepted by the staff, or (b) the source and 

technical substantiation of the values if the N6 LPCI nozzle welds were added to the evaluation 

for license renewal.

In its response dated September 28, 2015, the applicant stated that the percent nickel values for 

LSCS, Units 1 and 2, N6 LPCI nozzle welds are obtained from the CMTRs for the specific 

material heats. The applicant responded similarly for the percent copper values, as described in 

SER Section 4.2.2. The applicant also stated that the initial RTNDT values for Units 1 and 2 were 

determined using the GE/Boiling Water Reactor Owners Group (BWROG) methodology defined 

in NEDC-32399-P, “Basis for GE RTNDT Estimation Method,” dated September 1994. The 

applicant further stated that the information associated with the Unit 1 N6 LPCI nozzle welds is 

part of the CLB.

The staff reviewed the applicant’s response and finds it acceptable because the initial RTNDT

values and composition percentages for the N6 LPCI nozzle weld material were provided in the 

applicant’s license amendment request to revise the P-T curves for LSCS, Unit 1, and were 

approved in an NRC safety evaluation dated November 25, 2014. The RTNDT values and 

composition percentages for Unit 2 were determined in the same manner as those for Unit 1. 

The percent copper and nickel values for Unit 2 were obtained from the CMTRs for the specific 

material heats. The initial RTNDT values for the Unit 2 N6 LPCI nozzle welds were determined 

using the GE/BWROG methodology defined in GE Nuclear Energy report NEDC-32399-P, 

dated September 1994, which was approved in an NRC SE, dated December 16, 1994. The 

staff’s concerns, associated with the ART evaluation, described in Part 1 of RAI 4.2.2-1 are 

resolved.

The fluence values that are used to project the ART values to the end of the licensed operating 

period (54 EFPY) are provided in LRA Section 4.2.1. The LRA states that the methods used to 

calculate the fluence values at 1/4T for 54 EFPY are consistent with RG 1.99, Revision 2. The 

staff’s evaluation of neutron fluence analyses is in SER Section 4.2.1.

The guidance in RG 1.99, Revision 2, provides two methods for projecting ART values to the 

end of the licensed operating period. Regulatory Position 1.1 in RG 1.99, Revision 2, projects 

the ART values at the end of the licensed operating period using the initial RTNDT, material 

composition, and fluence when there is no credible surveillance data available. Regulatory 
4-26

Position 2.1 in RG 1.99, Revision 2, projects the ART values at the end of the licensed 

operating period using surveillance data when there are two or more credible data sets 

available. The LRA states that the ART values were projected to 54 EFPY based on methods 

consistent with RG 1.99, Revision 2; however, it is unclear to the staff if surveillance data are

used in these projections. To address this issue, Part 2 of RAI 4.2.2-1 requested that the 

applicant clarify if it used surveillance data to calculate any of the projected ART values and to 

distinguish between ART values that were calculated using Regulatory Position 1.1 and 

Regulatory Position 2.1. Part 3 of RAI 4.2.2-1 is associated with the reporting of surveillance 

program data and is reviewed in SER Section 4.2.2.2.

In its response dated September 28, 2015, the applicant stated that credible surveillance data 

are available for LSCS, Unit 1, but not for Unit 2. The applicant stated that Regulatory 

Position 2.1 was used to calculate the ART values for the plate (heat C6345-1) and weld 

(heat 1P3571) materials provided in LRA Table 4.2.3-2 under the heading, “Unit 1 Integrated 

Surveillance Program Chemistry Values from BWRVIP-135 Revision 3.” All other ART values 

for the Unit 1 RPV in LRA Table 4.2.3-1 and Table 4.2.3-2 are determined using Regulatory 

Position 1.1. The applicant also stated that the ART values determined using Regulatory 

Position 2.1 are greater than those determined using Regulatory Position 1.1. The applicant 

further stated that the highest ART values are limiting; therefore, the values determined using 

Regulatory Position 2.1 are limiting for heats C6345-1 and 1P3571.

For Unit 2, the applicant stated that Regulatory Position 2.1 was used to calculate ART values 

for the plate and weld materials provided in LRA Table 4.2.3-4 under the heading, “Unit 2

Integrated Surveillance Program Chemistry Values from BWRVIP-135 Revision 3.” The 

applicant also stated these heats of material do not meet the criteria in RG 1.99, Revision 2, for 

verifying the credibility of RPV surveillance data and that the information is provided for 

reference only. The applicant indicated that all other ART values for the LSCS, Unit 2, RPV in 

LRA Table 4.2.3-3 and Table 4.2.3-4 are determined using Regulatory Position 1.1.

The staff reviewed the applicant’s response and finds it acceptable because the applicant 

clarified the use of Regulatory Position 1.2 and Regulatory Position 2.2. The limiting 60-year 

ART values for LSCS, Unit 1, are 59 °F for the limiting RPV plate component (heat B0078-1) 

and 139 °F for the limiting RPV weld component (heat 1P3571). The limiting ART values for 

Unit 1 were determined using Regulatory Position 1.1 for the plate material and Regulatory 

Position 2.1 for the weld material. The limiting 60-year ART values for Unit 2 are 90 °F for the 

limiting RPV plate component (heat C9425-1) and 25 °F for the limiting RPV weld component 

(heat 3P4966). The limiting ART values for Unit 2 were determined using Regulatory 

Position 1.1 for both the plate and weld material. The staff’s concerns, associated with the ART

evaluation, described in Part 2 of RAI 4.2.2-1 are resolved.

Based on its review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that the ART analysis for the ferritic RPV materials has been projected to 

the end of the period of extended operation. Additionally, the ART analysis meets the 

acceptance criteria in SRP-LR Section 4.7.3.1.2 because the applicant’s analysis adequately 

evaluates the effects of neutron irradiation embrittlement, including the surveillance data, in 

accordance with RG 1.99, Revision 2.

4.2.3.3 UFSAR Supplement

LRA Section A.4.2.3 provides the UFSAR supplement summarizing the ART analysis for the 

ferritic RPV materials. The staff reviewed LRA Section A.4.2.3 consistent with the review 
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procedures in SRP-LR Section 4.7.3.2, which state that the reviewer must verify that the 

applicant has provided information to be included in the UFSAR supplement that includes a 

summary description of the evaluation of the TLAA.

Based on its review of the UFAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2 and, therefore, is acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address ART analysis for 

the ferritic RPV materials, as required by 10 CFR 54.21(d).

4.2.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the ART analysis for the ferritic RPV 

beltline components has been projected to the end of the period of extended operation. The 

staff also concludes that the UFSAR supplement contains an appropriate summary description 

of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.2.4 Pressure-Temperature Limits

4.2.4.1 Summary of Technical Information in the Application

LRA Section 4.2.4 describes the applicant’s TLAA for pressure-temperature (P-T) limits. The 

technical information that the applicant provided in the LRA is summarized in this section.

The regulations in 10 CFR Part 50, Appendix G, require that the reactor vessel be maintained 

within established P-T limits. These limits specify the minimum acceptable reactor coolant 

temperature as a function of reactor pressure. As the reactor vessel is exposed to increased

neutron irradiation over time, the P-T limits must account for the reduction in fracture toughness 

due to anticipated reactor vessel fluence. The current P-T limit curves are located in the TS and 

are based the cumulative neutron fluence levels for the reactor vessels through 32 EFPY of 

licensed operations. Because the P-T limits for 32 EFPY are based on the nominal amount of 

power assumed for 40 years of plant operation, the P-T limits satisfy the criteria of 

10 CFR 54.3(a) and have been identified as a TLAA.

The LRA states that the P-T limits are currently located in the TS, but a pressure-temperature 

limit report (PTLR) may be submitted for NRC approval for the next P-T limit update, which must 

occur before 32 EFPY. Updated P-T limits will be approved for use before 32 EFPY for each 

unit. Maintenance of the P-T limits during the period of extended operation will be managed

through the licensing process in 10 CFR 50.90, “Application for Amendment of License, 

Construction Permit, and Early Site Permit,” as currently required by TS or by the PTLR process 

and the plant’s administrative controls section of the TS if a PTLR has been approved at that 

time.

The applicant dispositioned this TLAA on the P-T limits for the reactor vessels in accordance 

with 10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of loss of fracture toughness due to 

neutron irradiation embrittlement on the intended functions of the reactor vessels will be 

adequately managed.
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4.2.4.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the reactor vessels and the corresponding 

disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures in SRP-LR 

Section 4.2.3.1.3.3. The review procedures indicate that (1) updated P-T limits for the period of 

extended operation must be available before the period of extended operation, and (2) an 

adequate process to maintain and update the P-T limits through the period of extended

operation is the 10 CFR 50.90 process for P-T limits located in the limiting conditions of 

operation (LCO) of the plant TS, or an administrative process for updating P-T limits located in a 

PTLR, as controlled by the administrative controls section of the plant TS.

SRP-LR Section 4.2.3.1.3.3 also states that, for BWRs, the staff confirms that the applicant 

addresses license renewal AAI No. 9 that is specified in the staff’s SE for the BWRVIP-74

report. The action item is that the applicant, who has not provided updated P-T limits for the 

period of extended operation, shall have a process for updating P-T limits before the period of 

extended operation in accordance with 10 CFR Part 50, Appendix G, to cover updates to the PT limits during the period of extended operation.

The staff reviewed the applicant’s CLB to determine whether the applicant updates its P-T limits 

through updates of the LCOs in the plant TS in accordance with the 10 CFR 50.90 license 

amendment process or through a PTLR process that is governed and controlled by the 

administrative controls section of the plant TS.

In its review, the staff noted that, by its letter dated April 15, 2011, the NRC approved the 

32-EFPY P-T limits for LSCS, Units 1 and 2, through the 10 CFR 50.90 license amendment 

process. The staff also noted that the applicant’s P-T limits were generated by using the 

staff-approved methodology described in Licensing Topical Report NEDC-33178P-A, “Licensing 

Topical Report GE Hitachi Nuclear Energy Methodology for Development of Reactor Pressure 

Vessel Pressure Temperature Curves,” dated June 2009. The staff further noted that, by its 

letter dated November 25, 2014, the NRC approved a revision to the 32-EFPY Unit 1 P-T limits 

through the license amendment process. That revision was based on credible Unit 1 reactor 

vessel surveillance data from the 120-degree capsule (weld material 1P3571) and the 

associated change to the ART for the beltline material. As discussed above, the staff confirmed 

that the updates of the LSCS P-T limits were controlled in accordance with the 10 CFR 50.90 

license amendment process, consistent with SRP-LR Section 4.2.3.1.3.3.

The applicant also indicated that PTLRs may be submitted for NRC approval for the next P-T 

limit update and that the PTLR process will be used to update P-T limits if a PTLR has been 

approved by the staff. The applicant further indicated that the 10 CFR 50.90 process or the 

PTLR process, whichever constitutes the CLB as approved by the NRC, will ensure that the P-T 

limits for the period of extended operation will be updated before expiration of the 32-EFPY P-T 

limits. The staff noted that these processes that the applicant identified for updates to the P-T 

limits are consistent with those specified in SRP-LR Section 4.2.3.1.3.3.

In its review, the staff noted the following concern related to the P-T limits and neutron fluence 

projections. LRA Section 4.2.1 describes the applicant’s TLAA on reactor vessel fluence 

calculations for the period of extended operation. However, it was not clear to the staff how the 

applicant will ensure that the actual fluence levels are bounded by the projected fluence levels

without impact on the validity of neutron embrittlement analyses (such as P-T limits analysis) 

throughout the period of extended operation.
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By letter dated August 18, 2015, the staff issued RAI 4.2.1-1, regarding reactor vessel neutron 

fluence projections. In Part 2 of the RAI, the staff addressed the concern described above and 

requested that the applicant clarify how it will ensure that the actual fluence levels are bounded 

by the neutron fluence levels analyzed in LRA Section 4.2.1. Part 1 of the RAI is discussed in 

SER Section 4.2.1.2.

In its letter dated September 15, 2015, the applicant stated that, to ensure that the LSCS,

Units 1 and 2, actual fluence levels are bounded through the period of extended operation, the 

fluence values projected in LRA Section 4.2.1 are based on conservative estimates of future 

unit operating capacity factor and previously withdrawn and tested flux wires and capsule 

dosimetry. The applicant also stated that the EFPY and cumulative fluence are tracked to 

ensure that analyzed conditions are not exceeded. The applicant further indicated that, before

each scheduled reactor refueling outage, actual and estimated EFPY are determined and 

reconciled against the CLB.

In addition, the applicant stated that, before exceeding the EFPY value qualified in the current 

P-T limits, fluence projections will be updated and revised P-T limits will be calculated and 

incorporated into the CLB. The applicant stated that LSCS, Unit 1, is a BWRVIP ISP host plant. 

The applicant also stated that, as a BWRVIP ISP host plant, one remaining surveillance capsule 

will be withdrawn per the BWRVIP ISP withdrawal schedule, which will provide future dosimetry 

data for use as an additional benchmark for the LSCS, Unit 1, fluence projections.

In its review, the staff finds the applicant’s response acceptable because the applicant clarified 

that (1) cumulative fluence values are tracked to ensure that the actual operating conditions do 

not exceed the analyzed fluence levels, (2) actual and estimated EFPY are determined and 

evaluated at the end of each fuel cycle to ensure that the operating conditions are consistent 

with the CLB, and (3) future dosimetry data from the Reactor Vessel Surveillance program will 

be used for additional benchmarking of the LSCS, Unit 1, fluence projections. The staff’s 

concern described in RAI 4.2.1-1, Part 2, is resolved.

As discussed above, the staff noted that the P-T limits of LSCS, Units 1 and 2, are currently 

located in the LCO of the TS. The staff also noted that the applicant may submit a license 

amendment request in accordance with Generic Letter (GL) 96-03, “Relocation of the Pressure 

Temperature Limit Curves and Low Temperature Overpressure Protection System Limits,”

dated January 1, 1996, for implementing the PTLR process to relocate the P-T limits into a 

PTLR. If the applicant’s PTLR is approved in the 10 CFR 50.90 license amendment process, 

the applicant may use the PTLR process to update P-T limits in accordance with the 

administrative controls section of the TS during the period of extended operation.

Based on its review, the staff finds that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of loss of fracture toughness due to neutron irradiation 

embrittlement on the intended functions of the reactor vessels will be adequately managed in 

accordance with the 10 CFR 50.90 license amendment process before entering into the period 

of extended operation. The applicant may use the PTLR process to update P-T limits if the 

relocation of P-T limits into PTLRs is approved. Additionally, it meets the acceptance criteria in 

SRP-LR Section 4.2.2.1.3.3 because these processes that the applicant identified for the 

updates to P-T limits provide an adequate basis for accepting this TLAA in accordance with 

10 CFR 54.21(c)(1)(iii).
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4.2.4.3 UFSAR Supplement

LRA Section A.4.2.4 provides the UFSAR supplement summarizing the TLAA on the P-T limits 

of reactor vessels. The staff reviewed LRA Section A.4.2.4, consistent with the review 

procedures in SRP-LR Section 4.2.3.2, which state that the reviewer verifies that the applicant 

has provided information to be included in the UFSAR supplement that includes a summary 

description of the evaluation of the reactor vessel neutron embrittlement TLAA. Based on its 

review of the UFSAR supplement, the staff finds it meets the acceptance criteria in SRP-LR 

Section 4.2.3.2 and, therefore, is acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the TLAA for the 

P-T limits of reactor vessels, as required by 10 CFR 54.21(d).

4.2.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of loss of fracture toughness 

due to neutron irradiation embrittlement on the P-T limits will be adequately managed for the 

period of extended operation through the 10 CFR 50.90 license amendment process. The staff 

also concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d).

4.2.5 Axial Weld Failure Probability Assessment Analyses

4.2.5.1 Summary of Technical Information in the Application

LRA Section 4.2.5 describes the evaluation of the reactor vessel axial weld failure probability 

analysis based on 54-EFPY mean RTNDT for the period of extended operation. The technical 

information in the LRA is summarized as follows in this section.

The BWRVIP recommendations for inspection of reactor vessel shell welds in the BWRVIP-05 

report include examination of 100 percent of the axial welds and inspection of the 

circumferential welds only at the intersections of these welds with the axial welds. The 

BWRVIP-05 report contains generic analyses supporting a generic conclusion in the NRC SE, 

dated July 28, 1998, of the BWRVIP-05 report that the 40-year axial weld failure probability is 

orders of magnitude greater than the circumferential weld failure probability. This weld failure 

probability analysis was used to justify relief from inspection of the circumferential welds, as 

permitted in GL 98-05, “Boiling Water Reactor Licensees Use of the BWRVIP-05 Report to 

Request Relief from Augmented Examination Requirements on Reactor Pressure Vessel 

Circumferential Shell Welds,” dated November 10, 1998, and as described in LRA 

Section 4.2.6.

In addition, the NRC SE, dated July 28, 1998, of the BWRVIP-05 report provides conditional 

failure probability values for the axial welds of the Combustion Engineering Owners Group 

(CEOG) reactor vessel and CB&I reactor vessel at 64 EFPY. Although a conditional failure 

probability has not been calculated for the LSCS units at 54 EFPY, the Unit 1 mean RTNDT of 

139.9 °F is less than the NRC-assessed value of 172.4 °F at 64 EFPY for the CEOG reactor 

vessel, and the Unit 2 mean RTNDT of 12 °F is less than the NRC-assessed value of 117.1 °F at 

64 EFPY for the CB&I reactor vessel. Based on this, the LRA concludes that the conditional 

failure probabilities and RTNDT values of Units 1 and 2 axial welds are bounded by the NRC 

analysis, consistent with the requirements defined in GL 98-05.
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The applicant initially dispositioned the TLAA for the reactor vessel axial welds of LSCS, Units 1 

and 2, in accordance with 10 CFR 54.21(c)(1)(ii) to demonstrate that the analysis has been 

projected to the end of the period of extended operation.

4.2.5.2 Staff Evaluation

The staff reviewed the TLAA associated with the reactor vessel axial welds and the 

corresponding disposition of 10 CFR 54.21(c)(1)(ii), consistent with the review procedures in 

SRP-LR Section 4.2.3.1.5, which state the following:

To demonstrate that the vessel has not been embrittled beyond the basis for the 

staff and BWRVIP analyses, the applicant should provide (a) a comparison of the 

neutron fluence, initial RTNDT, chemistry factor, amounts of copper and nickel, 

∆RTNDT, and mean RTNDT of the limiting axial weld at the end of the license 

renewal period to the reference case in the BWRVIP and staff analyses and 

(b) an estimate of conditional failure probability of the RPV at the end of the 

license renewal term based on the comparison of the mean RTNDT for the limiting 

axial welds and the reference case. If this comparison does not indicate that the 

RPV failure frequency for axial welds is less than 5x10-6 per reactor-year, the 

applicant should provide a probabilistic analysis to determine the RPV failure 

frequency for axial welds.

The review procedures in the SRP-LR also indicate that, consistent with the staff’s supplemental 

SE, dated March 7, 2000, of the BWRVIP-05 report (March 7, 2000, evaluation), the staff 

ensures that the applicant’s plant is bounded by the BWRVIP-05 analysis or that the applicant 

has committed to a program to monitor axial weld embrittlement relative to the values specified 

by the staff in its supplemental SE of the BWRVIP-05 report.

The SRP-LR review procedures further state that the staff confirms that the applicant has 

addressed the following renewal AAI Item in the staff’s SE of the BWRVIP-74:

• Action Item 12: As indicated in the staff's March 7, 2000, letter to Carl Terry, a LR 

[license renewal] applicant shall monitor axial beltline weld embrittlement. One 

acceptable method is to determine the mean RTNDT of the limiting axial beltline weld at 

the end of the extended period of operation is less than the values specified in Table 1 

of this FSER [October 18, 2001, letter to C. Terry].

In its review, the staff noted that LRA Section 4.2.5 does not provide a comparison of axial weld 

failure probability parameters between the applicant’s analysis and the staff’s March 7, 2000, 

supplemental SE regarding the BWRVIP-05 report. Specifically, Table 3 of the supplemental 

SE addresses the reactor vessel failure frequencies due to axial weld failure determined in the 

staff’s assessment. However, the LRA does not discuss these staff-assessed failure 

frequencies in comparison with the applicant’s analysis results. In addition, the staff noted that 

the applicant did not provide a probabilistic analysis establishing that the reactor vessel failure 

frequency for axial welds is less than 5x10-6 per reactor-year in accordance with the staff’s 

March 7, 2000, supplemental SE.

By letter dated July 27, 2015, the staff issued RAI 4.2.5-1, requesting that the applicant justify 

why LRA Section 4.2.5 does not need to be revised to provide comparison of axial weld failure 

probability parameters between the applicant’s analysis and the staff’s supplemental SE, dated 

March 7, 2000. If the applicant’s failure probability comparison does not indicate that the 
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reactor vessel failure frequency due to axial weld failure is less than 5x10-6 per reactor-year, the 

staff requested that the applicant provide one of the following:

• a plant-specific probabilistic analysis for axial weld failure, consistent with 

SRP-LR Section 4.2.3.1.5

• information demonstrating that loss of fracture toughness due to neutron irradiation 

embrittlement of axial welds does not affect the structural integrity of the reactor vessel 

for the period of extended operation

In its response dated August 26, 2015, the applicant stated that, subsequent to the staff’s

original SE, dated July 28, 1998, of the BWRVIP-05 report, additional failure probability 

assessments were prepared by the BWRVIP to more accurately determine the conditional 

failure probability of BWR axial welds. The applicant also indicated that the staff reviewed these

BWRVIP-05 assessments and provided separate conditional failure probability assessments in 

the supplemental SE, dated March 7, 2000, for the BWRVIP-05 report. The applicant further 

indicated that the staff’s assessments resulted in higher failure probabilities than the BWRVIP 

assessments and, therefore, are limiting.

In addition, the applicant stated that the staff determined that the reactor vessel failure 

frequency due to failure of the axial welds in the BWR fleet is no greater than 5.02x10-6 per 

reactor-year. The applicant stated that, because these assessments are applicable to LSCS, 

Units 1 and 2, they are identified as TLAAs requiring evaluation through the period of extended 

operation.

As described below, the applicant revised LRA Sections 4.2.5, 4.8 (references for TLAAs), 

A.4.2.5 (UFSAR supplement for axial weld failure probability analysis), A.2.1.20 (UFSAR 

supplement for the Reactor Vessel Surveillance program), and A.1.1 item 20 (identification of 

enhancements for the Reactor Vessel Surveillance program), as a part of its response to 

RAI 4.2.5-1.

In its response regarding the LSCS, Unit 2, axial weld failure probability analysis, the applicant 

revised LRA Section 4.2.5, including Table 4.2.5-2, to provide a comparison of the RTNDT values 

associated with the failure probability analysis. The comparison indicates that the limiting Unit 2 

axial weld mean RTNDT at 54 EFPY (12.2 °F without margin) is less than the mean RTNDT (91 °F 

without margin) that was determined for the limiting CB&I reactor vessel in the staff’s 

March 7, 2000, supplemental SE. The applicant indicated that, because the mean RTNDT from 

the staff assessment (91 °F) bounds the mean RTNDT of the limiting Unit 2 axial weld (12.2 °F), 

the staff-assessed failure probability of 2.73x10-6 is bounding for Unit 2 axial welds at 54 EFPY, 

confirming that the failure probability is less than 5x10-6 reactor-year. The applicant further 

indicated that the limiting Unit 2 axial welds are Welds BD, BE, and BF in this analysis.

In addition, the applicant dispositioned the TLAA for LSCS, Unit 2, reactor vessel axial welds in 

accordance with 10 CFR 54.21(c)(1)(ii) to demonstrate that the analysis has been projected to 

the end of the period of extended operation. The applicant also revised UFSAR supplement 

Section A.4.2.5 accordingly to summarize the updated analysis for Unit 2.

In its review, the staff finds the applicant’s response acceptable because (a) the applicant 

adequately compared the mean RTNDT of the limiting LSCS, Unit 2, axial weld to the mean 

RTNDT that was determined in the staff’s March 7, 2000, supplemental SE, (b) the applicant also 

confirmed that, because the Unit 2 RTNDT is bounded by the staff-assessed RTNDT, the Unit 2 

reactor vessel failure frequency due to axial weld failure is less than 5x10-6 per reactor-year as 
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specified in the March 7, 2000, supplemental SE, and (c) the applicant adequately revised the 

LRA, consistent with its response. The staff also finds that the applicant’s response adequately 

addresses, for Unit 2, AAI 12 in the staff’s SE of the BWRVIP-74 report, consistent with SRP-LR 

Section 4.2.3.1.5.

In its response regarding the Unit 1 axial weld failure probability analysis, the applicant revised 

LRA Section 4.2.5, including Table 4.2.5-1, to provide a comparison of the RTNDT values 

associated with the failure probability analysis. The comparison indicates that the limiting Unit 1 

axial weld mean RTNDT at 54 EFPY (139.9 °F without margin) is greater than the mean RTNDT

(114 °F without margin) that was determined for the limiting CE reactor, “Mod 2” variant, in the 

staff’s March 7, 2000, supplemental SE of the BWRVIP-05 report.

The applicant indicated that, because the mean RTNDT from the staff assessment (114 °F) does 

not bound the mean RTNDT of the limiting LSCS, Unit 1, axial weld (139.9 °F for Welds 3-308A, 

B, and C), the staff-assessed failure probability of 5.02x10-6 is not bounding for the Unit 1 axial 

welds at 54 EFPY. The applicant further stated that the limiting Unit 1 axial welds are projected 

to reach the 114 °F mean RTNDT value (without margin) at approximately 39.15 EFPY. For 

reference information, the applicant indicated that the Unit 1 cumulative neutron exposure 

through July 2015 is equivalent to 24.05 EFPY. LRA Section 1.1.3 also indicates that the 

LSCS, Unit 1, license expires at midnight on April 17, 2022.

In addition, the applicant dispositioned the TLAA for the LSCS, Unit 1, reactor vessel axial welds 

in accordance with 10 CFR 54.21(c)(1)(iii) to manage the effects of aging for the reactor vessel 

axial welds. The applicant indicated that the effects of aging on the Unit 1 reactor vessel axial 

welds will be managed by the ASME Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD program and the Reactor Vessel Surveillance program. The applicant stated that the 

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program includes 

periodic volumetric examinations and that the Reactor Vessel Surveillance program manages 

neutron embrittlement by monitoring neutron fluence and by ensuring that neutron embrittlement 

analyses are updated as necessary to evaluate bounding neutron fluence values.

The applicant further identified two enhancements of the Reactor Vessel Surveillance program 

for aging management of the LSCS, Unit 1, axial welds as follows:

• Enhancement 1: Prior to the period of extended operation, the applicant will establish a 

monitoring limit for neutron fluence at the limiting Unit 1 axial weld (currently 

39.15 EFPY) that corresponds to the axial weld failure probability of 5.02x10-6 per 

reactor-year specified in the supplement to the final SE of the BWRVIP-05 report.

• Enhancement 2: Prior to 39.15 EFPY, the applicant will complete a probabilistic axial 

weld failure analysis for Unit 1 that demonstrates that the 60-year axial weld failure 

probability is no greater than 5.02x10-6 per reactor-year.

In its review, the staff identified the following issues related to the LSCS, Unit 1, axial weld 

failure probability analysis:

• The applicant’s response did not provide a neutron fluence level (E > 1 MeV) that 

corresponds to 39.15 EFPY, up to which the applicant identified that Unit 1 is bounded 

by 5.02x10-6 per reactor-year.
4-34

• It was not clear whether operating restrictions will be established to ensure that the 

Unit 1 reactor is operated only within the neutron fluence range for which the applicant’s 

analysis remains valid.

• It was not clear whether the applicant will submit the updated analysis for the staff’s 

review and approval sufficiently in advance of the reactor vessel fluence level exceeding 

the fluence range for which the applicant’s analysis remains valid.

By letter dated October 23, 2015, the staff issued RAI 4.2.5-1a, Parts 1 through 3, requesting 

that the applicant address these issues. In RAI 4.2.5-1a, Part 1, the staff asked the applicant to 

provide the neutron fluence value (E > 1 MeV) that corresponds to 39.15 EFPY. In 

RAI 4.2.5-1a, Part 2, the staff asked the applicant to clarify whether the applicant’s program 

includes an enhancement to establish operating restrictions that will ensure the LSCS, Unit 1, 

reactor is operated within the neutron fluence range for which the analysis remains valid. In 

RAI 4.2.5-1a, Part 3, the staff asked the applicant to clarify whether it will submit an updated 

reactor vessel axial weld failure probability analysis for Unit 1 to the staff for review and 

approval sufficiently in advance of the time when the reactor vessel fluence level is projected to 

exceed the fluence range assumed in the original reactor vessel axial weld failure probability 

analysis for Unit 1 (e.g., submittal at least 3 years before the analysis is projected to become 

invalid).

The applicant responded to RAI 4.2.5-1a, Parts 1 through 3, in its letter dated October 29, 2015. 

In the response to RAI 4.2.5-1a, Part 1, the applicant indicated that 6.25x1017 n/cm2

(E > 1 MeV) is the neutron fluence level that corresponds to 39.15 EFPY of power operations 

for LSCS, Unit 1, and to an axial weld failure probability of 5.02x10-6 per reactor-year for this 

unit. The applicant also revised LRA Section 4.2.5 (reactor vessel axial weld failure probability 

TLAA), Section B.2.1.20 (Reactor Vessel Surveillance program), and Sections A.2.1.20 and 

A.4.2.5 (UFSAR supplement descriptions for the TLAA and AMP) to specify this as the fluence 

limit for the axial weld failure probability analysis. The staff finds the applicant’s response 

acceptable because the applicant provided the specific Unit 1 fluence limit that corresponds to 

an axial weld failure probability of 5.02x10-6 per reactor-year.

In its responses to RAI 4.2.5-1a, Parts 2 and 3, the applicant revised the enhancements of the 

Reactor Vessel Surveillance program to ensure the implementation of the following program 

enhancements:

• Enhancement 1: Establish a maximum fluence limit of 6.25x1017 n/cm2 (39.15 EFPY) for 

monitoring the limiting Unit 1 axial welds to ensure that the axial weld failure probability 

will not exceed 5.02x10-6 per reactor-year. This enhancement will be implemented prior 

to the period of extended operation.

• Enhancement 2: Complete a probabilistic axial weld failure analysis for Unit 1 that 

demonstrates the 60-year axial weld failure probability is no greater than 5.02x10-6 per 

reactor-year. Submit the analysis to the NRC for review and approval. This

enhancement will be implemented at least 3 years prior to the limiting axial welds 

reaching the fluence limit specified above.

The staff noted that the applicant also incorporated these revised enhancements into LRA 

Sections A.2.1.20 and A.4.2.5, which provide the UFSAR supplement descriptions for the 

Reactor Vessel Surveillance program and the reactor vessel axial weld failure probability TLAA, 

and into Commitment No. 20 in UFSAR supplement Table A.5. The applicant stated that the 

implementation of the applicant’s commitment tracking assignments will ensure that these 
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procedurally controlled operating restrictions are established before the period of extended 

operation, which is estimated to be approximately 9 years before reaching a failure probability of 

5.02x10-6 per reactor-year. The applicant also revised LRA Section 4.2.5 to state that the

reactor vessel axial weld failure probability TLAA for LSCS, Unit 1, is acceptable in accordance 

with the TLAA acceptance criterion in 10 CFR 54.21(c)(1)(iii). Specifically, the applicant 

amended LRA Section 4.2.5 to state that combined activities in LRA AMP B.2.1.20, “Reactor 

Vessel Surveillance Program”; LRA AMP B.2.1.1, “ASME Section XI, Inservice Inspection, 

Subsections IWB, IWC, and IWD Program”; and the programmatic enhancements of LRA 

Commitment No. 20 are adequate and will be used to manage loss of fracture toughness in the 

reactor vessel axial shell welds of Unit 1 during the period of extended operation.

The staff determined that these AMPs, as subject to the programmatic enhancements in LRA 

Commitment No. 20, provide an acceptable basis for dispositioning this TLAA in accordance 

with 10 CFR 54.21(c)(1)(iii) because (a) the applicant established an appropriate operational 

neutron fluence limit of 6.25x1017 n/cm2 (E > 1 MeV) for axial shell welds in the LSCS, Unit 1,

reactor vessel, (b) the establishment of this limit will ensure that the actual neutron fluence for 

the limiting reactor vessel axial shell welds in the unit will not exceed the specified neutron 

fluence assumed in the failure probability TLAA for the welds, (c) the applicant will complete and 

submit an updated reactor vessel axial weld failure probability analysis for Unit 1 to the staff for 

review and approval at least 3 years before reaching the fluence limit specified above, and 

(d) the applicant has adequately defined and described appropriate programs and enhanced 

programmatic activities in LRA Commitment No. 20 that will be used to manage loss of fracture 

toughness in these reactor vessel axial shell welds during the period of extended operation. 

Therefore, based on this review, the staff finds that the applicant has demonstrated that the 

reactor vessel axial weld failure probability TLAA for Unit 1 is acceptable in accordance with 

10 CFR 54.21(c)(1)(iii) because the applicant has demonstrated that the impacts of loss of 

fracture toughness on the intended reactor coolant pressure boundary functions of the reactor 

vessel axial shell welds will be adequately managed during the period of extended operation. 

The staff’s concerns in RAI 4.2.5-1a, Parts 1 through 3 are resolved.

4.2.5.3 UFSAR Supplement

LRA Section A.4.2.5 provides the UFSAR supplement summarizing the TLAA evaluation of the 

reactor vessel axial weld failure probability analysis. The staff reviewed LRA Section A.4.2.5,

consistent with the review procedures in SRP-LR Section 4.2.3.2, which state that the reviewer

should verify that the applicant has provided information to be included in the UFSAR 

supplement that includes a summary description of the evaluation of the TLAA.

As discussed in Section 4.2.5.2 of this SER, the applicant revised LRA Section A.4.2.5 (UFSAR 

supplement) in its letter dated August 26, 2015, and subsequently in its letter dated 

October 29, 2015. Specifically, the staff noted that, in the letter dated August 26, 2015, the 

applicant revised the UFSAR supplement to indicate that the reactor vessel axial weld failure 

probability analysis for LSCS, Unit 2, was dispositioned in accordance with the acceptance 

criterion in 10 CFR 54.21(c)(1)(ii). The staff found this revision acceptable because the staff 

confirmed that the applicant appropriately projected the Unit 2 axial weld failure probability 

analysis to the end of the period of extended operation and demonstrated that the mean RTNDT

value for the welds is bounded by the limiting mean RTNDT value for reactor vessel axial shell 

welds cited in the NRC SE, dated March 7, 2000, of the BWRVIP-05 report. Thus, the staff 

finds that the revised UFSAR supplement adequately summarizes the TLAA on the Unit 2 axial 

weld failure probability analysis.
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The staff noted some issues regarding the applicant’s TLAA evaluation on the LSCS, Unit 1,

axial weld failure analysis, as described above. The staff further noted that, in the letter dated 

October 29, 2015, the applicant resolved these issues by amending the acceptance basis for

the Unit 1 reactor vessel axial weld failure probability TLAA from 10 CFR 54.21(c)(1)(ii) to 

10 CFR 54.21(c)(1)(iii). As previously discussed in Section 4.2.5.2, the staff found that, based 

on the applicant’s revisions to LRA Section 4.2.5, LRA UFSAR Supplement Section A.4.2.5, and 

Commitment No. 20 in LRA Table A.5, the applicant has provided adequate demonstration that 

the reactor vessel axial weld failure probability TLAA for Unit 1 is acceptable in accordance with 

10 CFR 54.21(c)(1)(iii) and that loss of fracture toughness due to neutron irradiation 

embrittlement in these welds will be adequately managed during the period of extended 

operation.

Therefore, based on the staff’s review of the revised UFSAR supplement in the letters dated 

August 26, 2015, and October 29, 2015, the staff finds that the applicant provided an acceptable 

UFSAR supplement summary description of the reactor vessel axial weld failure probability 

TLAAs that apply to LSCS, Units 1 and 2, as required by 10 CFR 54.21(d).

4.2.5.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an adequate 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the LSCS, Unit 2, reactor vessel axial 

weld failure probability analysis has been projected to the end of the period of extended 

operation and that, pursuant to 10 CFR 54.21(c)(1)(iii), the effects of aging on the intended 

functions of the Unit 1 reactor vessel axial welds will be adequately managed by the 

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program and the 

Reactor Vessel Surveillance program (with enhancements) for the period of extended operation. 

The staff also concludes that the UFSAR supplement contains an appropriate summary

description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.2.6 Circumferential Weld Failure Probability Assessment Analyses

4.2.6.1 Summary of Technical Information in the Application

LRA Section 4.2.6 describes the applicant’s TLAA for reactor vessel circumferential weld failure 

probability assessments. The technical information in LRA Section 4.2.6 is summarized as 

follows.

LSCS previously applied for relief from the circumferential weld inservice inspection

requirements for the Unit 1 reactor vessel manufactured by CE and for the Unit 2 reactor vessel 

manufactured by CB&I. The relief request was granted, as described in the staff’s SE, dated 

January 28, 2004.

In the circumferential weld failure probability assessments for 60 years of operation, the 

applicant stated that the 54-EFPY neutron fluence values for the reactor vessels were 

calculated using the RAMA neutron methodology, as described in LRA Section 4.2.1. The 

applicant stated that the mean RTNDT values for the circumferential welds at 54 EFPY are 

bounded by the staff’s assessments that are described for CE- and CB&I-designed reactor 

vessels in the July 28, 1998, SE for the BWRVIP-05 report, as consistent with the guidance in 

GL 98-05. The applicant also stated that the comparison of these mean RTNDT values confirms 

that the conditional failure probabilities for LSCS reactor vessel circumferential welds are 
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bounded by the conditional failure probabilities for the limiting CE and CB&I reactor vessels 

assessed in the July 28, 1998, SE.

The applicant dispositioned the TLAA for the reactor vessel circumferential welds in accordance 

with 10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of loss of fracture toughness due to 

neutron irradiation embrittlement on the intended functions will be adequately managed by a 

relief request from inservice inspection requirements in accordance with the 10 CFR 50.55a 

process.

4.2.6.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the reactor vessel circumferential welds and the 

corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures in

SRP-LR Section 4.2.3.1.4. The SRP-LR states that the staff verifies that the applicant has 

identified that, if the inspection relief is desired for the period of extended operation, an 

application will be made pursuant to 10 CFR 50.55a before the plant enters the period of 

extended operation. SRP-LR Section 4.2.3.1.4 also states that, if the applicant indicates that 

relief from circumferential weld examination requirements will be made pursuant to

10 CFR 50.55a, the applicant will manage this TLAA in accordance with 10 CFR 54.21(c)(1)(iii).

In its review, the staff noted that LRA Table 4.2.6-1 provides a comparison between the mean 

RTNDT value (-11 °F) for Unit 1 limiting circumferential weld (Weld 6-308) at 54 EFPY and the 

staff-calculated mean RTNDT value (128.9 °F) in the assessment for the limiting CE reactor 

vessel that is documented in the July 28, 1998, SE for the BWRVIP-05 report. The staff also 

noted that LRA Table 4.2.6-2 provides a comparison between the mean RTNDT value (-11 °F) for

the Unit 2 beltline circumferential weld (Weld AB) at 54 EFPY and the staff-calculated mean 

RTNDT value (70.6 °F) in the assessment of the limiting CB&I reactor vessel that is documented 

in the July 28, 1998, SE. The LRA also indicates that Weld AB is the only circumferential weld 

in the Unit 2 beltline region.

As discussed above, the staff confirmed that the applicant provided adequate comparison 

between the mean RTNDT values of LSCS reactor vessel circumferential welds at 54 EFPY and 

the staff-determined mean RTNDT values for the circumferential welds of limiting CE and CB&I 

reactor vessels at 64 EFPY. In its review, the staff confirmed that the mean RTNDT value for 

each unit at 54 EFPY is less than the applicable staff-determined mean RTNDT value at 64 EFPY 

in the July 28, 1998, SE. The staff finds that the conditional failure probability for reactor vessel 

circumferential welds at each unit is bounded by the staff-determined conditional failure 

probability for the corresponding limiting analysis; therefore, the failure probability assessments 

are acceptable.

The staff also noted that LRA Section 4.2.6 indicates that the applicant will reapply for inservice 

inspection relief from circumferential weld examination requirements pursuant to 10 CFR 50.55a

for NRC review and approval before the period of extended operation. The staff noted that the 

applicant’s basis for resubmitting an applicable inspection relief request for these welds during 

the period of extended operation is consistent with the guidance described in SRP-LR 

Section 4.2.3.1.4 and with the relief request requirements in 10 CFR 50.55a. The staff also 

noted that, consistent with the guidelines in SRP-LR Section 4.2.3.1.4, the applicant’s 

resubmittal of an inspection relief request provides an adequate basis for accepting this TLAA in 

accordance with 10 CFR 54.21(c)(1)(iii). Based on its review, the staff finds the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of loss of fracture toughness 
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due to neutron irradiation embrittlement on the intended functions of reactor vessel 

circumferential welds will be adequately managed for the period of extended operation.

Additionally, it meets the acceptance criteria in SRP-LR Section 4.2.3.1.4 because (a) the 

applicant’s analysis in LRA Section 4.2.6 confirms that the conditional failure probability values 

for LSCS reactor vessel circumferential welds at 54 EFPY are bounded by the staff-accepted 

conditional failure probability values that are described in the July 28, 1998, SE for the 

BWRVIP-05 report and (b) the applicant confirmed that it will request relief from the 

requirements to perform volumetric examinations of the circumferential welds in accordance 

with 10 CFR 50.55a before the plant enters the period of extended operation.

4.2.6.3 UFSAR Supplement

LRA Section A.4.2.6 provides the UFSAR supplement summarizing the TLAA evaluation on the 

reactor vessel circumferential weld failure probability assessment. The staff reviewed LRA 

Section A.4.1.6, consistent with the review procedures in SRP-LR Section 4.2.3.2, which state

that the reviewer should verify that the applicant has provided information to be included in the 

UFSAR supplement that includes a summary description of the neutron embrittlement TLAA.

The staff verified that the UFSAR supplement provides a sufficient summary description of the 

TLAA and is consistent with the basis in the staff’s SE regarding the BWRVIP-05 report. The 

staff also confirmed that the UFSAR supplement appropriately reflects that any inservice 

inspection relief for these welds will be resubmitted to justify elimination of the inservice 

inspection requirements before the period of extended operation. In addition, the staff 

confirmed that the UFSAR supplement adequately identifies resubmittal of the relief request for 

the circumferential welds as adequate basis for disposition of this TLAA in accordance with 

10 CFR 54.21(c)(1)(iii).

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SRP-LR Section 4.2.3.2. Additionally, the staff determines that the applicant provided 

an adequate summary description of its actions to address the TLAA on the reactor vessel 

circumferential weld inspection, as required by 10 CFR 54.21(d).

4.2.6.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an adequate 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of loss of fracture toughness 

on the intended functions of the reactor vessel circumferential welds will be adequately 

managed by the inservice inspection relief request process for the period of extended operation. 

The staff also concludes that the UFSAR supplement contains an appropriate summary 

description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.2.7 Reactor Pressure Vessel Reflood Thermal Shock Analyses

4.2.7.1 Summary of Technical Information in the Application

LRA Section 4.2.7 describes the applicant’s TLAA for RPV reflood thermal shock analysis (RPV 

reflood analysis). The technical information that the applicant provided in the LRA is 

summarized in this section as follows.
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General Design Criterion 31, “Fracture prevention of reactor coolant pressure boundary,” of 

Appendix A to 10 CFR Part 50, requires that the reactor coolant pressure boundary of a light 

water reactor be designed with adequate margins of safety against non-ductile failure. The 

applicant stated that this requirement was demonstrated for GE-designed BWRs by 

development of both P-T limits (LRA Section 4.2.4) and generic fracture mechanics analyses 

that evaluate the effects of the limiting loss-of-coolant accident (LOCA) event.

The applicant stated that postulated sudden rupture due to a main steam line LOCA was 

determined to be bounding for all other LOCA events in these fracture mechanics analyses. 

Several emergency core cooling systems are activated at different times after the LOCA, and 

the reactor vessel is flooded with cooling water. The applicant stated that the resulting RPV 

blowdown and the subsequent injection of cold water produce low temperature and high thermal 

stresses in the reactor vessel.

The applicant stated acceptance criterion used in the fracture mechanics analyses is that the 

crack driving force (stress intensity factor, KI-applied) for postulated flaws in the RPV, present 

during the bounding emergency or faulted condition, is less than the limiting material resistance 

to fracture, KIc, applicable during the event. The applicant stated that the limiting KIc fracture 

toughness, as calculated as a function of crack tip temperature and fluence level, was 

determined to be significantly higher than the applied stress intensity factor at all times during 

the progression of emergency and faulted condition transients evaluated in the analysis.

The applicant dispositioned this TLAA for the RPV reflood thermal shock in accordance with 

10 CFR 54.21(c)(1)(ii) to demonstrate that the analysis has been projected to the end of the 

period of extended operation.

4.2.7.2 Staff Evaluation

The staff reviewed the applicant’s TLAA and the corresponding disposition of 

10 CFR 54.21(c)(1)(ii) to ensure that the analysis has been projected to the end of the period of 

extended operation.

LRA Section 4.2.7 indicates that the generic fracture mechanics analyses for RPV reflood 

thermal shock LOCA events are described in the following references: (1) NEDO-10029, “An 

Analytical Study on Brittle Fracture of GE-BWR Vessel Subject to the Design Basis Accident,” 

dated 1969, and (2) Ranganath, S., “Fracture Mechanics Evaluation of a Boiling Water Reactor 

Vessel Following a Postulated Loss of Coolant Accident,” Fifth International Conference on 

Structural Mechanics in Reactor Technology, Berlin, Germany, August 1979. The applicant also 

indicated that the applicant performed an updated reflood thermal shock analysis for license 

renewal that is bounding for LSCS, Units 1 and 2. The applicant further indicated that the 

updated analysis includes RPV beltline shells and nozzles.

LRA Section 4.2.7 also includes a discussion of the criteria and methodology used in the 

analysis. The LRA indicates that the RPV reflood analysis for the RPV beltline materials uses a 

conservative factor of 1.414 for the evaluation of ASME Code Service Level D loadings

(i.e., faulted condition loadings), consistent with the flaw evaluation rules specified in ASME 

Code Section XI, IWB-3600. The crack driving force (stress intensity factor), KI-applied, is 

compared to the adjusted Mode I plane-strain fracture toughness, KIc/1.414 (as conservatively 

adjusted by a factor of 1.414). This comparison is performed to demonstrate that the postulated 

flaws are stable without non-ductile crack propagation. The applicant also indicated that KIa

(crack arrest fracture toughness) and KIc (crack initiation fracture toughness) values are 
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calculated using the equations in ASME Code Section XI, Non-mandatory Appendix A, and a

through-wall temperature distribution that is applicable to the time-dependency of the analyzed 

transients in the RPV reflood analysis.

In its review, the staff noted that the LRA does not provide the following information regarding 

the parameters and methods used in the analysis: (1) the maximum depth of the postulated 

flaw, (2) any conservative factor used in the analysis involving ASME Code Service Level C 

loading (emergency condition), and (3) the method used to calculate neutron fluence 

attenuation through RPV thickness when fluence attenuation is considered. By letter dated 

July 7, 2015, the staff issued RAI 4.2.7-1, requesting that the applicant provide information on 

the items described above.

In its response dated August 6, 2015, the applicant clarified that the maximum flaw depth used 

in the analysis for LSCS, Units 1 and 2, is 5.2 percent of the RPV wall thickness, consistent with 

the criteria in ASME Code Section XI, Tables IWB-3510-1 and IWB-3512-1. The applicant also 

clarified that, for the ASME Code Service Level C loadings (i.e., for emergency condition

loadings) in the analysis, the applied stress intensity factor, KI-applied, is compared with the 

adjusted fracture toughness value, KIc/1.414, where the crack initiation fracture toughness, KIc, 

has been reduced conservatively by a safety factor of 1.414. The applicant further clarified that 

this approach is consistent with the crack initiation criterion specified in ASME Code Section XI, 

IWB-3612(b). In addition, the applicant clarified that the fluence attenuation for the RPV wall 

thickness is computed in accordance with the guidance described in RG 1.99, Revision 2 

(i.e., Equation 3 of RG 1.99).

In its review, the staff finds that the applicant’s response acceptable because (1) the postulated 

flaw depth in the applicant’s analysis is consistent with the maximum allowable depth for RPV

planar flaws specified in ASME Code Section XI, Table IWB-3510-1 and IWB-3512-1, (2) the 

use of fracture toughness conservatively adjusted by a factor of 1.414 is consistent with ASME 

Code Section XI, IWB-3612(b), and (3) the method used for calculation of neutron fluence 

attenuation in the analysis is consistent with the guidance described in RG 1.99, Revision 2. 

The staff’s concern described in RAI 4.2.7-1 is resolved.

LRA Section 4.2.7 also describes the applicant’s evaluation of the integrity of RPV shell 

materials during a main steam line break LOCA as follows.

In the evaluation of the main steam line break analysis, the applicant indicated that the 

bounding 54-EFPY inside surface (0T) neutron fluence values are used to calculate the limiting 

ART for LSCS, Units 1 and 2 (i.e., 168 °F). The applicant also indicated that, based on the 

limiting ART, the allowable fracture toughness value, KIc/1.414, is 141 ksi√in. for the limiting 

material (weld heat 1P3571) and this limiting fracture toughness value (141 ksi√in.) is greater 

than the maximum KI-applied (105 ksi√in.) during the main steam line break transient. Therefore, 

the applicant concluded that the postulated flaw in either the Unit 1 or Unit 2 RPV would be 

stable without non-ductile crack propagation during the main steam line break transient.

In its review, the staff finds that the LRA, as supplemented by letter dated August 6, 2015 

(applicant’s response to RAI 4.2.7-1), confirms that the applicant adequately projected the main 

steam line break LOCA analysis to the end of the period of extended operation, consistent with 

the guidance in RG 1.99, Revision 2 and the analytical flaw evaluation methodology in ASME 

Code Section XI.
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LRA Section 4.2.7 further describes the applicant’s evaluation of integrity of RPV shell materials 

during a recirculation line break LOCA as follows.

In its evaluation, the applicant indicated that the fracture mechanics analysis of the recirculation 

line break LOCA was updated with the material properties projected for 60 years of operation 

(54 EFPY). The applicant also indicated that the fracture toughness (KIc) values of the RPV

materials are determined using crack-tip temperature at the maximum allowable crack depth 

and that the ART is based on the limiting inside surface (0T) neutron fluence.

The applicant’s analysis also compared the applied stress intensity factor at the crack tip, 

KI-applied, to the conservatively reduced fracture toughness value, KIc/1.414. The applicant 

indicated that, at 480 and 1,200 seconds after the start of the transient, the KI-applied value 

exceeds the KIc/1.414 value by 40 percent, which thus indicates that crack initiation and 

propagation would occur during that time period. However, the applicant further indicated that, 

because neutron fluence actually attenuates as a function of distance from the RPV inside 

surface, additional analysis was performed to take into account the reduced fluence as a 

function of crack depth. The applicant provided the following analysis on crack arrest to confirm 

that, even if a crack is initiated, the crack propagation will be arrested before it reaches

75 percent of the RPV wall thickness (0.75T). The applicant stated that the crack arrest within 

the 75-percent wall thickness is consistent with the crack arrest acceptance criteria described in 

ASME Code Section XI (e.g., ASME Code Section XI, Appendix A, A-5000).

In the crack arrest analysis, the applicant indicated that, at times of 480 seconds and 

1,200 seconds after the start of the transient, the KIc (crack initiation fracture toughness) and KIa

(crack arrest fracture toughness) values are determined as a function of crack depth, as well as 

associated temperature, fluence, and ART. In LRA Figures 4.2.7-1 and 4.2.7-2, the applicant 

also plotted KI-applied (applied stress intensity factor) in comparison with KIc and KIa at transient 

times of 480 and 1,200 seconds, respectively.

The staff noted that these plots indicate that, at times of 480 and 1,200 seconds, shallow cracks 

may be initiated to propagate but that crack arrest will occur (KI-applied < KIa) well before the 

cracks reach a depth of 75-percent vessel wall thickness, consistent with the crack arrest 

acceptance criteria of ASME Code Section XI (i.e., crack arrest within 75-percent wall thickness 

during the emergency and faulted conditions). The staff also noted that the applicant’s analysis 

demonstrates that the RPV shell components at Units 1 and 2, as bounded by the limiting weld 

material (Heat No. 1P3571), will continue to have considerable margins of safety against 

postulated brittle fracture failures for the period of extended operation.

In its review of the recirculation line break analysis, the staff noted that the following item 

needed additional clarification. LRA Table 4.2.7-2 and associated discussion in LRA 

Section 4.2.7 have a reference to the 52-percent wall thickness location for the evaluation of 

applied stress intensity factor (KI-applied). The LRA also compares the KI-applied values at 

52-percent wall thickness to the adjusted fracture toughness values (KIc/1.414) of the limiting 

RPV material. It was not clear to the staff why LRA Table 4.2.7-2 and Section 4.2.7 refer to the 

location at 52 percent of the RPV wall thickness for the fracture toughness comparison rather 

than 5.2 percent of the wall thickness that corresponds to the postulated initial flaw depth.

By letter dated September 14, 2015, the staff issued RAI 4.2.7-1a, Part 1, requesting that the 

applicant clarify why LRA Table 4.2.7-2 and associated discussion in Section 4.2.7 assume a 

flaw depth of 52-percent wall thickness that is different from the postulated initial flaw depth 

(i.e., 5.2 percent of the RPV wall thickness).
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The applicant responded to RAI 4.2.7-1a, Part 1, by letter dated October 8, 2015. In its 

response, the applicant identified the listing of a postulated 52-percent flaw size in LRA 

Section 4.2.7 as a typographical error and that postulated flaw size should have been identified 

as a 5.2 percent of the RPV wall thickness. The applicant amended LRA Section 4.2.7 to 

identify that the postulated flaw size in the RPV reflood analyses was 5.2 percent of RPV wall 

thickness. The staff determined that the applicant’s response to the RAI and amendment of the 

LRA are acceptable because the postulated initial flaw size for the reflood analysis is now 

consistent with that evaluated in the design report for the reflood analysis (i.e., with that reported 

in GE Report NEDO-10029). RAI 4.2.7-1a, Part 1, is resolved.

In addition, LRA Section 4.2.7 describes the applicant’s analysis of the RPV beltline nozzles for 

the design basis LOCA. The applicant indicated the N6 LPCI nozzles are determined as the 

limiting beltline nozzles because the emergency core coolant system injects coolant through 

these nozzles following a LOCA. The applicant also indicated that the finite element analysis 

results documented in the stress analyses of LSCS, Units 1 and 2, are used in the applicant’s 

fracture mechanics analysis. The applicant indicated that the bounding temperature distribution 

in the LPCI nozzles was used to develop a thermal stress distribution, which is, in turn, used to 

calculate the stress intensity factor for the fracture mechanics analysis. The applicant stated 

that the resulting applied stress intensity factor (KI-applied) value is significantly less than the 

allowable fracture toughness value, KIc/1.414, thus demonstrating adequate margin against 

non-ductile fracture for these nozzles.In its review, the staff noted that LRA Section 4.2.7 does 

not provide the KI-applied and KIc/1.414 values determined in the applicant’s analysis. By letter 

dated September 14, 2015, the staff issued RAI 4.2.7-1a, Part 2, requesting that the applicant 

provide the KI-applied and KIc/1.414 values for the LPCI nozzles to confirm the adequacy of the 

analysis.

The applicant responded to RAI 4.2.7-1a, Part 2, by letter dated October 8, 2015. In its 

response, the applicant amended the part of the RPV reflood analysis that applies to the N6 

LPCI nozzle in the RPVs. The applicant indicated that the projected applied stress intensity 

value for the postulated flaw in the N6 LPCI nozzles is approximately 35 ksi√in. at 

3,000 seconds and that applied stress intensity value is less than the conservatively adjusted 

fracture toughness value (KIC/1.414) of 141 ksi√in.

The staff noted that the applicant’s response to RAI 4.2.7-1a, Part 2, and amendment of the 

LRA appropriately demonstrate that the stress intensity value for the limiting nozzle component 

in RPV reflood analysis has been projected to the end of the period of extended operation and 

will remain bounded by the conservatively adjusted fracture toughness value (KIC/1.414) of 

141 ksi√in. Therefore, based on this review, the staff finds that the applicant has demonstrated,

pursuant to 10 CFR 54.21(c)(1)(ii), that the RPV reflood analysis for the RPV components has 

been projected to the end of the period of extended operation. Additionally, it meets the 

acceptance criteria in SRP-LR Section 4.7.1 because (1) the applicant has projected a stress 

intensity value for the limiting RPV component in analysis to the end of the period of extended 

operation and (2) the stress intensity value remains bounded by the fracture toughness value of 

the nozzle components. RAI 4.2.7-1a, Part 2, is resolved.

4.2.7.3 UFSAR Supplement

LRA Section A.4.2.7 provides the UFSAR supplement summarizing the TLAA that applies to the 

RPV reflood analysis. The staff reviewed LRA Section A.4.2.7, consistent with the review 

procedures in SRP-LR Section 4.2.3.2, which state that the reviewer verifies that the applicant 
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has provided information to be included in the UFSAR supplement that includes a summary 

description of the TLAA evaluation.

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.2.3.2 and, therefore, is acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the TLAA for the 

reactor vessel reflood thermal shock, as required by 10 CFR 54.21(d).

4.2.7.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the RPV reflood analysis has been 

projected to the end of the period of extended operation. The staff also concludes that the 

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.2.8 RPV Core Plate Rim Hold-Down Bolt Loss of Preload Analysis

4.2.8.1 Summary of Technical Information in the Application

LRA Section 4.2.8 describes the applicant’s TLAA for the loss of preload analysis of the RPV 

core plate rim hold-down bolts resulting from irradiation effects. The LRA states that a 54-EFPY 

fluence evaluation has identified the hold-down bolts with the highest fluence values after 

60 years of operation for LSCS, Units 1 and 2. The highest average fluence value for a Unit 1 

bolt is 3.60x1019 n/cm2

. The highest average fluence value for a Unit 2 bolt is 3.85x1019 n/cm2. 

The LRA also states that an average fluence value of 8.0x1019 n/cm2

, which was projected for 

40 years of operation, results in a maximum relaxation of 19 percent in preload for the RPV core 

plate rim hold-down bolts. The loss of preload analysis was performed as part of EPRI 

BWRVIP-25, “BWR Core Plate Inspection and Flaw Evaluation Guidelines.”

The applicant dispositioned the TLAA for the loss of preload analysis for the RPV core plate rim 

hold-down bolts in accordance with 10 CFR 54.21(c)(1)(i) to demonstrate that the analysis

remains valid for the period of extended operation.

4.2.8.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the loss of preload analysis of the RPV core plate 

rim hold-down bolts resulting from irradiation effects and the corresponding disposition of 

10 CFR 54.21(c)(1)(i), consistent with the review procedures in SRP-LR Section 4.7.3.1.1. 

These procedures state that the staff is to review the justification provided by the applicant to 

verify that the existing analyses are valid during the period of extended operation. SRP-LR 

Section 4.7.3.1.1 also states that the existing analysis should be shown to be bounding during 

the period of extended operation.

The staff issued the final SEs for the BWRVIP-25 report (EPRI TR-107284, dated 

December 1996) and its associated Appendix B, “BWR Core Plate Demonstration of 

Compliance with the Technical Information Requirements of the License Renewal 

Rule (10 CFR 54.21),” by letters dated December 19, 1999, and December 7, 2000, 

respectively. Section 2.1.3 of the BWRVIP-25 report states that it has been determined that a 

5 percent to 19 percent reduction in preload is expected over a 40-year operating experience

and that the bolts will maintain some preload throughout the life of the plant. Section B.4 of 
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Appendix B to the BWRVIP-25 report states that the loss of preload was recalculated based on 

60 years of plant operation and that the reduction in preload remains 5 percent to 19 percent. 

However, there are no corresponding fluence values provided for the percent reductions of 

preload in either the BWRVIP-25 report or the appendices of the report. By letter dated 

August 18, 2015, the staff issued RAI 4.2.8-1, requesting that the applicant provide the analysis 

used to determine that an average fluence value of 8.0x1019 n/cm2 produces a maximum 

relaxation of 19 percent in preload for the RPV core plate rim hold-down bolts.

In its response dated September 15, 2015, the applicant stated that the analysis, used to 

determine that an average fluence value of 8.0x1019 n/cm2 produces a maximum relaxation of 

19 percent in preload for the RPV core plate rim hold-down bolts, is summarized in a letter 

dated June 29, 2006 (GE-EN-0000-0055-6793), from GE Nuclear Energy to EPRI with the 

subject of “Relaxation of Core Plate Rim Hold-down Bolts.” The RAI response quotes the letter 

as stating:

[T]he original fluence estimates that were used to derive the amount of relaxation 

were not bounding for the plant-specific conditions, including the effects of power 

uprate and the additional exposure associated with the period of extended 

operation. As a result, GE has re-evaluated the maximum relaxation value of 

19%, and determined that this value is applicable to an average fluence level of 

8E19 n/cm2 over the entire length of the bolt, determined at the peak azimuthal 

fluence location.

The RAI response also notes the conclusion of the letter, which states:

Evaluation of core plate bolt relaxation has determined that the maximum 

reported relaxation value of 19% remains valid to an average fluence value of 

8E19 n/cm2 or less. This fluence is an average fluence over the entire length of 

the core plate bolt. Plant-specific evaluations required for license renewal, or 

other structural evaluation, should incorporate this limitation.

The RAI response further states that LSCS, Units 1 and 2, are both BWR Type 5 (BWR/5) units 

and that the analysis described in the BWRVIP-25 report is applicable for all BWR/5 units.

The staff reviewed the applicant’s response and finds it acceptable because the source 

document that established that an average fluence level of 8.0x1019 n/cm2 produces a maximum 

relaxation of 19 percent in preload has been identified. The response also confirms that the 

loss of preload evaluation is bounded by the BWRVIP-25 report and its appendices because the 

configuration of the rim hold-down bolts and average fluence levels of both units are within the 

limitations of the analysis.

The highest average fluence values for the RPV core plate rim hold-down bolts were 

determined using RAMA fluence projections for both LSCS, Units 1 and 2. The 54-EFPY 

fluence evaluation was performed for all 34 core plate rim bolts in each unit. The staff’s 

evaluation of neutron fluence analyses is in SER Section 4.2.1.

Accordingly, the staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), 

that the analysis of the loss of preload for the RPV core plate rim hold-down bolts resulting from 

irradiation effects remains valid for the period of extended operation. Additionally, it meets the 

acceptance criteria in SRP-LR Section 4.7.2.1 because the fluence value of 8.0x1019 n/cm2
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used in the existing analysis is shown to be bounding for both LSCS, Units 1 and 2, during the 

period of extended operation.

4.2.8.3 UFSAR Supplement

LRA Section A.4.2.8 provides the UFSAR supplement summarizing the loss of preload for the 

RPV core plate rim hold-down bolts. The staff reviewed LRA Section A.4.2.8, consistent with 

the review procedures in SRP-LR Section 4.7.3.2, which state that the reviewer is to verify that 

the applicant has provided information to be included in the UFSAR supplement that includes a 

summary description of the evaluation of the TLAA.

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SRP-LR Section 4.7.2.2 and, therefore, is acceptable. Additionally, the staff 

determines that the applicant provided an adequate summary description of its actions to 

address loss of preload for the RPV core plate rim hold-down bolts, as required by 

10 CFR 54.21(d).

4.2.8.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the analysis of the loss of preload for the 

RPV core plate rim hold-down bolts resulting from irradiation effects remains valid for the period 

of extended operation. The staff also concludes that the UFSAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.2.9 Jet Pump Riser Brace Clamp Loss of Preload Analysis

4.2.9.1 Summary of Technical Information in the Application

LRA Section 4.2.9 describes the applicant’s TLAA for the loss of preload of the jet pump riser 

brace clamp resulting from neutron irradiation. The LRA states that the original 40-year design 

evaluation for the clamp used a neutron fluence value of 3.2x1020 n/cm2 to determine that a 

46-percent loss of preload would occur. The applicant performed a neutron fluence evaluation 

for 54 EFPY on the LSCS, Unit 1, jet pump riser brace clamp and projected that after 60 years 

of operation (54 EFPY) the neutron fluence value will be 2.0x1020 n/cm2

.

The applicant dispositioned the TLAA for the loss of preload of the jet pump raiser brace clamp 

in accordance with 10 CFR 54.21(c)(1)(i) to demonstrate that the analysis remains valid for the 

period of extended operation.

4.2.9.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the loss of preload of the jet pump raiser brace 

clamp resulting from irradiation effects and the corresponding disposition of 

10 CFR 54.21(c)(1)(i), consistent with the review procedures in SRP-LR Section 4.7.3.1.1. 

These procedures state that the staff must review the justification provided by the applicant to 

verify that the existing analyses are valid during the period of extended operation. SRP-LR 

Section 4.7.3.1.1 also states that the existing analysis should be shown to be bounding during 

the period of extended operation.
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The staff reviewed UFSAR Sections 3.9.5.1.8 and 4.5.2.1. The review of the UFSAR confirmed 

the installation of the jet pump raiser brace clamps in LSCS, Unit 1, and their material of 

construction. The staff noted that the 54-EFPY fluence value of 2.0x1020 n/cm2 for the jet pump 

raiser brace clamp was determined using the RAMA fluence methodology. The staff also noted 

that the neutron fluence evaluation was performed using the specific geometry of the jet pump 

and riser brace clamps. The staff further noted that the 54-EFPY fluence value of 

2.0x1020 n/cm2 is bounded by the original 40-year design value of 3.2x1020 n/cm2

. The staff’s 

evaluation of neutron fluence analyses is in SER Section 4.2.1.

Based on its review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that the analysis of the loss of preload for the jet pump raiser brace 

clamp resulting from irradiation effects remains valid for the period of extended operation. 

Additionally, it meets the acceptance criteria in SRP-LR Section 4.7.2.1 because the fluence 

value of 3.2x1020 n/cm2 used in the existing design analysis is shown to be bounding for the 

period of extended operation.

4.2.9.3 UFSAR Supplement

LRA Section A.4.2.9 provides the UFSAR supplement summarizing the loss of preload for the 

jet pump raiser brace clamp. The staff reviewed LRA Section A.4.2.9 consistent with the review 

procedures in SRP-LR Section 4.7.3.2, which state that the reviewer is to verify that the 

applicant has provided information to be included in the UFSAR supplement that includes a 

summary description of the evaluation of the TLAA.

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2 and, therefore, is acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address loss of preload for 

the jet pump raiser brace clamp, as required by 10 CFR 54.21(d).

4.2.9.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the analysis of the loss of preload for the 

jet pump raiser brace clamp resulting from irradiation effects remains valid for the period of 

extended operation. The staff also concludes that the UFSAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.2.10 Jet Pump Slip Joint Repair Clamp Loss of Preload Analysis

4.2.10.1 Summary of Technical Information in the Application

LRA Section 4.2.10 describes the applicant’s TLAA for the loss of preload analysis of the jet 

pump slip joint repair clamp resulting from irradiation effects. The LRA states that the function 

of the clamp is to apply a lateral preload to the slip joint to minimize slip joint vibrations and wear 

of the jet pump assemblies. The applicant stated that the clamps were installed with a preload 

of 500 lb and that the design specification requires a minimum preload of 350 lb at the end of 

life. The applicant also stated that this allowable 30-percent relaxation in preload corresponds 

to a fluence value of 1.17x1020 n/cm2 based on Figure 6-4 of EPRI BWRVIP-276, “Evaluation to 

Justify Core Plate Bolt Inspection Elimination,” which provides the relationship between neutron 

fluence and stress relaxation for stainless steel. The applicant further stated that the projected 

fluence value for the clamp at the end of the period of extended operation is 1.27x1020 n/cm2

.
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The applicant dispositioned the TLAA for the jet pump slip joint repair clamp in accordance with 

10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of loss of preload on the intended 

function(s) will be adequately managed for the period of extended operation.

4.2.10.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the loss of preload of the jet pump slip joint repair 

clamp resulting from irradiation effects and the corresponding disposition of 

10 CFR 54.21(c)(1)(iii), consistent with the review procedures in SRP-LR Section 4.7.3.1.3. 

These procedures state that the staff must review the AMP proposed by the applicant to verify 

that the program is adequate to manage the aging effects associated with the TLAA. SRP-LR 

Section 4.7.3.1.3 also states that the applicant must identify components associated with the 

TLAA and must describe relevant aspects of the analysis.

The LRA provides the relevant aspects of the TLAA, such as the applicable aging effect, 

intended function(s) of the clamp, and design acceptance criteria. The LRA states that the first 

clamp was installed in the RPV of LSCS, Unit 1, in February 2004 and that the original analysis 

predicted a 12-percent reduction in preload at the end of the 40-year license period based on a 

projected fluence level of 4.4x1019 n/cm2

. The design specification for the clamp allows a 

30-percent reduction in preload, which the applicant determined would be reached at a fluence 

level of 1.17x1020 n/cm2 before 60 years of plant operation. By letter dated August 18, 2015, the 

staff issued RAI 4.2.10-1, requesting that the applicant identify the program or a set of activities 

that will be used for the jet pump slip joint repair clamp to ensure that the limiting fluence value 

(1.17x1020 n/cm2

) is not exceeded.

In its response dated September 15, 2015, the applicant stated that the activities that will be 

used to ensure that the jet pump slip joint repair clamp does not exceed its limiting fluence value 

are (1) action tracking assignments for Commitment No. 47 in the Exelon commitment 

management program and (2) procedure LTS-1200-4, “Reactor Engineer’s Core Monitoring 

Surveillance.” The response also states that the action tracking assignments for Commitment 

No. 47 will include an assignment to ensure that corrective actions are taken to repair, replace, 

or reanalyze the clamps well in advance of reaching the fluence level of 1.17x1020 n/cm2

(50.7 EFPY). The due date to initiate this assignment will be approximately 5 years before the 

estimated calendar date that the fluence limit is reached. Procedure LTS-1200-4 requires the 

EFPY value for LSCS, Unit 1, to be updated each month and reported to the Reactor Internals 

Engineer. The response further states that procedure LTS-1200-4 will be revised before the 

plant enters the period of extended operation to require the Reactor Internals Engineer to 

ensure that corrective action has been taken before exceeding 50.7 EFPY.

The staff reviewed the applicant’s response and finds it acceptable because the applicant has 

provided its set of activities that will be used to ensure that the fluence limit is not exceeded. 

The set of activities described by the applicant will ensure that the intended function(s) of the jet 

pump slip joint repair clamp are maintained during the period of extended operation.

The highest fluence value for the limiting slip joint repair hardware was determined using RAMA 

three-dimensional fluence projections. The staff’s evaluation of the neutron fluence analyses is 

in SER Section 4.2.1.

Based on its review, the staff finds that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of the loss of preload on the intended functions of the jet 

pump slip joint repair clamp will be adequately managed for the period of extended operation.
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4.2.10.3 UFSAR Supplement

LRA Section A.4.2.10 provides the UFSAR supplement summarizing the loss of preload for the 

jet pump slip joint repair clamp. The staff reviewed LRA Section A.4.2.10, consistent with the 

review procedures in SRP-LR Section 4.7.3.2, which state that the reviewer must verify that the 

applicant has provided information to be included in the UFSAR supplement that includes a 

summary description of the evaluation of the TLAA. The staff also noted that the applicant 

committed (Commitment No. 47) to take corrective actions before the fluence limit of 

1.17x1020 n/cm2 is reached. The commitment, as revised by letter dated February 1, 2016, 

states that, if the corrective actions include a reanalysis of the slip joint repair clamp, the revised 

analysis will be submitted to the staff for review a minimum of 2 years prior to exceeding 

50.7 EFPY. The commitment also references Exelon letters RS-15-232, RS-16-003, and 

RS-16-033. These letters discuss the assignments within the commitment tracking program to 

revise procedure LTS-1200-4 and initiate corrective actions in well in advance of exceeding the 

fluence limit. As discussed in Section 4.2.10.2 above, the staff confirmed the adequacy of the 

applicant’s activities associated with the commitment to ensure that the limiting fluence value 

(1.17x1020 n/cm2

) for the jet pump slip joint repair clamp is not exceeded. The commitment 

must be implemented before the plant enters the period of extended operation.

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2 and, therefore, is acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address loss of preload for 

the jet pump slip joint repair clamp, as required by 10 CFR 54.21(d).

4.2.10.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of the loss of preload on the 

intended function(s) of the jet pump slip joint repair clamp will be adequately managed by 

license renewal Commitment No. 47 and associated activities for the period of extended 

operation. The staff also concludes that the UFSAR supplement contains an appropriate 

summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.3 Metal Fatigue Analyses

LRA Section 4.3 provides the applicant’s analyses of the following areas related to metal 

fatigue:

• LRA Section 4.3.1, ASME Section III, Class 1 Fatigue Analyses

• LRA Section 4.3.2, ASME Section III, Class 2 and 3 and ANSI B31.1 Allowable Stress 

Analyses

• LRA Section 4.3.3, Environmental Fatigue Analyses for RPV and Class 1 Piping

• LRA Section 4.3.4, Reactor Vessel Internals Fatigue Analyses

• LRA Section 4.3.5, High-Energy Line Break (HELB) Analyses Based on Fatigue

• LRA Section 4.3.6, Main Steam Relief Valve Discharge Piping Fatigue Analyses
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4.3.1 ASME Section III, Class 1 Fatigue Analyses

4.3.1.1 Summary of Technical Information

LRA Section 4.3.1 states that the RPV and RCPB piping and components were designed in 

accordance with the ASME Code Section III, Class 1 design requirements. The applicant 

prepared the fatigue analyses and fatigue exemptions to determine the effects of cyclic loading 

resulting from changes in system temperature and pressure and for seismic loading cycles, and 

to demonstrate that the CUF values for the components will not exceed the design limit of 1.0. 

The LRA states that the analyses have been identified as TLAAs because these fatigue 

analyses and fatigue exemptions are based on the number of transient occurrences estimated 

to bound 40 years of plant operation.

LRA Table 4.3.1-1 provides the transients analyzed for the LSCS, Unit 1, RPV and Class 1 

RCPB piping systems, and LRA Table 4.3.1-2 provides the transients analyzed for the Unit 2 

RPV and Class 1 RCPB piping systems. These LRA tables, in addition to the baselined 

cumulative cycle occurrences, projected 60-year occurrences, and CLB fatigue design cycle 

limits, include additional cycles applied to add margin for transients with low rates of past 

occurrence. LRA Table 4.3.1-3 provides the components with fatigue exemptions. The LRA 

states that the Fatigue Monitoring program will be used to monitor the transients and to ensure 

that corrective actions are taken before any design cycle limit is exceeded.

The applicant dispositioned the ASME Section III, Class 1 fatigue analyses in accordance with 

10 CFR 54.21(c)(1)(iii) such that the effects of metal fatigue on the intended functions will be 

adequately managed by the Fatigue Monitoring program for the period of extended operation.

4.3.1.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1 and the TLAAs for the ASME Section III, Class 1 fatigue 

analyses to verify, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of fatigue will be 

adequately managed by the Fatigue Monitoring program for the period of extended operation.

The staff reviewed the applicant’s TLAAs for the ASME Section III, Class 1 fatigue analyses, 

and the corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review 

procedures in SRP-LR Section 4.3.3.1.1.3. These procedures state that the reviewer should 

verify the appropriateness of the applicant’s program for monitoring and tracking the 

occurrences of critical thermal and pressure transients for the selected Reactor Coolant System 

(RCS) components.

LRA Section 4.3.1 states that the fatigue analyses and fatigue exemptions for ASME Section III, 

Class 1 RPV and RCPB piping and components are based on the transients listed in LRA 

Tables 4.3.1-1 and 4.3.1-2. The LRA states that the Fatigue Monitoring program is credited to 

monitor the transient cycles and to require corrective action before exceeding the design limits. 

The staff determined that the enhanced Fatigue Monitoring program ensures that the number of 

occurrences of transients will not be exceeded during the period of extended operation or that 

corrective actions are taken. The staff noted that the additional cycles added for margin to the 

transients is a conservative approach and will provide additional assurance that the design cycle 

limits will not be exceeded during the period of extended operation. The staff’s evaluation of the 

Fatigue Monitoring program is documented in SER Section 3.0.3.2.22.
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Based on its review, the staff finds that the applicant has demonstrated, in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of aging related to metal fatigue of the ASME Section III, 

Class 1 RPV and RCPB piping and components will be adequately managed through the period 

of extended operation. Additionally, it meets the acceptance criteria in SRP-LR 

Section 4.3.2.1.1.3 because the applicant’s Fatigue Monitoring program monitors and tracks the 

transient cycles assumed in the analysis and requires corrective action before exceeding the 

number of transient cycles used in the analysis.

4.3.1.3 UFSAR Supplement

LRA Section A.4.3.1 provides the UFSAR supplement, which summarizes the TLAA for ASME 

Section III, Class 1 fatigue analyses. The staff reviewed LRA Section A.4.3.1 consistent with 

the review procedures in SRP-LR Section 4.3.3.2, which state that the information to be 

included in the UFSAR supplement should include a summary description of the evaluation of 

the TLAA.

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SRP-LR Section 4.3.2.2. Additionally, the staff determines that the applicant provided 

an adequate summary description of its actions to address the TLAA for ASME Section III, 

Class 1 fatigue analyses, as required by 10 CFR 54.21(d).

4.3.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging related to fatigue on 

the intended functions of the ASME Section III, Class 1 RPV and RCPB piping and components

will be adequately managed by the Fatigue Monitoring program for the period of extended 

operation. The staff also concludes that the UFSAR supplement contains an appropriate 

summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.3.2 ASME Section III, Class 2 and 3 and ANSI B31.1 Allowable Stress Analyses

4.3.2.1 Summary of Technical Information

LRA Section 4.3.2 describes the applicant’s allowable secondary stress range reduction factor 

TLAAs for ASME Section III, Class 2 and 3 and American National Standards Institute 

(ANSI) B31.1 piping. A stress range reduction factor to the allowable stress range is required if 

the number of equivalent full temperature cycles exceeds 7,000. The applicant stated that 

these are considered to be implicit fatigue analyses because they are based on cycles 

anticipated for the life of the component and are, therefore, TLAAs requiring evaluation for the 

period of extended operation.

The LRA states that portions of certain systems within the scope of license renewal were 

designed in accordance with ASME Code Section III, Class 2 or 3 or ANSI B31.1 requirements 

but are attached to ASME Section III, Class 1 piping and are affected by the same thermal and 

pressure transients as the Class 1 systems. The list of these systems includes: Residual Heat 

Removal, High Pressure Core Spray, Low Pressure Core Spray, Reactor Core Isolation Cooling 

(RCIC), Reactor Water Cleanup, Control Rod Drive, Main Steam, Feedwater, and Condenser 

and Air Removal. The LRA states that the 60-year projections for the transients that affect 

these systems demonstrate that the total number of cycles will not exceed the total number of 

design cycles, which was initially used to determine the applicable stress reduction factor. The 
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LRA states that this ensures that the original stress range reduction factors used for these 

systems remain applicable and that the TLAAs will remain valid for the period of extended 

operation.

The LRA also states that the remaining systems that were designed in accordance with ASME 

Code Section III, Class 2 or 3 or ANSI B31.1 requirements are affected by different thermal and 

pressure cycles. The list of these systems include portions of the RCIC, Fire Protection, and 

Diesel Generator and Auxiliaries systems. The LRA states that an operation review was 

performed for each of these systems to determine the actual cycle occurrences and to project 

the number of cycles that will occur through the period of extended operation. The LRA states 

that each of these operational reviews concluded that the total number of projected 60-year 

cycles will not exceed 7,000 cycles. The LRA states that this ensures that the original stress 

range reduction factors used for these systems remain applicable and that the TLAAs will 

remain valid for the period of extended operation.

The applicant dispositioned these TLAAs in accordance with 10 CFR 54.21(c)(1)(i) such that the 

ASME Section III, Class 2 and 3 and ANSI B31.1 allowable stress calculations will remain valid 

for the period of extended operation.

4.3.2.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2 and the TLAA for portions of the systems within the scope 

of license renewal that were designed in accordance with ASME Code Section III, Class 2 or 3 

or ANSI B31.1 requirements. These components and piping are attached to ASME Section III, 

Class 1 piping and are affected by the same thermal and pressure transients as those for the 

Class 1 systems. The staff reviewed the TLAA to verify, in accordance with 

10 CFR 54.21(c)(1)(i), that the ASME Section III, Class 2 and 3 and ANSI B31.1 allowable 

stress calculations will remain valid for the period of extended operation.

The staff reviewed the applicant’s TLAA and the corresponding disposition of 

10 CFR 54.21(c)(1)(i), consistent with the review procedures in SRP-LR Section 4.3.3.1.2.1. 

These procedures state that the relevant information in the TLAA, operating plant transient 

history, design basis, and the CLB are reviewed to confirm that the maximum allowable stress 

range values for the existing fatigue analysis remain valid for the period of extended operation 

and that the allowable limit for full thermal range transients will not be exceeded during the 

period of extended operation.

The staff noted that the LRA did not specify which thermal and pressure cycles affect these 

systems or the projected 60-year cycle occurrences. However, because the LRA stated that 

these systems are affected by the same cycles that affect Class 1 piping, the staff reviewed 

LRA Tables 4.3.1-1 and 4.3.1-2. For both units, the sum of all the projected 60-year cycle 

occurrences for all the transients that affect Class 1 RPV and RCPB piping and component is 

less than 7,000 cycles. The staff noted that each of the systems do not experience all the 

transients listed in LRA Tables 4.3.1-1 and 4.3.1-2; therefore, this summation was conservative 

and still resulted in a total of less than 7,000 cycles. Therefore, the staff finds it reasonable that 

the full-range thermal cycle limit of 7,000, used in the applicant design basis fatigue evaluations 

associated with the ANSI B31.1 and ASME Section III, Class 2 and 3, piping and components,

will not be exceeded and includes margin to account for unanticipated transient occurrences 

during the period of extended operation.
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Accordingly, the staff finds that the applicant has demonstrated, in accordance with 

10 CFR 54.21(c)(1)(i), that the TLAAs for the ASME Section III, Class 2 and 3 and ANSI B31.1 

piping and components associated with the portions of the Residual Heat Removal, High 

Pressure Core Spray, Low Pressure Core Spray, RCIC, Reactor Water Cleanup, Control Rod 

Drive, Main Steam, Feedwater, and Condenser and Air Removal systems, for which the 

allowable range of secondary stresses depends on the number of assumed thermal cycles, will

remain valid for the period of extended operation. Additionally, the applicant’s analysis meets 

the acceptance criteria in SRP-LR Section 4.3.2.1.2.1 because the applicant has demonstrated

that, for those piping and components subject to the thermal fatigue described above, the cycle 

limit for full thermal range transients established in the design analyses will not be exceeded. 

Therefore, the analysis will remain valid for the period of extended operation.

LRA Section 4.3.2 also includes a TLAA for systems that were designed in accordance with 

ASME Code Section III, Class 2 or 3 or ANSI B31.1 requirements but are affected by different 

thermal and pressure cycles than those affecting Class 1 piping. The LRA states that an 

operational review concluded that the total number of cycles projected for 60 years for these 

systems are significantly less than the full-range thermal cycle limit of 7,000. However, the LRA 

did not contain enough information regarding the applicable thermal cycles and 60-year 

projections associated for these systems.

By letter dated July 7, 2015, the staff issued RAI 4.3.2-1, requesting that the applicant provide 

the ASME Section III, Class 2 or 3 or ANSI B31.1 systems that are affected by different 

transients than those affecting Class 1 piping. For each of these systems, the staff further 

requested that the applicant provide the applicable transients assumed in the allowable stress 

calculations and projected 60-year cycle occurrences and justify that the TLAA remains valid for 

the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

By letter dated August 6, 2015, the applicant responded to RAI 4.3.2-1. The applicant 

confirmed that the RCIC, Fire Protection, and Diesel Generator and Auxiliary systems are the 

systems affected by the different transients and specified which components within the system 

were analyzed. For the RCIC system, the applicant identified the portions as the piping 

components between the RCIC turbine and the suppression pool and between the normally

closed steam admission valve and the RCIC turbine.

For each of these three systems, the applicant provided the thermal and pressure cycles that 

affect the components and provided a justification on how it projected the 60-year cycle 

occurrences through the period of extended operation. For the RCIC system, the applicant 

projected a total of 938 applicable cycles for LSCS, Unit 1, and 932 applicable cycles for Unit 2. 

For the Fire Protection system, the applicant projected a total of 1,530 applicable cycles for 

each of the diesel-driven fire pumps. For the Diesel Generator and Auxiliary system, the 

applicant projected a total of 1,420 applicable cycles for each of the emergency diesel 

generators.

The staff finds the applicant’s response to RAI 4.3.2-1 acceptable because the applicant 

(a) listed the specific transients that affect each of the systems, (b) used an adequate, 

conservative approach to calculating the projected 60-year cycle count for each of the 

transients, and (c) provided the total projected cycle counts that affect each of the systems. 

Thus, the staff’s concerns in RAI 4.3.2-1 are resolved.

Based on its review, the staff finds it reasonable that the full-range thermal cycle limit of 7,000, 

used in the applicant design basis fatigue evaluations associated with the ANSI B31.1 and 
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ASME Section III, Class 2 and 3 piping and components, will not be exceeded and includes 

margin to account for unanticipated transient occurrences during the period of extended 

operation.

Accordingly, the staff finds that the applicant has demonstrated, in accordance with 

10 CFR 54.21(c)(1)(i), that the TLAAs for the ASME Section III, Class 2 and 3 and the 

ANSI B31.1 piping and components associated with the RCIC, Fire Protection, and Diesel 

Generator and Auxiliary systems, for which the allowable range of secondary stresses depends 

on the number of assumed thermal cycles, remain valid for the period of extended operation. 

Additionally, the applicant’s analysis meets the acceptance criteria in SRP-LR 

Section 4.3.2.1.2.1 because the applicant has demonstrated that, for those piping and 

components subject to thermal fatigue described above, the cycle limit for full thermal range 

transients established in the design analyses will not be exceeded; therefore, the analysis will 

remain valid for the period of extended operation.

4.3.2.3 UFSAR Supplement

LRA Section A.4.3.2 provides the UFSAR supplement summarizing the TLAA for ANSI B31.1 or 

ASME Section III, Class 2 and 3 piping and components. The staff reviewed LRA 

Section A.4.3.2, consistent with the review procedures in SRP-LR Section 4.3.3.2, which state 

that the reviewer verifies that the applicant has provided information to be included in the 

UFSAR supplement that includes a summary description of the evaluation of the metal fatigue 

TLAAs.

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SRP-LR Section 4.3.2.2 and, therefore, is acceptable. Additionally, the staff 

determines that the applicant provided an adequate summary description of its actions to 

address the TLAA for ANSI B31.1 or ASME Section III, Class 2 and 3 piping and components, 

as required by 10 CFR 54.21(d).

4.3.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(i), that the TLAA for ASME Section III, 

Class 2 and 3 and ANSI B31.1 allowable stress calculations remains valid for the period of 

extended operation. The staff also concludes that the UFSAR supplement contains an 

appropriate summary description of the TLAA evaluations, as required by 10 CFR 54.21(d).

4.3.3 Environmental Fatigue Analyses for RPV and Class 1 Piping

4.3.3.1 Summary of Technical Information

LRA Section 4.3.3 describes the applicant’s evaluation of the effects of the reactor coolant 

environment on component fatigue life for the period of extended operation. The applicant 

assessed the impact of the reactor coolant environment on a sample of critical components, 

which include those listed in NUREG/CR-6260, “Application of NUREG/CR-5999 Interim 

Fatigue Curves to Selected Nuclear Power Plant Components,” dated February 1995, and any 

additional plant-specific components considered to be more limiting.

The LRA states that environmental fatigue calculations were prepared for each component 

location listed in NUREG/CR-6260 for the newer vintage BWR, which is applicable at LSCS. In 
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order to identify any plant-specific locations that are not bounded by the locations identified in 

NUREG/CR-6260, the LRA states that environmental fatigue calculations were performed for 

each RPV component location that has a reported CUF. An environmental fatigue analysis was 

also prepared for each ASME Section III, Class 1 system or group of subsystems that are 

affected by the same transients that normally contact reactor coolant. The LRA states that 

these environmental fatigue calculations were prepared for the limiting location of each wetted 

material type within the component or system that contacts reactor coolant. The applicant 

stated that the methodology of NUREG/CR-6909, “Effect of LWR Coolant Environments on the 

Fatigue Life of Reactor Materials,” dated March 2014, was used to determine applicable values 

of the environmental fatigue life correction factor (Fen) for each material type. These Fen values 

were then used to evaluate the CUFs that include environmentally adjusted cumulative usage 

factor (CUFen) effects.

LRA Table 4.3.3-1 and 4.3.3-2 provide the environmental fatigue calculation results for the RPV 

components. LRA Tables 4.3.3-3 and 4.3.3-4 provide the environmental fatigue calculation 

results for the Class 1 piping systems. These tables include the locations identified in 

NUREG/CR-6909 for newer vintage BWR plants.

The applicant dispositioned the evaluations associated with EAF on the Class 1 components in 

accordance with 10 CFR 54.21(c)(1)(iii) such that the effects of EAF on the intended functions 

will be adequately managed by the Fatigue Monitoring program for the period of extended 

operation.

4.3.3.2 Staff Evaluation

The staff found that the applicant addressed the effects of the reactor coolant environment on 

component fatigue life consistent with the guidance in the SRP-LR and the staff’s 

recommendations for resolving Generic Safety Issue No. 190 (GSI-190), “Fatigue Evaluation of 

Metal Components for 60-Year Plant Life,” dated December 10, 1999. The staff also identified

that, consistent with Commission Order No. CLI-10-17, dated July 8, 2010, the evaluations 

associated with the effects of the reactor coolant environment on component fatigue life are not 

TLAAs in accordance with the definition in 10 CFR 54.3(a) because these evaluations are not in 

the applicant’s CLB. Nevertheless, the applicant has credited its Fatigue Monitoring program to 

manage the effects of reactor coolant environment on component fatigue life. Therefore, the 

staff reviewed LRA Section 4.3.3 and the evaluations for EAF to confirm, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of reactor coolant environment on component fatigue life 

will be adequately managed for the period of extended operation.

The staff reviewed the applicant’s EAF evaluations consistent with the review procedures in 

SRP-LR Section 4.3.3.1.3, which state that the reviewer should confirm that the applicant has 

addressed the effects of the reactor coolant environment on component fatigue life as AMPs are 

formulated in support of license renewal.

In its review of LRA Section 4.3.3, the staff noted that the sample of critical components should 

include the locations identified in NUREG/CR-6260, as a minimum, as well as additional 

locations based on plant-specific considerations. The LRA states that environmental fatigue 

calculations were prepared for each of these component locations. The LRA states that, for 

carbon and low-alloy steels, austenitic stainless steels, and nickel alloys, the methodology in 

NUREG/CR-6909 was used to determine applicable Fen factors and to obtain a CUFen, which 

included the effects of the reactor water environment.
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The LRA states that for Class 1 piping systems, the applicant evaluated the locations within the 

system(s) or subsystem(s) that are affected by the same transient definitions and selected the 

location with the highest CUFen value as its limiting location. The applicant stated that it 

selected limiting locations for each wetted material type for each system. The applicant then 

compared the fatigue usage values for the limiting piping locations for each system and 

compared them to the fatigue usage values for the Class 1 valves, pumps, and containment 

penetrations within the same system. The LRA states that the selected limiting piping location 

bounded other component locations for each system, with the exception of Feedwater system

Class 1 valves. The applicant applied the Fen factors to determine the projected 60-year CUFen

values. The LRA states that the 60-year CUFen values, as listed in LRA Tables 4.3.3-1 

through 4.3.3-4, do not exceed the design Code limit of 1.0. The applicant stated that the 

limiting piping location that was analyzed for environmental fatigue can represent another 

component or piping location that is bounded by that limiting location. The LRA states that the 

bounded location must be affected by the same transients as the analyzed location; must have 

a lower CUF value than the CUF value of the analyzed location; and must either be made from 

the same material or, if made of a different material, the bounded material must have a lower

Fen value than that of the bounding material.

The staff noted that in order to have a meaningful comparison of CUF values to determine the 

most limiting component (or leading location) by using the highest CUF value, it is important that 

the CUF values were assessed similarly (e.g., amount of rigor in calculating CUF) and used the 

same fatigue curves as those in ASME Code, Section III, Appendix I. The staff noted that 

through the course of plant operation, it is possible that CUF values for specific components 

were re-evaluated as part of power uprates, generic letters, and bulletins to different editions of 

ASME Code, Section III and with varying levels of rigor when compared to the fatigue 

evaluations performed for the plant’s original design.

By letter dated July 7, 2015, the staff issued RAI 4.3.3-1, requesting that the applicant confirm 

that the CUF values that were compared with each other in a given system to identify the 

location with the highest CUF value were assessed similarly (e.g., amount of rigor in calculating 

CUF) and used the same fatigue curves to provide a meaningful comparison. The staff also 

requested that the applicant provide the basis for ranking or comparing the CUF values to one 

another to provide an appropriate method for screening and determining a leading/limiting 

location.

By letter dated August 6, 2015, the applicant responded to RAI 4.3.3-1. The response stated 

that the Class 1 fatigue analyses were performed in accordance with the ASME Code fatigue 

curves invoked in the applicable Edition and Addenda of the ASME Code listed in the design 

specifications for the components. The applicant stated that Class 1 piping systems were 

originally designed in accordance with ASNI B31.7 Class 1 requirements (1969) and that 

subsequent piping fatigue analyses were prepared in accordance with ASME Code Section III, 

Subsection NB-3600 requirements. The applicant stated that these two methodologies apply 

the same rules for determining the effects of cyclic loading. The response further stated that the 

thermal transients used in the design and fatigue analyses of the Class 1 piping and 

components are listed in UFSAR Table 3.9-24, which were derived from those established for 

the RPV. The applicant stated that this shows that the original design fatigue analyses were 

prepared using the same set of fatigue curves and the same set of design transients.

To determine limiting locations in the Class 1 piping, the applicant stated that initial comparisons 

of the CUF values were made between locations within the same stress report for a given 

subsystem, which ensured that the same inputs and methodology were applied to each location. 
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The applicant stated that the next step was to compare the limiting CUF values of each 

subsystem to determine the leading location of the overall piping system. The applicant stated 

that specific locations were reanalyzed as appropriate to account for modifications and power 

uprates and that the reanalyses were performed in accordance with ASME Code Section III, 

Class 1 fatigue design requirements. The applicant noted that this ensured that the revised 

analyses could still be compared to those in the original ASME NB-3600 stress reports. The 

applicant then determined the limiting locations by identifying the highest CUF values and then 

by comparing the bounding Fen values for each material. A limiting location(s) for the piping 

system was selected if the location with the highest CUF value also had the highest bounding

Fen value determined for the system.

The applicant also stated that certain RPV nozzle fatigue analyses were performed in 

accordance with ASME Code Section III, NB-3200, which results in a more accurate, rigorous 

analysis. The applicant stated that it selected a limiting location for each wetted material that 

was evaluated in accordance with ASME Code Section III, NB-3200.

The staff finds it appropriate that the applicant considered the type of fatigue curves and 

transient inputs in the fatigue analysis comparisons and that it ensured that the same set of 

fatigue curves and design transients were consistently used. The staff notes that this ensures 

the ability to compare CUF values for locations on an equivalent basis. The staff also finds 

reasonable that the applicant identified limiting locations for each wetted material in its fatigue 

analyses that used a different methodology (ASME Code Section III, NB-3200) than the 

methodology primarily used in its comparisons. The staff finds the applicant’s response 

acceptable because (a) the applicant provided an adequate basis to ensure that its comparison 

of locations was performed on an equivalent basis and (b) the applicant used a conservative 

approach to determine limiting locations by selecting locations that had the highest CUF value 

and bounding Fen values.

LRA Tables 4.3.3-1 and 4.3.3-2 provide the environmental fatigue results for RPVs of the LSCS, 

Units 1 and 2, respectively. LRA Tables 4.3.3-3 and 4.3.3-4 provide the environmental fatigue 

results for the Unit 1 and Unit 2 Class 1 piping systems, respectively. The LRA states that the 

location with the highest CUF value within the stress report for each material is considered 

limiting. However, the LRA also states that a location may be bounded by a location of a 

different material if the bounded material has a lower Fen value than that of the material of the 

leading location.

Note 12 in LRA Table 4.3.3-3 states that stainless steel location 376IJ in the N7 Head Spray 

Nozzle bounds the carbon steel location 10A in the Reactor Core Isolation Cooling piping 

system for LSCS, Unit 1. The staff also noted that Note 12 in LRA Table 4.3.3-3 states that 

environmental fatigue analysis for the stainless steel location 376IJ is provided in LRA 

Table 4.3.3-1. The staff noted that location 376IJ is provided in LRA Table 4.3.3-2, which 

provides the environmental fatigue analysis results for Unit 2. The staff is unclear on either one 

of the following: (a) which component in LRA Table 4.3.3-1 the note is referencing or (b) how a 

component in Unit 2 can bound a piping component in Unit 1 for consideration of EAF.

In addition, in RAI 4.3.3-1, by letter dated July 7, 2015, the staff also requested the applicant to 

clarify which RPV component bounds the carbon steel location 10A from LRA Table 4.3.3-3. 

The applicant was also requested to identify any additional locations where a different material 

type was bounded by the limiting location(s) within a system and provide the system, locations,

and materials that have been compared and bounded. For carbon steel location 10A in LRA 

Table 4.3.3-3 and any additional locations, the applicant was further requested to justify that the 
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comparison of CUFen values between different materials within a RPV component or piping 

system for the consideration of EAF is appropriate or valid.

In addition, in its response to RAI 4.3.3-1, by letter dated August 6, 2015, the applicant stated 

that it acknowledged the incorrect bounding location for the carbon steel location 10A and 

identified another incorrect link from a bounded location to a bounding location in LRA 

Table 4.3.3-2. The applicant provided the correct location links and updated LRA tables that 

show the updated locations. The staff reviewed the updated LRA tables and finds the 

corrections appropriate.

In its response, the applicant confirmed that this carbon steel piping location is bounded by a 

stainless steel head spray nozzle outer flange component in the RCIC system. The applicant 

also identified the additional systems where the leading stainless steel location bounds a carbon 

steel location: the Reactor Recirculation system, the Reactor Water Cleanup system, and the

RHR Supply and Return system.

For the RCIC system, the applicant’s response states that separate ASME Section III, NB-3600 

fatigue analyses were performed for each unit’s carbon steel RCIC piping systems. The 

applicant stated that there was one ASME Section III, NB-3200 analysis that included a finite 

element model that was common for both units for the stainless steel head spray nozzle outer 

flange. The carbon steel location, Node 10A, is a piping elbow welded to the stainless steel 

flange; therefore, both components experience the same set of transients. The applicant 

applied its methodology to select the limiting location and determined that the stainless steel 

head spray nozzle outer flange has both a higher CUF value, a higher bounding Fen multiplier, 

and it was performed with a more rigorous fatigue analysis than the carbon steel piping 

locations. Therefore, the applicant selected the stainless steel flange to bound the carbon steel 

piping locations for the RCIC system. The applicant applied this methodology to determine the 

limiting locations for the Reactor Recirculation system, the Reactor Water Cleanup system, and 

the RHR Supply and Return system. However, the staff noted that the CUFen value of locations 

made from different materials may respond differently when the EAF is being refined in the 

future. For the systems that include a limiting location that bounds a location of a differing 

material, the applicant did not provide sufficient justification that the stainless steel component 

would continue to be the leading location for components made from carbon steel materials 

eliminated after the CUFen has been refined for the stainless steel component. The applicant 

did not justify that the refinement of the higher CUFen of one material would ensure the reduction 

of CUFen values for another material within the same transient section such that the selected 

leading location would remain appropriate.

In its response to RAI 4.3.3-1, the applicant provided Tables 1 and 2 (for Units 1 and 2, 

respectively), which contain the ASME CUF values and bounding Fen multiplier factors for 

stainless steel and carbon steel locations with the highest CUF values. It was not clear to the 

staff whether the ASME CUF values represented the environmentally adjusted CUF values. 

The staff also had questions on how the bounding Fen factors were calculated, and why these 

values differed from the Fen values provided in LRA Tables 4.3.3-3 and 4.3.3-4.

The applicant’s response to RAI 4.3.3-1 also stated that, for LSCS, Unit 1, the reactor 

recirculation system, RHR supply and return system, and reactor water cleanup system are 

subjected to similar transients. For LSCS, Unit 2, the applicant stated that the reactor 

recirculation system and reactor water cleanup system are subjected to a similar set of 

transients. LRA Section 4.3.3 uses the term “same” when referencing transient sets. The staff 

was unclear whether the “similar” transients represent the “same” transient set for each system.
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The LRA states that the environmental fatigue analyses will be reviewed and updated if 

necessary to ensure that the limiting locations have been satisfactorily evaluated for reactor 

water environmental effects. The staff was unclear if the applicant will review the locations 

initially determined as limiting (locations included in LRA Tables 4.3.3-1 through 4.3.3-4), or if 

the applicant will re-evaluate the limiting locations using its screening determination to ensure 

that locations selected are still the most limiting in the system or subsystem. If the applicant will 

only review the environmental fatigue analyses for the locations in LRA Tables 4.3.3-1 through 

4.3.3-4, the staff needed additional justification on how the applicant will ensure that the limiting 

locations have not changed, especially accounting for systems that include different materials.

By letter dated November 3, 2015, the staff issued follow-up RAI 4.3.3-1a, requesting that the 

applicant provide justification that the refinement of the leading component material would 

bound other component materials in the listed systems. The staff requested that the applicant: 

(a) clarify the information provided in Tables 1 and 2, (b) clarify if “similar” transient sets 

represent the same set of transients, (c) describe how ASME CUF values were refined to 

achieve the 60-year NUREG/CR-6909 CUF values represented in the LRA, (d) provide 

additional justification that the environmental fatigue evaluation of stainless steel components 

can bound carbon steel components within the same systems, and (e) clarify if the selection of 

limiting components will be re-evaluated when initiating corrective actions.

By letter dated December 10, 2015, the applicant responded to RAI 4.3.3-1a. In the first part of 

the response, the applicant clarified that the ASME CUF values provided in Tables 1 and 2 in its 

response to RAI 4.3.3-1 are not environmentally adjusted CUF values but are the limiting ASME 

CUF values for the subsystems. Also, for Tables 1 and 2, the applicant provided the 

assumptions and methodology to calculate the bounding Fen multipliers that were used to select 

the bounding stainless steel locations. For carbon steel and stainless steel, the applicant used 

applicable sulfur content and/or strain rates that conservatively maximizes the Fen values. The 

applicant also stated that average temperatures were used to calculate Fen values, consistent 

with NUREG/CR-6909. The applicant specified that when calculating average transient 

temperatures, the higher value between the minimum transient temperature and the threshold 

temperature was used as a conservative approach. The applicant also provided additional 

details on its implementation of the equations from NUREG/CR-6909 to calculate the bounding 

Fen multipliers for the stainless steel and carbon steel components listed in Tables 1 and 2. The 

staff noted that the applicant’s methodology, including average temperature calculations, are 

consistent with the guidance in NUREG/CR-6909. The staff also noted that the applicant 

provided appropriate clarification regarding the values in Tables 1 and 2 in the response to 

RAI 4.3.3-1. The staff finds this portion of the applicant’s response acceptable.

Also in its response to RAI 4.3.3-1a, the applicant clarified that for Unit 1, the Reactor 

Recirculation system, RHR Supply and Return system, and Reactor Water Cleanup system are 

subjected to the same set of design transients and likewise for Unit 2, the Reactor Recirculation 

system and Reactor Water Cleanup system. The staff noted that this clarification resolves the 

staff’s concern that the same set of design transients were used to compare systems when 

evaluating fatigue. The staff finds this portion of the applicant’s response acceptable.

Also in its response to RAI 4.3.3-1a, the applicant provided additional details on how CLB 

ASME CUF values, such as those listed in Tables 1 and 2, were refined to achieve the 60-year 

NUREG/CR-6909 CUF values listed in the LRA. The applicant stated that the 60-year 

NUREG/CR-6909 CUF values were determined using the NUREG/CR-6909 fatigue curves 

instead of ASME Code fatigue curves for the applicable materials; using average operating 

temperature for transients instead of bounding design temperatures, and using reduced 
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numbers of cycles based upon 60-year cycle projections shown in LRA Tables 4.3.1-1 and 

4.3.1-2. The staff noted that these refinements provide appropriate and meaningful values 

when developing the 60-year projected CUF values. The staff finds this portion of the 

applicant’s response acceptable.

To address the staff’s concerns associated with bounding a component of one material with a 

different material within a system, the applicant stated that it performed additional environmental 

fatigue analyses for the carbon steel locations that were previously stated to be bounded by 

stainless steel components. The applicant stated that it has now evaluated the bounding 

location of each material within a system and no longer credits environmental fatigue analyses 

of stainless steel components to bound carbon steel components. The applicant evaluated the 

limiting carbon steel location for each of the Unit 1 and Unit 2 Reactor Recirculation system, the 

RHR Supply and Return system, the Reactor Water Cleanup system, and Reactor Core 

Isolation Cooling system. The applicant updated LRA Tables 4.3.3-3 and 4.3.3-4 to include 

these new evaluation results and deleted references in its LRA that state that one material can 

bound another material for environmental fatigue evaluations. The staff noted that the applicant 

has performed the environmental fatigue evaluations of the limiting components of each 

material within a system and no longer uses an environmental fatigue evaluation of one material 

to bound a differing material. The staff also reviewed the updates to the LRA and noted that it 

appropriately reflects the applicant’s response and new fatigue evaluation results. The staff 

finds this portion of the applicant’s response acceptable.

In its response to RAI 4.3.3-1a, the applicant stated that when initiating corrective actions to 

review and update environmental fatigue analyses, the applicant will evaluate and update the 

selection of limiting locations as necessary. The applicant specified that its implementing

procedures state that the locations qualified for environmental fatigue must continue to bound 

the locations that were not evaluated for environmental fatigue. The applicant stated that it 

updated the LRA, including the description of the Fatigue Monitoring program in the UFSAR 

supplement to specify that corrective actions will confirm that the locations evaluated for 

environmental fatigue remain bounding or will evaluate new limiting locations. The staff noted 

that with this clarification, the applicant will re-evaluate its bounding location selections and 

ensure that with any changes to environmental fatigue calculations, the applicant will continue to 

evaluate all limiting locations for environmental fatigue. The staff also noted that the updates to 

LRA Sections A.3.1.1 and B.3.1.1 accurately reflect the applicant’s RAI response. The staff 

finds this portion of the applicant’s response acceptable. The staff’s concerns in RAI 4.3.3-1 

and RAI 4.3.3-1a are resolved.

LRA Section 4.3.3 states that the environmental fatigue evaluations, shown in LRA 

Tables 4.3.3-1 through 4.3.3-4, as revised, will be incorporated into the CLB prior to the period 

of extended operation. The applicant will manage these fatigue evaluations using the Fatigue 

Monitoring program. The applicant states that this program will ensure that the cumulative 

number of occurrences of each of the transients will be maintained below the occurrence values 

used in the environmental fatigue evaluations. The Fatigue Monitoring program will initiate 

corrective actions when cycle limits are approached. The corrective actions will ensure that the 

CUF values do not exceed the ASME Code design limit of 1.0, including the effects of the 

reactor coolant environment. The applicant also clarified that these corrective actions include 

re-evaluation of bounding location selections as provided in its response to RAI 4.3.3-1a, as 

described above in this SER section. The staff’s evaluation of the Fatigue Monitoring program 

is provided in SER Section 3.0.3.2.22. The staff noted the applicant enhanced its program to 

evaluate the effects of the reactor coolant on fatigue evaluations. Therefore, the staff finds the 

applicant’s use of the Fatigue Monitoring program appropriate.
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Accordingly, the staff finds that the applicant has demonstrated, in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of environmental fatigue on the intended functions of 

Class 1 components will be adequately managed for the period of extended operation. 

Additionally, the applicant’s disposition meets the acceptance criteria in SRP-LR 

Section 4.3.2.1.3 because the applicant has demonstrated that the impact of the environmental 

fatigue on Class 1 components has been adequately addressed and will be managed by the 

Fatigue Monitoring Program. Therefore, the applicant’s environmental fatigue evaluations will 

remain valid, and the ASME Code limit of 1.0 will not be exceeded during the period of extended 

operation, or corrective actions will be taken.

4.3.3.3 UFSAR Supplement

LRA Section A.4.3.3 provides the UFSAR supplement summarizing the environmental fatigue 

analyses for RPV and Class 1 piping. The staff reviewed LRA Section A.4.3.3, consistent with 

the review procedures in SRP-LR Section 4.3.3.2, which state that the reviewer verifies that the 

applicant has provided information to be included in the UFSAR supplement that includes a 

summary description of the evaluation of the metal fatigue TLAA.

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SRP-LR Section 4.3.2.2 and, therefore, is acceptable. Additionally, the staff 

determines that the applicant provided an adequate summary description of its actions to 

address the metal fatigue TLAA for the RVIs, as required by 10 CFR 54.21(d).

4.3.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has acceptably demonstrated, 

in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of environmental fatigue on the 

intended functions of the Class 1 components will be adequately managed by the Fatigue 

Monitoring program for the period of extended operation. The staff also concludes that the 

UFSAR supplement contains an appropriate summary description of the EAF evaluations, as 

required by 10 CFR 54.21(d).

4.3.4 Reactor Vessel Internals Fatigue Analyses

4.3.4.1 Summary of Technical Information

LRA Section 4.3.4 states that the RVIs were procured before the issuance of ASME Code 

Section III, Subsection NG. However, the applicant stated that after the issuance of ASME 

Code Section III, Subsection NG, the applicant compared its RVI design with the ASME Code to 

ensure that the equivalent level of safety was met. The LRA states that it identified the RVI 

components that have been analyzed for fatigue, which are listed in LRA Table 4.3.4-1 along

with the corresponding bounding CUF value for both units at 40 years.

The LRA states that the fatigue analyses and fatigue exemptions for these RVI components 

were identified as TLAAs that are based on the same set of design transients used in the RPV 

fatigue analyses. The LRA further states that the original analyses were updated to consider 

the hydrodynamic loading effects resulting from LOCA events (including condensation 

oscillation and chugging cycles) and main steam relief valve (MSRV) discharge loads.
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The applicant dispositioned the TLAA for the RVIs in accordance with 10 CFR 54.21(c)(1)(iii) 

such that the effects of metal fatigue on the intended functions will be adequately managed by 

the Fatigue Monitoring program for the period of extended operation.

4.3.4.2 Staff Evaluation

The staff reviewed LRA Section 4.3.4 and the metal fatigue TLAAs for the RVI components to 

verify, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of fatigue will be adequately 

managed by the Fatigue Monitoring program for the period of extended operation.

The staff reviewed the applicant’s metal fatigue TLAAs for the RVI components and the 

corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures in 

SRP-LR Section 4.3.3.1.1.3. These procedures state that the reviewer should verify the 

appropriateness of the applicant’s program for monitoring and tracking the number of 

occurrences of critical thermal and pressure transients for the selected RCS components.

The staff noted that the transients for the RVI components are those listed in LRA 

Tables 4.3.1-1 and 4.3.1-2 and will be monitored and tracked by the Fatigue Monitoring 

program. The staff reviewed LRA Table 4.3.4-1 and (a) noted that the applicant used the 

bounding CUF value from both units to analyze each RVI component and (b) confirmed that the 

bounding CUF value is either below the design limit of 1.0 or is exempted in accordance with 

the criteria of ASME Code Section III, NG-3222.4(d). The staff determined that the enhanced 

Fatigue Monitoring program is capable of managing metal fatigue during the period of extended 

operation, consistent with GALL Report X.M1. The staff’s evaluation of the Fatigue Monitoring 

program is documented in SER Section 3.0.3.2.22.

The staff also reviewed its SEs of the power uprates implemented at LSCS. LSCS implemented 

a stretch power uprate in 2000 and a MUR power uprate in 2010. The staff confirmed that for 

both uprates, the fatigue design requirements will remain valid following implementation of the 

power uprates.

Based on its review, the staff finds that the applicant has demonstrated, in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of aging related to fatigue of the RVI components will be 

adequately managed for the period of extended operation. Additionally, the applicant’s 

disposition meets the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because the applicant 

is crediting its Fatigue Monitoring program to manage metal fatigue to ensure that the allowable 

design limits on fatigue usage are not exceeded during the period of extended operation;

otherwise, the applicant will take corrective actions in accordance with its program.

4.3.4.3 UFSAR Supplement

LRA Section A.4.3.4 provides the UFSAR supplement summarizing the metal fatigue TLAA for 

the RVI components. The staff reviewed LRA Section A.4.3.4, consistent with the review 

procedures in SRP-LR Section 4.3.3.2, which state that the reviewer verifies that the applicant 

has provided information to be included in the UFSAR supplement that includes a summary 

description of the evaluation of the metal fatigue TLAA.

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2 and, therefore, is acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address metal fatigue 

TLAA for the RVIs, as required by 10 CFR 54.21(d).
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4.3.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of metal fatigue on 

the intended functions of the RVI components will be adequately managed by the Fatigue 

Monitoring program for the period of extended operation. The staff also concludes that the 

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.3.5 High-Energy Line Break Analyses Based on Fatigue

4.3.5.1 Summary of Technical Information

LRA Section 4.3.5 states that the HELB analyses used the CUF values from the ASME 

Section III, Class 1 fatigue analyses as inputs for determining intermediate break locations. The 

applicant identified the HELB analyses as TLAAs because the Class 1 fatigue analyses were 

based on transient cycles postulated to bound 40 years of operation. The LRA states that these 

transients include 400 Startup and Shutdown cycles and will be monitored by the Fatigue 

Monitoring program to ensure that the CUF values will not exceed the design limit of 0.1 used in 

the HELB analyses.

The applicant dispositioned the TLAA in accordance with 10 CFR 54.21(c)(1)(iii) such that the 

Fatigue Monitoring program will be used to manage transient cycles as inputs for the HELB 

analyses.

4.3.5.2 Staff Evaluation

The staff reviewed LRA Section 4.3.5 and the TLAAs for HELB analyses based on a CUF 

criterion to verify, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of aging will be 

adequately managed during the period of extended operation.

The staff reviewed the applicant’s TLAA and the corresponding disposition consistent with the 

review procedures in SRP-LR Section 4.7.3.1.3, which state that the applicant proposes to 

manage the aging effects associated with the TLAA by an AMP in the same manner as 

described in the integrated plant assessment in 10 CFR 54.21(a)(3). The SRP-LR also states 

that the reviewer reviews the applicant’s AMP to verify that the effects of aging on the intended 

function(s) are adequately managed consistent with the CLB for the period of extended 

operation. In addition, SRP-LR requires that a license renewal applicant must identify the 

structures and components associated with the TLAA.

UFSAR Section 3.6.2 states that high-energy piping are those for which, during “normal plant 

conditions,” the maximum temperature exceeds 200 °F or the maximum pressure exceeds 

275 psig. The staff noted that a given location is identified as a postulated pipe break location if 

it satisfied the criteria in UFSAR Section 3.6.2.1.1. One such criterion is that any intermediate 

location between terminal ends where the CUF from the piping fatigue analysis exceeds 0.1 is 

identified as a line break location. The staff noted that the postulations of break location based 

on CUFs are TLAAs because they are dependent on an assumed number of cycles expected 

for the design of the plant.

The applicant credits the Fatigue Monitoring program to manage the HELB analyses through 

the period of extended operation. The staff noted that as long as the number of occurrences of 
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each transient that occurs at the site remains bounded by the 40-year number of cycles 

assumed in these analyses, the HELB postulation evaluation remains valid. The staff 

determined that the enhanced Fatigue Monitoring program ensures that the number of 

occurrences of each transient will not be exceeded during the period of extended operation or 

that corrective actions are taken. The staff’s evaluation of the Fatigue Monitoring program is 

documented in SER Section 3.0.3.2.22.

Accordingly, the staff finds that the applicant has demonstrated, in accordance with 

10 CFR 54.21(c)(1)(iii), that the HELB analyses based on CUF will be adequately managed 

through the period of extended operation. Additionally, the applicant’s Fatigue Monitoring 

program meets the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because it monitors and 

tracks the transient cycles assumed in the analysis and requires corrective action before

exceeding the numbers of cycles for each transient used in the analysis.

4.3.5.3 UFSAR Supplement

LRA Section A.4.3.5 provides the UFSAR supplement, which summarizes the TLAA for HELB 

analyses based on CUF. The staff reviewed LRA Section A.4.3.4, consistent with the review 

procedures in SRP-LR-Section 4.3.3.2, which state that the information to be included in the 

UFSAR supplement should include a summary description of the evaluation of the TLAA.

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SRP-LR Section 4.3.2.2. Additionally, the staff determines that the applicant provided 

an adequate summary description of its actions to address the TLAA for HELB analyses based 

on CUF as required by 10 CFR 54.21(d).

4.3.5.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the HELB analyses will be adequately 

managed by the Fatigue Monitoring program for the period of extended operation. The staff 

also concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d).

4.3.6 Main Steam Relief Valve Discharge Piping Fatigue Analyses

4.3.6.1 Summary of Technical Information

LRA Section 4.3.6 describes the fatigue analysis performed for the MSRV discharge lines. The 

LRA states that this system was designed to ASME Code Section III, Class 3 requirements, but 

the applicant conservatively performed a Class 1 fatigue analysis for the MSRV discharge lines 

for the portion of the MSRV discharge lines that extend from the drywell floor penetration to the 

quencher. The applicant stated that the combined stresses and corresponding equivalent 

stress cycles were inputs into the fatigue usage factors. The LRA states that the input cycles 

were based on the projected 40-year operation service; therefore, the analysis is identified as a 

TLAA.

The fatigue analysis for the MSRV discharge line is based on a small break accident (SBA) 

event, which accounts for the hydrodynamic loadings that can affect the MSRV discharge 

piping, including MSRV actuations, chugging, and seismic effects. The LRA states that, based 

on the SBA event evaluation, the fatigue analysis for the MSRV discharge lines assumed 
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2,800 MSRV actuations and determined the limiting MSRV discharge line CUF value to be 

0.616. The LRA states that the cycles assumed in the fatigue analysis were projected to 

60 years of operation, as included in LRA Tables 4.3.1-1 and 4.3.1-2. Based on these 

projections, the applicant concluded that the cycles caused by the SBA event will not exceed 

the number of cycles assumed in the original 40-year analysis. Therefore, the applicant 

dispositioned this TLAA in accordance with 10 CFR 54.21(c)(1)(i) such that the MSRV 

discharge piping analyses will remain valid for the period of extended operation.

4.3.6.2 Staff Evaluation

The staff reviewed LRA Section 4.3.6 and the TLAA for the MSRV discharge piping analyses to 

verify, in accordance with 10 CFR 54.21(c)(1)(i), that MSRV discharge piping analyses will

remain valid for the period of extended operation.

The staff reviewed the applicant’s TLAA and the corresponding disposition, consistent with the 

review procedures in SRP-LR Section 4.3.3.1.1.1, which state that the operating transient 

experience and a list of the assumed transients used in the existing CUF calculations for the 

current operating term are reviewed to ensure that the number of assumed transients would not 

be exceeded during the period of extended operation. The SRP-LR further states that the 

review should also include an assessment of the TLAA information against the relevant design 

basis information and CLB information.

The LRA states that the MSRV discharge line fatigue analyses are based on the SBA LOCA 

event. The applicant stated that its original fatigue analyses considered the hydrodynamic 

loadings that can affect the MSRV discharge piping, including MSRV actuations, chugging, and 

seismic effects. The LRA states that this evaluation resulted in the original fatigue analyses for 

the MSRV discharge lines to assume 2,800 MSRV actuations. The staff reviewed LRA 

Tables 4.3.1-1 and 4.3.1-2 and confirmed that the applicant appropriately baselined the actual 

transient cycle count of the MSRV actuations for both units and projected the 60-year cycle 

count. For LSCS, Unit 1, MSRV actuations, the staff noted that the applicant projected a total of 

841 cycles at the end of 60 years of operation but still added a margin of 1,159 cycles. For 

Unit 2 MSRV actuations, the staff noted that the applicant projected a total of 688 cycles at the 

end of 60 years of operation but still added a margin of 1,312 cycles. The staff noted that the 

applicant chose to add a conservative margin to project the 60-year cycle counts for the 

transient. Even with the added margin, the total projected number of occurrences at the end of 

the period of extended operation would remain below the assumed analysis input of 

2,800 cycles. Therefore, the staff finds it reasonable that the input of 2,800 MSRV actuation 

cycles assumed in the original fatigue analyses will not be exceeded and includes additional 

margin to account for unanticipated transient occurrences during the period of extended 

operation.

Accordingly, the staff finds that the applicant has demonstrated, in accordance with 

10 CFR 54.21(c)(1)(i), that the TLAAs for the MSRV discharge piping fatigue analyses will 

remain valid for the period of extended operation. Additionally, the applicant’s analysis meets 

the acceptance criteria in SRP-LR Section 4.3.2.1.2.1 because the applicant has demonstrated

that, for those limiting MSRV discharge lines, the cycle limit for fatigue analyses established in 

the design analyses will not be exceeded; therefore, the analysis will remain valid for the period 

of extended operation.
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4.3.6.3 UFSAR Supplement

LRA Section A.4.3.6 provides the UFSAR supplement, which summarizes the TLAA for the

MSRV discharge piping fatigue analyses. The staff reviewed LRA Section A.4.3.6, consistent 

with the review procedures in SRP-LR Section 4.3.3.2, which state that the information to be 

included in the UFSAR supplement should include a summary description of the evaluation of 

the TLAA.

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SRP-LR Section 4.3.2.2. Additionally, the staff determines that the applicant provided 

an adequate summary description of its actions to address the TLAA for the MSRV discharge 

piping fatigue analyses as required by 10 CFR 54.21(d).

4.3.6.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, in accordance with 10 CFR 54.21(c)(1)(i), that the TLAA for the MSRV discharge 

piping fatigue analyses remains valid for the period of extended operation. The staff also 

concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluations, as required by 10 CFR 54.21(d).

4.4 Environmental Qualification (EQ) of Electric Components

The 10 CFR 50.49 EQ program is a TLAA for purposes of license renewal. The TLAA of the EQ 

electrical components includes all long-lived, passive, and active electrical and instrumentation 

and control (I&C) components that are important to safety and located in a harsh environment. 

The harsh environments of the plant are those areas subject to the environmental effects of a 

design basis event (e.g., LOCAs or HELBs or post-LOCA environment). EQ equipment 

comprises electrical equipment important to safety (i.e., safety-related and nonsafety-related 

equipment) that is relied upon to remain functional during and following design basis events 

including nonsafety-related electrical equipment whose failure under postulated environmental 

conditions could prevent the satisfactory accomplishment of a safety-related function, and

certain post-accident monitoring equipment.

As required by 10 CFR 54.21(c)(1), the applicant must provide a list of EQ TLAAs in the LRA. 

The applicant shall demonstrate that for each type of EQ equipment, one of the following is true: 

(1) the analyses remain valid for the period of extended operation, (2) the analyses have been 

projected to the end of the period of extended operation, or (3) the effects of aging on the 

intended function(s) will be adequately managed for the period of extended operation.

4.4.1 Summary of Technical Information in the Application

LRA Section 4.4 describes the applicant’s TLAA for the “Environmental Qualification (EQ) of 

Electric Components.” The TLAA states that the aging evaluations for electrical components in 

the applicant’s EQ program that specify a qualification of at least 40 years are TLAAs for license 

renewal because the criteria contained in 10 CFR 54.3 are met. The LRA states that the EQ 

program meets the requirements of 10 CFR 50.49 for the applicable electrical components 

important to safety. The LRA also states that the EQ program demonstrates that certain 

electrical components located in harsh environments are qualified to perform their safety 

function in those harsh environments after the effects of inservice aging. As stated in the LRA, 

a harsh environment is an area of the plant that could be subject to the harsh environmental 
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effects of a LOCA, HELB, or post-LOCA radiation. The LRA further states that the EQ program 

also requires that significant aging mechanisms (e.g., thermal, radiation, and cyclical aging as 

applicable) be addressed as part of environmental qualification. According to the applicant’s EQ 

program, as required by 10 CFR 50.49, EQ components are refurbished or replaced, or their 

qualification is extended before they reach the aging limits established in the evaluation. 

Further, the LRA notes that the reanalysis of an aging evaluation addresses the attributes of 

analytical methods, data reduction and collection methods, underlying assumptions, acceptance 

criteria, and corrective actions. The EQ program is stated to manage these aging mechanisms 

with evaluations based on 10 CFR 50.49 qualification methods. The applicant, in accordance 

with 10 CFR 54.21(c)(2), performed a review for applicable exemptions to TLAAs and noted that 

no exemptions were identified based on a TLAA.

The applicant dispositioned the TLAA for the EQ program in accordance with 

10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of inservice aging on the intended 

functions will be adequately managed by the Environmental Qualification (EQ) of Electric 

Components program for the period of extended operation.

4.4.2 Staff Evaluation

The staff reviewed the applicant’s “Environmental Qualification (EQ) of Electric Components”

TLAA for electric components and the corresponding disposition of 10 CFR 54.21(c)(1)(iii), 

consistent with the review procedures in SRP-LR Section 4.4.2.1, which state that, pursuant to 

10 CFR 54.21(c)(1)(iii), an applicant must demonstrate that the effects of aging on the intended 

function(s) will be adequately managed for the period of extended operation.

The EQ requirements established by Criterion 4, “Environmental and Dynamic Effects Design 

Bases,” of Appendix A to 10 CFR Part 50 and by 10 CFR 50.49 specifically require each 

applicant to establish a program to qualify electrical equipment so that such equipment, in its 

end of life condition, will meet its performance specifications during and following design basis 

accidents. An EQ program in accordance with the requirements of 10 CFR 50.49 is considered 

an adequate AMP for the purposes of license renewal. Electric components in the applicant’s 

EQ program identified as having a qualified life equal to, or greater than, the current operating 

term (i.e., 40 years) are considered a TLAA for license renewal. The Environmental 

Qualification (EQ) of Electric Components program includes long-lived passive and active 

electrical and I&C components that are important to safety and are located in a harsh 

environment. Harsh environments are those areas of the plant subject to the environmental 

effects of a design basis event (e.g., LOCA, an HELB, or post-LOCA environment). EQ 

equipment comprises electrical equipment important to safety (i.e., safety-related and

nonsafety-related equipment) that is relied upon to remain functional during and following 

design basis events including nonsafety-related electrical equipment whose failure under 

postulated environmental conditions could prevent the satisfactory accomplishment of a 

safety-related function, and certain post-accident monitoring equipment.

The staff reviewed LRA Sections 4.4 and B.3.1.3, plant basis documents, and additional 

information provided to the staff and interviewed plant personnel to verify whether the applicant 

provided adequate information to meet the requirement of 10 CFR 54.21(c)(1). For electrical 

equipment, the applicant uses 10 CFR 54.21(c)(1)(iii) in its “Environmental Qualification (EQ) of 

Electric Components” TLAA evaluation to demonstrate that EQ equipment aging mechanisms 

and effects will be adequately managed during the period of extended operation. In accordance 

with the GALL Report, plant EQ programs that implement the requirements of 10 CFR 50.49 are 

considered acceptable AMPs under license renewal 10 CFR 54.21(c)(1)(iii). GALL Report 
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AMP X.E1, “Environmental Qualification (EQ) of Electric Components,” meets the requirements 

of 10 CFR 54.21(c)(1)(iii). The staff reviewed the applicant’s “Environmental Qualification (EQ) 

of Electric Components” program to determine whether the electrical and I&C components 

covered under this program will continue to perform their intended functions, consistent with the 

CLB, for the period of extended operation.

The staff’s evaluation of the components qualification focused on how the “Environmental 

Qualification (EQ) of Electric Components” TLAA and the Environmental Qualification (EQ) of 

Electric Components AMP manages aging effects to meet the requirements pursuant to

10 CFR 50.49. The staff conducted an audit of the information provided in LRA Sections 4.4, 

A.4.4, B.3.1.3, and A.3.1.3 and program basis documents, including the aging management 

review of electrical systems, AMP evaluation results, and operating experience reviews. LRA 

Section 4.4 evaluates the component reanalysis attributes, including analytical models, data 

collection and reduction methods, underlying assumptions, acceptance criteria, and corrective 

actions referenced in SRP-LR Table 4.4-1 against the applicant’s EQ program. On the basis of 

its audit, the staff concluded that the Environmental Qualification (EQ) of Electric Components 

AMP, which the applicant claimed to be consistent with GALL Report AMP X.E1, “Environment 

Qualification (EQ) of Electric Components,” is consistent with the GALL Report. The staff also 

concluded that the applicant’s EQ program reanalysis attributes TLAA evaluation is consistent 

with SRP-LR Section 4.4.2.1.3 and SRP-LR Table 4.4-1. Additionally, the staff’s review for 

applicable exemptions to TLAAs during the audit noted that no exemptions were identified 

based on a TLAA.

The staff concludes that the applicant’s “Environmental Qualification (EQ) of Electric 

Components” TLAA meets the acceptance criteria in SRP-LR Section 4.4.2.1 and the specific 

acceptance criteria of SRP-LR Section 4.4.2.1.3 because the TLAA demonstrates that the 

applicant’s EQ program is capable of programmatically managing the qualified life of 

components within the scope of the program for license renewal. The continued implementation 

of the EQ program provides assurance that the aging effects will be managed and that 

components within the scope of the EQ program will continue to perform their intended 

functions for the period of extended operation.

The staff also finds that the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), 

that the effects of thermal, radiation, and cyclical aging on the intended functions of EQ 

electrical components will be adequately managed for the period of extended operation.

Additionally, the “Environmental Qualification (EQ) of Electric Components” program meets the 

acceptance criteria in SRP-LR Section 4.4.2.1.3 because the continued implementation of the 

EQ program provides assurance that the aging effects will be managed and that components 

within the scope of the EQ program will continue to perform their intended functions for the 

period of extended operation in accordance with the requirements of 10 CFR 50.49 and 

10 CFR 54.21(c)(1)(iii).

4.4.3 UFSAR Supplement

LRA Section A.4.4 provides the UFSAR supplement summarizing the “Environmental 

Qualification (EQ) of Electric Components” TLAA. The staff reviewed LRA Section A.4.4,

consistent with the review procedures in SRP-LR Section 4.4.3.2, which state that the applicant 

has provided information to be included in the UFSAR supplement that includes a summary 

description of the TLAA evaluation of the environmental qualification of electric equipment and 

has provided a UFSAR supplement with information equivalent to that in SRP-LR Table 4.4-2.
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Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.4.2.2 and, therefore, is acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the 

“Environmental Qualification (EQ) of Electric Components” TLAA, as required by 

10 CFR 54.21(d).

4.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of thermal, radiation, and 

cyclic aging on the intended functions of EQ electrical components will be adequately managed 

by the “Environmental Qualification (EQ) of Electric Components” program for the period of 

extended operation. The staff also concludes that the UFSAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.5 Concrete Containment Tendon Prestress Analyses

4.5.1 Summary of Technical Information in the Application

LRA Section 4.5 describes the applicant’s TLAA for the concrete containment tendon prestress 

analyses. The LRA states that the BWR Mark II post-tensioned concrete containment 

structures at LSCS, Units 1 and 2, consist of a steel head and a post-tensioned wall supported 

on a basemat of reinforced concrete. The LRA also states that the containment wall 

post-tensioning system, which extends from the basemat to the refuel floor, consists of 

188 horizontal (hoop) and 120 vertical unbonded tendons. Each tendon consists of 90 high 

strength steel wires within steel conduits filled with a corrosion protection medium.

The LRA states that the containment tendon prestressing forces are subject to time-dependent 

losses due to relaxation of the steel tendons and to creep and shrinkage of the concrete, which 

were considered in the original design of the plant to arrive at minimum required values (MRVs) 

for each tendon type (vertical or hoop) based on a 40-year operating term. The LRA also states 

that the ASME Section XI, Subsection IWL program (LRA Section B.2.1.30) conducts periodic 

surveillances in which individual tendon prestressing forces are measured and plotted and trend 

lines are developed. These are evaluated against acceptance criteria in ASME Code 

Section XI, Subsection IWL, that are based on predicted lower limit (PLL) force values for each 

sampled tendon at the time of surveillance, calculated in accordance with RG 1.35.1, 

“Determining Prestressing Forces for Inspection of Prestressed Concrete Containments,” dated 

July 1990, and MRVs for each tendon type. The LRA further states that calculated PLL values 

and updated trend lines developed based on regression analyses of all actual measured 

individual tendon forces consistent with NRC Information Notice (IN) 99-10, “Degradation of 

Prestressing Tendon Systems in Prestressed Concrete Containments,” dated April 13, 1999, 

are used to evaluate the acceptability of the containment structure to perform its intended 

function over the current 40-year life of the plant and, therefore, are TLAAs requiring evaluation 

for the period of extended operation.

The applicant stated that the regression analyses of all measured forces in individual tendons 

from surveillances to date, associated with the vertical and hoop tendons at LSCS, Units 1 

and 2, updated and projected to 60 years (LRA Figures 4.5.1-1 through 4.5.1-4), indicate a 

trend that the prestressing forces will remain above the respective group MRVs through the 

period of extended operation for each tendon group. The applicant stated that the trend lines 

are updated at each surveillance to demonstrate that the individual and tendon group 
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prestressing forces will remain above the MRV for each tendon type until the next scheduled 

surveillance and for the life of the plant.

The applicant dispositioned the TLAA for the concrete containment tendon prestress analyses in 

accordance with 10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of loss of prestress 

forces on the intended functions of containment will be adequately managed by the Concrete 

Containment Tendon Prestress program in LRA Section B.3.1.2 for the period of extended 

operation.

4.5.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the concrete containment tendon prestress analyses 

and the corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review 

procedures in SRP-LR Section 4.5.3.1.3, which state that the applicant may reference the 

applicable GALL Report program and that the reviewer verifies that the applicant has identified 

the appropriate program (i.e., GALL Report AMP X.S1, “Concrete Containment Tendon 

Prestress”) as described and evaluated in the GALL Report. The SRP-LR also states that the 

reviewer ensures that the applicant has stated that its program contains the same program 

elements that the staff evaluated and relied on in approving the corresponding generic program 

in the GALL Report.

Further, the SRP-LR states that the GALL Report recommends further evaluation of the 

applicant’s operating experience related to the containment prestress force to ensure that the 

applicant’s program adequately incorporates the relevant operating experience that occurred at 

the applicant’s plant, as well as at other plants. The SRP-LR also states that the applicant 

should consider, in its AMP, applicable portions of the operating experience with prestressing 

systems described in IN 99-10.

The staff reviewed LRA Section 4.5 and verified that the applicant’s containment tendon 

surveillance program, in accordance with ASME Code Section XI, Subsection IWL, develops the 

PLL force values for each individual tendon scheduled for examination for the given surveillance 

year, consistent with the guidance in RG 1.35.1. The staff also verified that the applicant’s 

program develops trend lines of prestressing forces for each tendon type or group using actual 

individual prestressing forces measured during surveillances to date, which is consistent with 

the guidance provided in IN 99-10. The applicant’s acceptance criteria for prestressing forces 

consists of PLLs and MRVs in accordance with ASME Code Section XI, Subsection IWL. The 

staff noted that the applicant’s updated regression analyses of measured tendon forces for 

vertical and hoop tendons, based on surveillances at years 1, 3, 5, 10, 15, and 25 for LSCS, 

Unit 1, and surveillances at years 1, 3, 5, 15, and 25 for LSCS, Unit 2, projected to 60 years 

(LRA Figures 4.5.1-1 through 4.5.1-4) indicate a trend that the prestressing forces will remain 

above the MRV for each tendon group through the period of extended operation. Further, the 

staff noted that, because tendon force trends may vary with time, the applicant plans to use its 

enhanced Concrete Containment Tendon Prestress AMP, described in LRA Section B.3.1.2, to 

monitor and manage the TLAAs (PLLs and regression analysis) associated with the loss of 

tendon prestressing forces during the period of extended operation. The staff noted that, as an 

enhancement to the LRA program, the trend lines will be updated as part of the regression 

analyses following each surveillance interval during the period of extended operation and will be 

compared to the PLL and MRV for each tendon group; appropriate corrective action will be 

taken if adverse trends are indicated.
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The staff’s review and evaluation of the LRA Section B.3.1.2 AMP, “Concrete Containment 

Tendon Prestress,” which, with enhancement, will be consistent with the 10 elements of the 

GALL Report AMP X.S1, “Concrete Containment Tendon Prestress,” is documented in SER 

Section 3.0.3.2.23. This review includes further evaluation of the applicant’s operating 

experience related to the containment prestress forces, and the results show that the applicant’s 

program has adequately considered plant-specific and industry operating experience.

Accordingly, the staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(iii), 

that the effects of loss of tendon prestressing forces on the intended functions of concrete 

containment structures will be adequately managed by the Concrete Containment Tendon 

Prestress AMP for the period of extended operation.

Additionally, the applicant’s program meets the acceptance criteria in SRP-LR Section 4.5.2.1.3 

because (1) the applicant has identified the Concrete Containment Tendon Prestress program

that assesses containment tendon prestressing forces, which, with an enhancement, will be 

consistent with the 10 elements of the GALL Report AMP X.S1, determined by staff as an 

acceptable AMP to address containment tendon prestress pursuant to 10 CFR 54.21(c)(1)(iii), 

and (2) the applicant’s program adequately considered plant-specific and industry operating

experience related to the containment prestress forces.

4.5.3 UFSAR Supplement

LRA Section A.4.5 provides the UFSAR supplement summarizing the TLAA related to concrete 

containment tendon prestress analyses. The staff reviewed LRA Section A.4.5, consistent with

the review procedures in SRP-LR Section 4.5.3.2, which state that the reviewer verifies that the 

applicant has provided an UFSAR supplement that includes a summary description of the 

evaluation of tendon prestress TLAA with information equivalent to that in SRP-LR Table 4.5-1.

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SRP-LR Section 4.5.2.2 and, therefore, is acceptable. Additionally, the staff 

determines that the applicant provided an adequate summary description of its actions to 

address concrete containment tendon prestress analyses TLAA, as required by 

10 CFR 54.21(d).

4.5.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of loss of tendon 

prestressing forces on the intended functions of concrete containment structures will be 

adequately managed by the Concrete Containment Tendon Prestress AMP for the period of 

extended operation. The staff also concludes that the UFSAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.6 Primary Containment Fatigue Analyses

LRA Section 4.6 provides the applicant’s analyses of the following areas related to primary 

containment fatigue:

• LRA Section 4.6.1, Primary Containment Liner and Penetrations Fatigue Analyses

• LRA Section 4.6.2, Primary Containment Refueling Bellows Fatigue Analysis

• LRA Section 4.6.3, Primary Containment Downcomer Vents Fatigue Analysis
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4.6.1 Primary Containment Liner and Penetrations Fatigue Analyses

4.6.1.1 Summary of Technical Information in the Application

LRA Section 4.6.1 describes the applicant’s TLAAs for primary containment liner, Class MC 

components, and penetrations that were designed and analyzed for transient cycles predicted 

for 40 years. The containment liner and Class MC components are non-Class 1 components 

designed for cumulative fatigue damage in accordance with ASME Code Section III, 

Subsection NE-3222.4, based on the transient cycles listed in LSCS UFSAR Table 5.2-4. In the 

same manner, the fatigue analyses for the primary containment penetrations are performed in 

accordance with ASME Code Section III, Subsections NB-3222 and NE-3223, for Class 1 

penetrations and in accordance with ASME Code Section III, Subsection NB-3222.4 for 

non-Class 1 (Class MC) penetrations. The applicant considers Class 1 penetrations to be those 

penetration assemblies with Type I head fittings and penetration sleeves and non-Class 1 or 

Class MC as those penetration assemblies with Type II and III head fittings and penetration 

sleeves. The applicant also considers Class MC components to be those steel components 

from the concrete containment that form part of the pressure boundary and are not backed by 

structural concrete (e.g., drywell head assembly and equipment hatch).

LRA Tables 4.3.1-1 and 4.3.1-2 shows the results of 60-year transient cycles projections for 

LSCS, Units 1 and 2, respectively. These transient cycle projections include 21 normal, upset,

and test conditions and 8 emergency and faulted conditions. The applicant stated that the 

results for Unit 1 (LRA Table 4.3.1-1) show that transient cycle projections for startup and 

shutdown conditions, transient numbers 3 and 13, are projected to exceed their design limits 

within 60 years. The applicant also stated that the results for Unit 2 (LRA Table 4.3.1-2) 

demonstrate that transient cycle limits for Class 1 piping penetrations and the containment liner 

will not be exceeded in 60 years. The applicant further stated that the Fatigue Monitoring 

program (LRA Section B.3.1.1) will be used to monitor and track the analyzed transients and to 

provide corrective actions before exceeding the transient cycle limits to ensure that the 

component CUF does not exceed the design limit of 1.0 for these components.

The applicant dispositioned the TLAAs for the primary containment liner, Class MC 

components, and penetrations in accordance with 10 CFR 54.21(c)(1)(iii) to demonstrate that 

the effects of cumulative fatigue damage on the intended functions of components analyzed in 

accordance with ASME Code Section III, Class 1 requirements will be adequately managed by 

the Fatigue Monitoring program for the period of extended operation.

4.6.1.2 Staff Evaluation

The staff reviewed the applicant’s TLAAs for the primary containment liner, Class MC 

components, and penetrations and their corresponding disposition of 10 CFR 54.21(c)(1)(iii), 

consistent with the review procedures in SRP-LR Section 4.6.3.1.1.3, which state that the 

program shall demonstrate that the effects of aging on the component’s intended function(s) will 

be adequately managed during the period of extended operation. The SRP-LR also states that,

if the program relies on mitigation or inspection, it shall be reviewed against the 10 elements 

described in SRP-LR Section A.1 “Aging Management Review-Generic (Branch Technical 

Position RLSB-1).” If the applicant proposes a component replacement before its CUF exceeds 

1.0, the CUF for the replacement must be less than or equal to 1.0 during the period of 

extended operation.
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In its review of the applicant’s TLAA disposition in LRA Section 4.6.1, the staff noted that the 

disposition specifically addresses components that are in accordance with ASME Code 

Section III, Class 1 requirements, but it does not address non-Class 1 components. The LRA 

does not state how the TLAA analyses associated with non-Class 1 components were 

dispositioned in the application or how the effects of aging for these components will be 

adequately managed to ensure that the CUF values are maintained less than or equal to 1.0

during the period of extended operation. The staff also noted that the application does not 

specify which transient cycle projections from LRA Tables 4.3.1-1 and 4.3.1-2 correspond to 

each fatigue analysis described in LRA Section 4.6.1. By letter dated August 28, 2015, the staff 

issued RAI 4.6.1-1, requesting that the applicant clarify which transient cycle projection(s) from 

LRA Tables 4.3.1-1 and 4.3.1-2 was considered for each design analysis described in LRA 

Section 4.6.1, clarify the TLAA dispositions for non-Class 1 components, and describe how the 

transient limits will be maintained below the design limits for these components.

In its response dated September 28, 2015, the applicant stated that the design analyses 

described in LRA Section 4.6.1 are associated with the transient cycle projections from LRA

Tables 4.3.1-1 and 4.3.1-2 as follows:

• For primary containment liner plates and Class MC components, the applicant stated 

that transient numbers 21 and 28 were projected for 60 years and are monitored by the 

Fatigue Monitoring program.

• For containment penetration assemblies that contain Class 1 process pipe or head 

fittings, the applicant stated that transient numbers 1, 2, 3, 4, 5, 6, 7, 8a, 8b, 9a, 9b, 9c, 

10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, and 28 were projected for 60 years and are 

monitored by the Fatigue Monitoring program.

• For containment penetration assemblies that contain non-Class 1 process pipe with 

maximum operating temperatures greater than 220 °F (including head fitting and 

penetration sleeves), the applicant stated that transient numbers 1, 3, 4, 9a, 9b, 10, 11, 

13, 15, 16, 17, 22, 23, 24, 27, and 28 were projected for 60 years and are monitored by 

the Fatigue Monitoring program.

• For containment penetration assemblies that contain non-Class 1 process pipe with 

maximum operating temperatures equal to or less than 220 °F (including head fitting and 

penetration sleeves), the applicant stated that most of the analyses are based on the 

same transients listed for those penetrations with maximum operating temperatures 

greater than 220 °F (above) and they are monitored by the Fatigue Monitoring program. 

The applicant also stated that these analyses were designed in the same manner as 

those with maximum operating temperatures greater than 220 °F.

In its response, the applicant also stated that there are some primary containment penetration 

assemblies that contain non-Class 1 piping that were analyzed for transients that are not 

included in LRA Tables 4.3.1-1 and 4.3.1-2. The applicant addressed these additional 

transients as follows:

• For containment penetration M-76, the applicant stated that the penetration contains the 

RCIC turbine exhaust line to the suppression pool for which the associated fatigue 

analysis is based on the RCIC injections cycles listed in LRA Tables 4.3.1-1 and 4.3.1-2, 

transient numbers 9b and 17, and other surveillance testing cycles not included in the 

LRA tables. The applicant also stated that this analysis was re-evaluated based on 

60-year projection cycles for transient numbers 9b and 17, plus the predicted RCIC 
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turbine surveillance tests for 60 years (300), and including a margin of 47, which 

resulted in a total of 600 cycles, with a 60-year CUF value of 0.00235. The applicant 

further stated that the allowable number of cycles for these transients is approximately 

255,000 cycles.

• Using containment penetrations M-83, M-88, M-89, and M-99 as a representative 

sample, the applicant stated that the fatigue analyses are based on transients that are 

associated with potential discharges from relief valves that are not included in the LRA 

tables. The applicant also stated that current CUF values are 0.000005 for containment 

penetration M-83 and 0.000038 for containment penetrations M-88, M-89, and M-99, 

with an allowable number of cycles of approximately 52,750 cycles for these transients.

• Using containment penetrations M-85, M-86, and M-87 as a representative sample, the 

applicant stated that the fatigue analyses are based on transients that are associated 

with potential discharges from safety valves that are not provided in the LRA tables. The 

applicant also stated that the CUF from current analyses is 0.000004, with an allowable 

number of cycles of approximately 475,000 cycles for these transients.

The applicant clarified the TLAA dispositions for non-Class 1 components as follows:

• For primary containment Class 1 and non-Class 1 components (for containment liner, 

MC components, and penetrations) that are analyzed for fatigue based on transient 

cycles listed in LRA Tables 4.3.1-1 and 4.3.1-2, the applicant stated that they are 

dispositioned in accordance with 10 CFR 54.21(c)(1)(iii) because the effects of aging will 

be adequately managed by the Fatigue Monitoring program.

• For primary containment non-Class 1 penetration fatigue analyses that are based on 

transient cycles not listed in LRA Tables 4.3.1-1 and 4.3.1-2, the applicant stated that 

they are dispositioned in accordance with 10 CFR 54.21(c)(1)(i); the analyses remain 

valid through the period of extended operation because they have low CUF values and a 

high number of allowable cycles that will not be exceeded during the period of extended 

operation.

• For primary containment penetration M-76, the applicant stated that the non-Class 1 

RCIC turbine exhaust line is dispositioned in accordance with 10 CFR 54.21(c)(1)(ii) 

because the analysis has been projected through the period of extended operation.

As a part of this RAI response, the applicant revised LRA Section 4.6.1 and Appendix A.4.6.1.

The staff finds the applicant’s response acceptable because the applicant (1) stated the 

transient cycle projections from LRA Tables 4.3.1-1 and 4.3.1-2 that correspond to each design 

analysis described in LRA Section 4.6.1, (2) clarified that the TLAA disposition in accordance 

with 10 CFR 54.21(c)(1)(iii) addresses Class 1 and non-Class 1 components for the primary 

containment liner, Class MC components, and penetrations to ensure that transient limits will be 

maintained below the design limits during the period of extended operation, and (3) evaluated

other transients not listed in the LRA tables in accordance with 10 CFR 54.21(c)(1)(i) and

10 CFR 54.21(c)(1)(ii) in a manner that is consistent with the review procedures in SRP-LR 

Sections 4.6.2.1.1.1 and 4.6.2.1.1.2, respectively. Thus, the staff’s concern described in 

RAI 4.6.1-1 is resolved.

Based on its review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of cumulative fatigue damage on the intended functions 

of Class 1 and non-Class 1 components for the primary containment liner, Class MC 
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components, and penetrations will be adequately managed for the period of extended operation. 

Additionally, it meets the acceptance criteria in SRP-LR Section 4.6.2.1.1.3 because the Fatigue 

Monitoring program is a preventive program that will ensure that the CUF is not permitted to 

exceed the design limit of 1.0 for these components by analyzing transients and by initiating 

corrective action before exceeding the transient limits.

The staff also reviewed the applicant’s TLAA for the primary containment non-Class 1 

penetrations that are based on transient cycles not listed in LRA Tables 4.3.1-1 and 4.3.1-2 and 

the corresponding disposition of 10 CFR 54.21(c)(1)(i), consistent with the review procedures in 

SRP-LR Section 4.6.3.1.1.1, which state that the number of assumed transients used in the 

existing CUF calculations for the current operating term needs to be compared to the 

extrapolation to 60 years of operation of the number of operating transients experienced to date, 

and this comparison must confirm that the number of transients in the existing analyses will not 

be exceeded during the period of extended operation. Based on its review, the staff finds that 

the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the fatigue analyses for 

the primary containment non-Class 1 penetrations that are based on transients cycles not listed 

in LRA Tables 4.3.1-1 and 4.3.1-2 will remain valid for the period of extended operation. 

Additionally, it meets the acceptance criteria in SRP-LR Section 4.6.2.1.1.1 because the number 

of assumed cyclic loads will not be exceeded during the period of extended operation, 

considering the very low CUF values and high number of allowable cycles provided by the 

analyses for these components.

The staff also reviewed the applicant’s TLAA for the primary containment non-Class 1 

penetration M-76 and the corresponding disposition of 10 CFR 54.21(c)(1)(ii), consistent with 

the review procedures in SRP-LR Section 4.6.3.1.1.2, which state that the revised CUF 

calculations based on the projected number of assumed cyclic loads are reviewed to ensure 

that the CUF remains less than 1.0 at the end of the period of extended operation. Based on its 

review, the staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that 

the fatigue analysis for the primary containment non-Class 1 penetration M-76 has been 

projected to the end of the period of extended operation. Additionally, it meets the acceptance 

criteria in SRP-LR Section 4.6.2.1.1.2 because the revised analysis shows that the 60-year CUF 

value of 0.00235 does not exceed 1.0, as required by the ASME Code, for the period of 

extended operation.

4.6.1.3 UFSAR Supplement

LRA Section A.4.6.1, as amended, provides the UFSAR supplement summarizing the 

applicant’s TLAAs for primary containment liner, Class MC components, and penetrations that 

were designed and analyzed for transient cycles predicted for 40 years. The staff reviewed LRA 

Section A.4.6.1 consistent with the review procedures in SRP-LR Section 4.6.3.2, which state

that the staff verifies that the applicant has provided a UFSAR supplement that includes

information equivalent to that in SRP-LR Table 4.6-1 and a summary description of the 

evaluation of each fatigue analysis TLAA.

Based on its review of the UFSAR supplement, as amended by letter dated September 28, 2015, 

the staff finds that it meets the acceptance criteria in SRP-LR Section 4.6.2.2 and, therefore, is

acceptable. Additionally, the staff determines that the applicant provided an adequate summary 

description of its actions to address primary containment liner, Class MC components, and 

penetrations fatigue analyses, as required by 10 CFR 54.21(d).
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4.6.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of cumulative fatigue 

damage on the intended functions of Class 1 and non-Class 1 components from the primary 

containment liner, Class MC components, and penetrations will be adequately managed by the 

Fatigue Monitoring program (LRA Section B.3.1.1) for the period of extended operation. The 

staff also concludes that the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that 

the fatigue analyses for the primary containment non-Class 1 penetrations that are based on 

transients cycles not listed in the LRA Tables 4.3.1-1 and 4.3.1-2 remain valid for the period of 

extended operation. The staff also concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that the fatigue analysis for the primary containment non-Class 1 

penetration M-76 has been projected to the end of the period of extended operation. The staff 

also concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d).

4.6.2 Primary Containment Refueling Bellows Fatigue Analysis

4.6.2.1 Summary of Technical Information in the Application

LRA Section 4.6.2 describes the applicant’s TLAA for the primary containment refueling bellows 

that were designed and analyzed for transient cycles predicted for 40 years of operation. The 

applicant stated that the metal refueling bellows provides a flexible seal to prevent water 

leakage from the LSCS, Units 1 and 2, reactor cavity refueling pool into the drywell during 

refueling operations. The applicant further stated that the refueling bellows were analyzed for 

200 startup/shutdown cycles, 200 normal operation cycles, 123 refueling (boltup/unbolt) cycles, 

1 normal seismic event, and 1 refueling seismic event with a total CUF of 0.158 for the refueling 

bellows. Because the analyzed 60-year transient cycle projections (LRA Tables 4.3.1-1 

and 4.3.1-2) will not exceed the numbers of cycles analyzed for the refueling bellows, the 

applicant concluded that the analysis remains valid through the period of extended operation.

The applicant dispositioned the TLAA for the metal refueling bellows in accordance with 

10 CFR 54.21(c)(1)(i) to demonstrate that the analysis remains valid for the period of extended 

operation.

4.6.2.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the primary containment refueling bellows and the 

corresponding disposition of 10 CFR 54.21(c)(1)(i), consistent with the review procedures in 

SRP-LR Section 4.6.3.1.1.1, which state that the number of assumed transients used in the 

existing CUF calculations for the current operating term needs to be compared to the 

extrapolation to 60 years of operation of the number of operating transients experienced to date, 

and this comparison must confirm that the number of transients in the existing analyses will not 

be exceeded during the period of extended operation.

In its review, the staff noted that both units have projected 123 boltup/unbolt cycles, which do 

not exceed the 123 refueling (boltup/unbolt) cycles used in the transient analysis for the 

refueling bellows. The staff also noted that the other projected 60-year cycles associated with 

the refueling bellows do not exceed the analyzed cycles.
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Based on its review, the staff finds that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that the fatigue analysis for the primary containment refueling bellows 

remains valid for the period of extended operation. Additionally, it meets the acceptance criteria 

in SRP-LR Section 4.6.2.1.1.1 because the number of assumed transients cycles in the existing 

fatigue analysis of the refueling bellows will not be exceeded during the period of extended 

operation.

4.6.2.3 UFSAR Supplement

LRA Section A.4.6.2 provides the UFSAR supplement summarizing the TLAA for cumulative 

fatigue analysis of the primary containment refueling bellows. The staff reviewed LRA 

Section A.4.6.2, consistent with the review procedures in SRP-LR Section 4.6.3.2, which state

that the staff verifies that the applicant has provided a UFSAR supplement with information 

equivalent to that in SRP-LR Table 4.6–1, and that includes a summary description of the 

evaluation of each fatigue analysis TLAA.

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SR-LR Section 4.6.2.2 and, therefore, is acceptable. Additionally, the staff determines 

that the applicant provided an adequate summary description of its actions to address the TLAA 

for cumulative fatigue analysis of the primary containment refueling bellows, as required by 

10 CFR 54.21(d).

4.6.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the analysis for the primary containment 

refueling bellows remains valid for the period of extended operation. The staff also concludes 

that the UFSAR supplement contains an appropriate summary description of the TLAA 

evaluation, as required by 10 CFR 54.21(d).

4.6.3 Primary Containment Downcomer Vents Fatigue Analysis

4.6.3.1 Summary of Technical Information in the Application

LRA Section 4.6.3 describes the applicant’s TLAA for the primary containment downcomer 

vents that were designed and analyzed for transient cycles predicted for 40 years of operation. 

The applicant stated that the 98 primary containment downcomer vent pipes transport steam 

and non-condensable gases to the suppression pool from the reactor and the drywell during 

LOCA conditions. The applicant also stated that there are three locations of discontinuity on the 

downcomers that govern for fatigue: (1) drywell floor anchor, (2) upper bracing attachment 

location, and (3) lower bracing attachment location. The applicant further stated that combined 

stresses and corresponding equivalent stress cycles were analyzed for a 40-year plant life to 

obtain the fatigue usage factors by considering the following three subevents: (1) one SBA 

LOCA (producing chugging loads) with a safe-shutdown earthquake (SSE), (2) five isolation 

events (cyclic MSRV actuation), each with one coincident operating basis earthquake (OBE),

and (3) remaining MSRV actuations (including 163 isolation events). LRA Tables 4.3.1-1 

and 4.3.1-2 show the applicant’s 60-year transient cycle projections for the MSRV actuations, 

OBE events, and SSE events for LSCS, Units 1 and 2, respectively. Because the analyzed 

60-year transient cycle projections will not exceed the number of transient cycles analyzed for 

the primary containment downcomers vents, the applicant concluded that the analysis remains 

valid through the period of extended operation.
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The applicant dispositioned the TLAA for the primary containment downcomer vent pipes in 

accordance with 10 CFR 54.21(c)(1)(i) to demonstrate that the analysis remains valid for the 

period of extended operation.

4.6.3.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the primary containment downcomer vent pipes and 

the corresponding disposition of 10 CFR 54.21(c)(1)(i), consistent with the review procedures in 

SRP-LR Section 4.6.3.1.1.1, which state that the number of assumed transients used in the 

existing CUF calculations for the current operating term needs to be compared to the 

extrapolation to 60 years of operation of the number of operating transients experienced to date, 

and this comparison must confirm that the number of transients in the existing analyses will not 

be exceeded during the period of extended operation.

In its review, the staff noted that the 60-year projected number of transient cycles for MSRV 

actuations from LRA Tables 4.3.1-1 and 4.3.1-2 does not exceed the 2,788 cycles evaluated by 

the current transient analysis. The staff also noted that the 60-year projected OBE and SSE 

events do not exceed the analyzed cycle of one event for the primary containment downcomer 

vents for either unit.

Based on its review, the staff finds that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that the analysis for the primary containment downcomer vent pipes 

remains valid for the period of extended operation. Additionally, it meets the acceptance criteria 

in SRP-LR Section 4.6.2.1.1.1 because the number of assumed transient cycles in the existing 

fatigue analysis of the downcomer vents will not be exceeded during the period of extended 

operation.

4.6.3.3 UFSAR Supplement

LRA Section A.4.6.3 provides the UFSAR supplement summarizing the TLAA for cumulative 

fatigue analysis of the primary containment downcomer vents and bracing. The staff reviewed 

LRA Section A.4.6.3 consistent with the review procedures in SRP-LR Section 4.6.3.2, which 

state that the staff verifies that the applicant has provided an FSAR supplement with information 

equivalent to that in SRP-LR Table 4.6-1 and that includes a summary description of the 

evaluation of each fatigue analysis TLAA.

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SRP-LR Section 4.6.2.2 and, therefore, is acceptable. Additionally, the staff 

determines that the applicant provided an adequate summary description of its actions to 

address the TLAA for cumulative fatigue analysis of the primary containment downcomer vents 

and bracing, as required by 10 CFR 54.21(d).

4.6.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the analysis for the primary containment 

downcomer vents remains valid for the period of extended operation. The staff also concludes 

that the UFSAR supplement contains an appropriate summary description of the TLAA 

evaluation, as required by 10 CFR 54.21(d).
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4.7 Other Plant-Specific Time-Limited Aging Analyses

LRA Section 4.7 summarizes the evaluation of the following plant-specific TLAAs:

• LRA Section 4.7.1, Reactor Building Crane Cyclic Loading Analysis

• LRA Section 4.7.2, Main Steam Line Flow Restrictors Erosion Analysis

4.7.1 Reactor Building Crane Cyclic Loading Analysis

4.7.1.1 Summary of Technical Information in the Application

LRA Section 4.7.1 describes the applicant’s TLAA for the reactor building crane load cycles. 

The LRA states that the reactor building crane serves both units at LSCS and was designed to 

meet the fatigue requirements of the ASME NOG-1-2004 and Crane Manufacturers Association 

of America (CMAA) Specification 70. The reactor building crane is a Class A crane that can be 

considered as experiencing “irregular occasional use followed by long idle periods.” The LRA

also states that the CMAA design allows for load cycles between 20,000 and 100,000 and has a 

design capacity of 125 tons. The LRA states that load cycles that are less than 50 percent of 

the design capacity of 125 tons (i.e., 62.5 tons) are considered to result in minimal fatigue of the 

crane; therefore, only lifts equal to or greater than 50 tons were evaluated. The LRA further 

states that the evaluation of the reactor building crane load cycles TLAA included (a) a review of 

the existing design basis to determine the number of load cycles considered in the 40-year 

design life of the crane, (b) the development of a 60-year projection for the crane load cycles, 

and (c) a comparison of the 60-year load cycle projection to the 40-year design load cycles of 

the crane. The LRA further states that the 60-year projected number of crane load cycles is 

2,672 load cycles and this is less than 20 percent of the allowable design value of 20,000 load 

cycles.

The applicant dispositioned the TLAA for the reactor building crane in accordance with 

10 CFR 54.21(c)(1)(i) to demonstrate that the analysis remains valid for the period of extended 

operation.

4.7.1.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the reactor building crane and the corresponding 

disposition that the analysis remains valid for the period of extended operation in accordance 

with 10 CFR 54.21(c)(1)(i), consistent with the review procedures in SRP-LR Section 4.7.3.1.1, 

which state that existing analyses should be shown to be bounding for the period of extended 

operation. The SRP-LR also states that the applicant should show that conditions and 

assumptions used in the analysis already address the relevant aging effects for the period of 

extended operation and that acceptance criteria are maintained to provide reasonable 

assurance that the intended functions are maintained for renewal.

The staff reviewed LRA Section 4.7.1, ASME NOG-1-2004, UFSAR Section 9.1.4, UFSAR 

Appendix O, and CMAA Specification 70 and finds that the carbon steel reactor building crane is 

designed to meet the fatigue requirements for a Class A, “standby service” or “infrequent use,”

crane. The staff noted that, for the reactor building crane fatigue load cycle counting, the 

applicant only counted loads that lift greater than 50 tons (i.e., loads that are greater than 

40 percent of the design capacity of 125 tons). The staff reviewed the applicant’s UFSAR and 

noted that UFSAR Section 9.1.4 references a letter from Commonwealth Edison Company 

(CECo) to the NRC, dated October 19, 1982. The staff notes that CECo was the former 
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licensee of LSCS and that Exelon is the current licensee and applicant of LSCS LRA. The letter 

provided information to the NRC on how the guidelines in Section 5.1.1 of NUREG-0612, 

“Control of Heavy Loads at Nuclear Power Plants: Resolution of Generic Technical Activity 

A-36,” dated July 1980, have been satisfied for LSCS. The letter stated, in part, that “fatigue 

failure was considered in the design. Assuming one refueling per year for a design plant life of 

40 years gives an estimated number of lifts greater than 50 [percent] of crane capacity. 

20 lifts/outage x 40 outages x 2 units = 1600 which is less than the 20,000 allowed in 

CMAA–70.” UFSAR Section 9.1.4 states that the staff’s evaluation provided in Supplement 

No. 5 to NUREG-0519, “Safety Evaluation Report Related to the Operation of LaSalle County 

Station, Units 1 and 2,” dated August 1983, concludes that the guidelines in NUREG-0612,

Section 5.1.1, have been satisfied for LSCS.

The staff noted that the letter dated October 19, 1982, is referenced in NUREG-0519, 

Supplement No 5; therefore, this information was considered by the staff in reaching its 

conclusion therein that LSCS meets the guidance in NUREG-0612, Section 5.1.1. During its 

review, the staff confirmed that (1) the staff previously found it acceptable to take into 

consideration, for fatigue cycle counting, only the crane lifts that are greater than 50 percent of 

crane capacity and (2) NUREG-0519 concludes that LSCS meets the guidance in

NUREG-0612, Section 5.1.1. The staff also reviewed stress versus number of cycles (S-N) 

curves in the American Society for Metals Atlas of Fatigue Curves, dated 1986, and noted that, 

for ferrous metals, when the applied load/stress is below 50 percent of the fracture 

strength/stress, the fatigue life (i.e., number of cycles) of steel components increases 

significantly and an “infinite-life region” in the S-N curve is reached in which an infinite number 

of cycles can be applied without fatigue fracture. The staff finds the applicant’s determination to 

not consider lifting loads less than 50 tons (i.e., loads that are less than 40 percent of the design 

capacity of 125 tons) for the reactor building crane fatigue cycle counting acceptable because 

this is consistent with LSCS CLB for the reactor building crane fatigue load cycle counting.

LRA Table 4.7.1-1 shows the 60-year projected total number of loading cycles based on the 

existing 40-year design basis. The 60-year total load cycles is projected to be 2,672 load 

cycles, which is less than 20 percent of the minimum design range of 20,000 to 100,000 load 

cycles.

Accordingly, the staff finds that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that the analysis for the reactor building crane remains valid for the 

period of extended operation. Additionally, it meets the acceptance criteria in SRP-LR 

Section 4.7.2.1 because the applicant’s 60-year total load cycle projection demonstrated that 

the analysis remains valid for the period of extended operation.

4.7.1.3 UFSAR Supplement

LRA Section A.4.7.1 provides the UFSAR supplement summarizing the reactor building crane 

load cycles analysis. The staff reviewed LRA Section A.4.7.1, consistent with the review 

procedures in SRP-LR Section 4.7.3.2, which state that the applicant has to provide information 

to be included in the UFSAR supplement that includes a summary description of the evaluation 

of each TLAA. The SRP-LR also states that each summary description is reviewed to verify that 

it is appropriate such that later changes can be controlled by 10 CFR 50.59, “Changes, Tests 

and Experiments,” and that the description should contain information that the TLAAs have 

been dispositioned for the period of extended operation.
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Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2 and, therefore, is acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the reactor 

building crane load cycles analysis, as required by 10 CFR 54.21(d).

4.7.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the analysis for the reactor building crane 

load cycles remains valid for the period of extended operation. The staff also concludes that the 

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.7.2 Main Steam Line Flow Restrictors Erosion Analysis

4.7.2.1 Summary of Technical Information in the Application

LRA Section 4.7.2 describes the applicant’s TLAA for the erosion of the main steam line flow 

restrictors. The LRA describes the restrictor assemblies as consisting of stainless steel 

verturi-type nozzles welded into the main steam line piping. The LRA refers to UFSAR 

Section 5.4.4, which indicates that very slow erosion of the venturi occurs with time and that the 

resulting slight enlargement has no safety significance. UFSAR Section 5.4.4 states that 

stainless steel was selected for the flow restrictor material because of its excellent resistance to 

erosion-corrosion in a high-velocity steam atmosphere. Flow velocities in the venturi range from 

150 ft/sec at the inlet to 600 ft/sec in the throat. UFSAR Section 5.4.4 also states that the 

material’s resistance to corrosion has been substantiated by turbine inspections at Dresden

Nuclear Power Station, Unit 1, where no noticeable effects from erosion were found on the 

stainless steel nozzle partitions with inlet velocities of 300 ft/sec and exit velocities from 600 to 

900 ft/sec. The UFSAR Section 5.4.4 states that even if erosion rates are as high as 0.004-inch

per year, after 40 years of operation, the increase in restrictor choked flow rate would be no 

more than 5 percent, and a 5 percent increase in the radiological dose calculated for the main 

steam line break accident is not significant.

The LRA evaluated the TLAA by stating that, as discussed in UFSAR Section 15.6.4 and 

UFSAR Table 15.6-8, the radiological consequences of a main steam line break would result in 

a whole body dose at the exclusion area boundary of 0.0354 rem, which is well below the limit 

of 25 rem in 10 CFR Part 100, “Reactor Site Criteria.” The LRA stated that, even if the choked 

flow rate is increased an additional 5 percent (for a total increase of 10 percent) to account for 

the additional 20 years of service, the increase in dose consequences is negligible relative to 

the 10 CFR Part 100 limits.

The applicant dispositioned the TLAA for the erosion of the main steam line flow restrictors in 

accordance with 10 CFR 54.21(c)(1)(ii), that the analysis has been projected through the period 

of extended operation with acceptable results.

4.7.2.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the erosion of the main steam line flow restrictors 

and the corresponding disposition in accordance with 10 CFR 54.21(c)(1)(ii), consistent with the 

review procedures in SRP-LR Section 4.7.3.1.2. These procedures state that the staff is to 

review the results of the applicant’s revised analysis to verify that the evaluation period has 
4-81

been extended such that the analysis is valid for the period of extended operation. SRP-LR 

Section 4.7.3.1.2 also states that the applicant may recalculate the analysis using a 60-year 

period to show that the acceptance criteria continue to be satisfied for the period of extended 

operation.

The staff reviewed the UFSAR and confirmed that Section 5.4.4 states that calculations have 

shown that an erosion rate of 0.004 inch per year would result in a maximum increase in 

restrictor choked flow rate of 5 percent after 40 years of operation. The staff also reviewed 

UFSAR Section 15.6.4 and UFSAR Table 15.6-8 and confirmed that the original design basis 

analysis performed for 40 years of operation determined that a main steam line break would 

result in a whole body dose at the exclusion area boundary of 0.0354 rem. The staff reviewed 

the methodology used by the applicant to project the analysis to the end of the period of 

extended operation and finds it to be acceptable because doubling the effects of the current 

operating period bounds the effects for the period of extended operation and because the 

resulting increase in calculated exposures continue to be a small fraction of 10 CFR Part 100 

guidelines.

Based on its review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that the analysis for the erosion of the main steam line flow restrictors 

has been projected to the end of the period of extended operation. Additionally, this meets the 

acceptance criteria in SRP-LR Section 4.7.2.1.

4.7.2.3 UFSAR Supplement

LRA Section A.4.7.2 provides the UFSAR supplement summarizing the erosion of the main 

steam line flow restrictors. The staff reviewed the LRA Section A.4.7.2, consistent with the 

review procedures in SRP-LR Section 4.7.3.2, which state that the information to be included in 

the UFSAR supplement includes a summary description of the evaluation of each TLAA. Based 

on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.3.2 and, therefore, is acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the main steam 

line flow restrictor erosion analysis, as required by 10 CFR 54.21(d).

4.7.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the analysis for erosion of the main 

steam line flow restrictors has been projected to the end of the period of extended operation. 

The staff also concludes that the UFSAR supplement contains an appropriate summary 

description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.8 Conclusion for TLAAs

The staff reviewed the information in LRA Section 4, “Time-Limited Aging Analyses.” On the 

basis of its review, the staff concludes that the applicant has provided a sufficient list of TLAAs, 

as defined in 10 CFR 54.3, and that the applicant has demonstrated that (1) the TLAAs will 

remain valid for the period of extended operation, as required by 10 CFR 54.21(c)(1)(i), (2) the 

TLAAs have been projected to the end of the period of extended operation, as required by

10 CFR 54.21(c)(1)(ii), or (3) the effects of aging on intended functions will be adequately 

managed for the period of extended operation, as required by 10 CFR 54.21(c)(1)(iii). The staff 

also reviewed the UFSAR supplement for the TLAAs and finds that the supplement contains 
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descriptions of the TLAAs sufficient to satisfy the requirements of 10 CFR 54.21(d). In addition, 

the staff concludes, as required by 10 CFR 54.21(c)(2), that no plant-specific, TLAA-based 

exemptions are in effect.

With regard to these matters, the staff concludes that there is reasonable assurance that the 

activities authorized by the renewed licenses will continue to be conducted in accordance with 

the CLB and that any changes made to the CLB to comply with 10 CFR 54.29(a) are in 

accordance with the Atomic Energy Act of 1954, as amended (42 U.S.C. 2011 et seq.), and 

NRC regulations.
5-1

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR

SAFEGUARDS

In accordance with Title 10 of the Code of Federal Regulations Part 54, “Requirements for 

Renewal of Operating Licenses for Nuclear Power Plants,” the Advisory Committee on Reactor 

Safeguards (ACRS) reviewed the license renewal application (LRA) for LaSalle County Station, 

Units 1 and 2 (LSCS). The U.S. Nuclear Regulatory Commission (NRC) staff (the staff) 

presented its safety evaluation report (SER) with open items to the ACRS Subcommittee on 

Plant License Renewal in a public meeting on April 19, 2016. The staff closed the open items 

based on additional information provided by Exelon Generation Company, LLC (Exelon or the 

applicant), and reviewed comments on the SER with open items from the applicant. The staff 

issued the final SER on June 2, 2016. The staff and the applicant met with the ACRS full 

committee on July 6, 2016, to discuss the closure of the open items and other issues associated 

with the review of the LRA.

During the 635th meeting of the ACRS held July 6-8, 2015, the ACRS completed its review of 

the LSCS LRA and the staff’s SER. The ACRS documented its findings in a letter to the 

Commission dated July 18, 2016. A copy of this letter is provided in this section.
UNITED STATES

NUCLEAR REGULATORY COMMISSION

ADVISORY COMMITTEE ON REACTOR SAFEGUARDS

WASHINGTON, DC 20555 - 0001

July 18, 2016

The Honorable Stephen G. Burns

Chairman

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

SUBJECT: REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL 

APPLICATION OF THE LASALLE COUNTY STATION, UNITS 1 AND 2

Dear Chairman Burns: 

During the 635th meeting of the Advisory Committee on Reactor Safeguards (ACRS), July 6 - 8, 

2016, we completed our review of the license renewal application for the LaSalle County 

Station, Units 1 and 2 (LaSalle) and the final safety evaluation report (SER) prepared by the 

NRC staff. Our Subcommittee on Plant License Renewal reviewed this matter during a meeting 

on April 19, 2016. During these reviews, we had the benefit of discussions with representatives 

of the NRC staff and the Exelon Generation Company, LLC (Exelon or the applicant). We also 

had the benefit of the referenced documents. This report fulfills the requirement of 10 CFR 

54.25 that the ACRS review and report on all license renewal applications.

CONCLUSION AND RECOMMENDATION

1. The programs established and committed to by Exelon to manage age-related

degradation provide reasonable assurance that LaSalle can be operated in accordance

with its current licensing bases for the period of extended operation without undue risk to

the health and safety of the public.

2. Exelon’s application for renewal of the operating licenses for LaSalle should be

approved.

BACKGROUND

LaSalle is located approximately 55 miles southwest of Chicago, Illinois. Units 1 and 2 are of a 

boiling water reactor (BWR) Type 5 (BWR/5) design. Each primary containment is a Mark II 

type, safety-related seismic Category I structure consisting of a steel dome head and posttensioned concrete wall standing on a base mat of conventionally reinforced concrete. General 

Electric provided the nuclear steam supply system, and Sargent & Lundy designed and 

constructed the balance of the plant. Each unit has a licensed power output of 3,546 

megawatts thermal, with a gross electrical output of approximately 1,207 megawatts. The NRC 

issued the construction permits (CPRR-99 and CPRR-100, respectively) for Units 1 and 2 on 

September 7, 1973. The NRC issued the operating licenses for Unit 1 and Unit 2 on April 17, 

1982, and December 16, 1983, respectively. 

5-2
2 

In this application, Exelon requests renewal of the operating licenses (Facility Operating License 

Nos. NPF-11 and NPF-18) for a period of 20 years beyond the current expiration date of April 

17, 2022, for Unit 1, and December 16, 2023, for Unit 2. 

DISCUSSION 

In its final SER, dated June 2016, the staff documented its review of the license renewal 

application and other information submitted by the applicant and obtained through staff audits

and inspections at the plant sites. The staff reviewed the completeness of the identification of 

structures, systems, and components (SSCs) that are within the scope of license renewal; the 

integrated plant assessment process; the identification of plausible aging mechanisms 

associated with passive, long-lived components; the adequacy of the Aging Management 

Programs (AMPs); and identification and assessment of Time-Limited Aging Analyses (TLAAs) 

requiring review.

Exelon’s LaSalle license renewal application identified the SSCs that fall within the scope of 

license renewal. The application is largely consistent with the Generic Aging Lessons Learned 

(GALL) Report (NUREG-1801). Deviations and exceptions are documented and justified. 

Exelon will implement 46 AMPs for license renewal, comprised of 35 existing programs and 11 

new programs. Nineteen of the 46 AMPs are consistent with the GALL Report without 

enhancements or exceptions. Nineteen AMPs are consistent with enhancements. Three AMPs 

are consistent with exceptions. Three AMPs are consistent with enhancements and exceptions. 

Two AMPs, Service Level III and Service Level III Augmented Coatings Monitoring and

Maintenance Program, and Unit 2 Inspection of The American Society of Mechanical Engineers 

(ASME) Code Class 1 Small-Bore Piping Program, are plant-specific. 

The license renewal application includes six programs with exceptions to the GALL Report. We 

reviewed these programs (Flow-Accelerated Corrosion, Reactor Vessel Surveillance, 

Compressed Air Monitoring, Fire Water System, Reactor Head Closure Stud Bolting, and Water 

Chemistry). We conclude that the six GALL programs with exceptions are acceptable. 

The staff conducted license renewal audits and performed license renewal inspections at 

LaSalle. The audits verified the adequacy of the scoping and screening methodology for AMPs, 

the appropriateness of the aging management review, and the acceptability of the TLAAs. The 

inspection verified that the license renewal requirements are implemented appropriately. Both 

the inspection, and the report of that inspection, are thorough. Based on the audits, the 

inspection, and the staff reviews related to this license renewal application, the staff concluded 

in the final SER that the proposed activities will manage the effects of aging of SSCs identified 

in the application and that the intended functions of these SSCs will be maintained during the 

period of extended operation. The staff concluded that Exelon has demonstrated that the effects 

of aging at LaSalle will be adequately managed so that the intended function(s) will be 

maintained consistent with the current licensing basis for the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Two open items were resolved between our subcommittee meeting on April 19, 2016, and our 

final review on July 6, 2016. The open items pertained to 1) enhanced visual testing 

examination coverage and 2) limited volumetric examination coverage. Resolution of the open 

items is as follows. 

5-3
3 

EVT-1 Examination Coverage - BWR Vessel ID Attachment Welds Aging Management 

Program

This item addresses changes to the BWR Vessel Internals Program (BWRVIP) guidance for 

EVT-1 viewing angle limitation that reduced effective examination coverage. Coverage 

requirements were not specified. The staff’s concern was the program’s ability to credit EVT-1s 

with 0% coverage; therefore, the staff raised the question of program adequacy. Exelon 

provided information to the NRC on February 25, 2016, in response to Request for Additional 

Information B.2.1.4-1 that 1) revised the procedure to eliminate the possibility that EVT-1 weld 

exam coverage of 0% could be acceptable and 2) communicated that visual inspections are 

performed of entire accessible Vessel ID attachment welds by a certified nondestructive 

examination examiner. EVT-1 examination coverage is maximized, consistent with BWRVIP-48-

A and BWRVIP-03 guidance. 

Limited Volumetric Exam Coverage – BWR Stress Corrosion Cracking Aging 

Management Program

This item addresses examination coverage for augmented weld inspections. The staff was 

concerned that program effectiveness could not be assured without documented bases for 

crediting limited weld inspections. Exelon provided information to the NRC on February 25, 

2016, stating that 90% examination coverage is considered the minimum acceptable 

examination coverage, without evaluation, during the period of extended operation. If

examination coverage is less than 90%, procedures require action to maximize the extent of 

examination coverage. In addition, if the examinations with less than 90% coverage are required 

to meet ASME Code Section XI requirements, a relief request is required. Exelon changed 

procedures for examinations that are required to meet the AMP, but not to meet ASME code

requirements. The new procedures require an engineering technical evaluation equivalent to a 

relief request. 

We agree with the staff that there are no issues related to the matters described in 10 CFR 

54.29(a) (1) and (a) (2) that preclude renewal of the operating licenses for LaSalle. The 

programs established and committed to by Exelon provide reasonable assurance that LaSalle 

can be operated in accordance with its current licensing basis for the period of extended 

operation without undue risk to the health and safety of the public. The Exelon application for 

renewal of the operating licenses for LaSalle, Units 1 and 2 should be approved.

Sincerely,

 /RA/

Dennis C. Bley

Chairman

5-4
3 

REFERENCES

1. Exelon Generation Company, LLC, LaSalle County Station, Units 1 and 2, “Application

for Renewed Operating Licenses,” December 9, 2014 (ML14343A840).

2. U.S. Nuclear Regulatory Commission, “Safety Evaluation Report Related to the License

Renewal of LaSalle County Station, Units 1 and 2,” June 2016 (ML16126A503).

3. U.S. Nuclear Regulatory Commission, “Safety Evaluation Report with Open items

Related to the License Renewal of LaSalle County Station, Units 1 and 2,” February

2016 (ML16053A439).

4. U.S. Nuclear Regulatory Commission, NUREG 1801, “Generic Aging Lessons Learned

(GALL) Report,” Revision 2, December 2010 (ML103490041).

5. U.S. Nuclear Regulatory Commission, “Aging Management Programs Audit Report

Regarding LaSalle County Station, Units 1 and 2 (TAC NOS. MF5347 and MF5346),”

September 22, 2015 (ML15196A115).

6. U.S. Nuclear Regulatory Commission, “Scoping and Screening Methodology Audit

Report Regarding LaSalle County Station, Units 1 and 2 (TAC NOS. MF5347 and

MF5346),” May 8, 2015 (ML15104A782).

7. U.S. Nuclear Regulatory Commission, “LaSalle County Station, Units 1 and 2 License

Renewal Scoping, Screening, and Aging Management Inspection Report

05000373/2015008; 05000374/2015008,” November 18, 2015 (ML15323A064).

8. U.S. Nuclear Regulatory Commission, NUREG-1800, “Standard Review Plan for Review

of License Renewal Applications for Nuclear Power Plants,” Revision 2, December 2010

(ML103490036).

9. U.S. Nuclear Regulatory Commission, Regulatory Guide 1.188, “Standard Format and

Content for Applications to Renew Nuclear Power Plant Operating Licenses,” Revision 1,

September 2005 (ML082950585).

5-5

6-1

CONCLUSION

The U.S. Nuclear Regulatory Commission (NRC) staff (the staff) reviewed the license renewal 

application (LRA) for LaSalle County Station, Units 1 and 2 (LSCS), in accordance with NRC 

regulations and NUREG-1800, Revision 2, “Standard Review Plan for Review of License 

Renewal Applications for Nuclear Power Plants,” dated December 2010. Title 10 of the Code of 

Federal Regulations (10 CFR) 54.29, “Standards for Issuance of a Renewed License,” sets the 

standards for issuance of a renewed license.

On the basis of its review of the LRA, the staff determines that the requirements of 

10 CFR 54.29(a) have been met.

The staff noted that any requirements of 10 CFR Part 51, “Environmental Protection 

Regulations for Domestic Licensing and Related Regulatory Functions,” Subpart A, “National 

Environmental Policy Act – Regulations Implementing Section 102(2),” will be documented in a 

plant-specific supplement to NUREG-1437, “Generic Environmental Impact Statement for 

License Renewal of Nuclear Power Plants, Supplement 57, Regarding LaSalle County Station, 

Units 1 and 2.”

LICENSE RENEWAL COMMITMENTS

A-1

A. License Renewal Commitments

During the review of the LaSalle County Station, Units 1 and 2 (LSCS), license renewal 

application (LRA) by the staff of the United States (U.S.) Nuclear Regulatory Commission (NRC) 

(the staff), Exelon Generation Company, LLC (Exelon or the applicant), made commitments 

related to aging management programs (AMPs) and time limited aging analyses (TLAAs) to 

manage aging effects for structures and components. The following table lists these 

commitments, as of June 8, 2016, along with the implementation schedules and sources for 

each commitment. The period of extended operation starts on April 17, 2022, for LSCS, Unit 1, 

and on December 16, 2023, for LSCS, Unit 2.
A-2

Table A.1-1 LaSalle County Station, Units 1 and 2, License Renewal Commitments

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

1 ASME Section XI 

Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD

Existing program is credited. Ongoing 

2 Water Chemistry Existing program is credited. Ongoing 

3 Reactor Head 

Closure Stud 

Bolting

Existing program is credited. Ongoing 

4 BWR Vessel ID 

Attachment 

Welds

Existing program is credited. Ongoing 

5 BWR Feedwater 

Nozzle

Existing program is credited. Ongoing 

6 BWR Control Rod 

Drive Return Line 

Nozzle

Existing program is credited. Ongoing 

7 BWR Stress 

Corrosion 

Cracking

Existing program is credited. Ongoing 

8 BWR 

Penetrations

Existing program is credited. Ongoing 
A-3

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

9 BWR Vessel 

Internals

BWR Vessel Internals is an existing program that will be enhanced to:

1. Perform an assessment of the susceptibility of reactor vessel 

internal components fabricated from CASS to loss of fracture 

toughness due to thermal aging embrittlement. If material 

properties cannot be determined to perform the screening, 

they will be assumed susceptible to thermal aging for the 

purposes of determining program examination requirements.

2. Perform an assessment of the susceptibility of reactor vessel 

internal components fabricated from CASS to loss of fracture 

toughness due to neutron irradiation embrittlement.

3. Specify the required periodic inspection of CASS components 

determined to be susceptible to loss of fracture toughness due 

to thermal aging and neutron irradiation embrittlement. The 

initial inspections will be performed either prior to or within five 

years after entering the period of extended operation.

4. Install core plate wedges no later than six months prior to the 

period of extended operation, or before the end of the last 

refueling outage prior to the period of extended operation, 

whichever occurs later; or, submit an inspection plan for the 

core plate rim hold-down bolts with a supporting analysis for 

NRC approval at least 2 years prior to entering the period of 

extended operation.

Program to be enhanced no lat

six months prior to the period o

extended operation.

Additional schedule information 

identified in commitment.

10 Flow-Accelerated 

Corrosion

Existing program is credited. Ongoing 

11 Bolting Integrity Bolting Integrity is an existing program that will be enhanced to:

1. Provide guidance to ensure proper specification of bolting 

material, lubricant and sealants, storage, and installation 

torque or tension to prevent or mitigate degradation and failure 

of closure bolting for pressure-retaining bolted joints.

2. Prohibit the use of lubricants containing molybdenum disulfide 

on pressure-retaining bolted joints.

3. Minimize the use of high strength bolting (actual measured 

yield strength equal to or greater than 150 ksi) for pressureretaining bolted joints in portions of systems within the scope 

of the Bolting Integrity program. High strength bolting 

(regardless of code classification) will be monitored for 

Program to be enhanced no lat

six months prior to the period o

extended operation.

Additional schedule information 

identified in commitment.
A-4

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

cracking in accordance with ASME Section XI, Table IWB2500-1, Examination Category B-G-1.

4. Perform inspection of submerged bolting for the emergency 

core cooling systems (ECCS) and reactor core isolation 

cooling (RCIC) system suction strainers in the suppression 

pool for loss of material and loss of preload during each ISI 

inspection interval.

5. Perform inspection of submerged bolting for the service water 

diver safety barriers and diesel fire pump suction screens for 

loss of material and loss of preload each refuel interval.

6. Perform inspection of submerged bolting for the Lake Screen 

House travelling screens framework for loss of material and 

loss of preload each refueling interval.
A-5

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

12 Open-Cycle 

Cooling Water 

System

Open-Cycle Cooling Water System is an existing program that will be 

enhanced to:

1. Perform a minimum of 10 microbiologically influenced 

corrosion (MIC) degradation inspections for aboveground 

piping in the Essential Cooling Water System every 24 months 

until the rate of MIC occurrences no longer meets the criteria 

for recurring internal corrosion. The selected inspection 

locations will be periodically reviewed to validate their 

relevance and usefulness and adjusted as appropriate. 

Evaluation of the inspection results will include; (1) a 

comparison to the nominal wall thickness or previous wall 

thickness measurements to determine rate of corrosion 

degradation; (2) a comparison to the design minimum 

allowable wall thickness to determine the acceptability of the 

component for continued use; and (3) a determination of reinspection interval. A portion of these inspection locations will 

be selected with process conditions similar (e. g. flow, 

temperature) to those in buried portions of the piping to 

provide sufficient understanding of the condition of the buried 

piping.

2. Perform a minimum of 10 MIC degradation inspections for in 

scope aboveground piping in the Nonessential Cooling Water 

System every 24 months until the rate of MIC occurrences no 

longer meets the criteria for recurring internal corrosion. The 

selected inspection locations will be periodically reviewed to 

validate their relevance and usefulness and adjusted as 

appropriate. Evaluation of the inspection results will include 

(1) a comparison to the nominal wall thickness or previous wall 

thickness measurements to determine rate of corrosion 

degradation; (2) a comparison to the design minimum 

allowable wall thickness to determine the acceptability of the 

component for continued use; and (3) a determination of reinspection interval. A portion of these inspection locations will 

be selected with process conditions similar (e. g. flow, 

temperature) to those in buried portions of the piping to 

provide sufficient understanding of the condition of the buried 

piping.

Program to be enhanced no lat

six months prior to the period o

extended operation.

Additional schedule information 

identified in commitment.
A-6

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

3. Select an inspection method that will provide indication of

suitable wall thickness to perform inspections on a 

representative sample of buried piping to supplement the 

aboveground piping inspection locations.

4. Perform visual inspections of the interior surface of buried 

portions of the Essential Cooling Water System and 

Nonessential Cooling Water System whenever the piping 

internal surface is made accessible due to maintenance and 

repair activities.

13 Closed Treated 

Water Systems

Closed Treated Water Systems is an existing program that will be 

enhanced to:

1. Perform condition monitoring, including periodic visual 

inspections and non-destructive examinations, to verify the 

effectiveness of water chemistry control to mitigate aging 

effects. A representative sample of piping and components 

will be selected based on likelihood of corrosion, stress 

corrosion cracking, or fouling, and inspected at an interval not 

to exceed once in 10 years during the period of extended 

operation. The selection of components to be inspected will 

focus on locations which are most susceptible to age-related 

degradation, where practical.

2. Monitor and trend drywell penetration cooling coil outlet 

temperatures monthly to ensure that adequate cooling is being 

provided to the concrete adjacent to the drywell penetrations.

Program to be enhanced no lat

six months prior to the period o

extended operation.

Additional schedule information 

identified in commitment.

14 Inspection of 

Overhead Heavy 

Load and Light 

Load (Related to 

Refueling) 

Handling 

Systems

Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems is an existing program that will be 

enhanced to:

1. Provide additional guidance to include inspection of structural

components, rails, and bolting for loss of material due to 

corrosion; rails for loss of material due to wear; and bolted 

connections for loss of preload.

Program to be enhanced no lat

six months prior to the period o

extended operation.
A-7

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

15 Compressed Air 

Monitoring

Compressed Air Monitoring is an existing program that will be enhanced 

to:

1. Inspect the internal surfaces of system filters, compressors, 

and after-coolers for signs of corrosion and corrosion products.

2. Perform analysis and trending of air quality monitoring results 

and visual inspection results.

3. Document deficiencies which are identified during visual 

inspections of the internal surfaces of system components in 

the corrective action program.

Program to be enhanced no lat

six months prior to the period o

extended operation.

16 Fire Protection Fire Protection is an existing program that will be enhanced to:

1. Perform periodic visual inspection of combustible liquid spill 

retaining curbs.

2. Perform periodic visual inspection for identification of corrosion 

that may lead to loss of material on the external surfaces of the 

low pressure carbon dioxide fire suppression systems.

3. Provide additional inspection guidance to identify aging effects 

as follows:

a. Fire barrier walls, ceilings, and floors degradation such as 

spalling, cracking, and loss of material for concrete.

b. Elastomeric fire barrier material degradation such as loss 

of material, shrinkage, separation from walls and 

components, increased hardness and loss of strength.

4. Provide additional inspection guidance to identify degradation 

of fire barrier penetration seals for aging effects such as loss of 

material, cracking, increased hardness, shrinkage, and loss of 

strength.

Program to be enhanced no lat

six months prior to the period o

extended operation.
A-8

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

17 Fire Water 

System

Fire Water System is an existing program that will be enhanced to:

1. Perform volumetric examinations at five locations on the 

carbon steel aboveground fire water piping susceptible to 

microbiologically induced corrosion (MIC) every year to identify 

loss of material. Additional locations will be examined if these 

volumetric examinations or plant operating experience identify 

significant degradation. For through-wall leaks and material 

loss greater than 50 percent of nominal wall, four additional 

locations will be examined. Where the identified material loss 

is 30 percent to 50 percent of nominal wall thickness and the 

calculated remaining life is less than two years, two additional 

locations will be examined.

2. Perform visual inspections, for loss of material and flow 

obstructions, of the accessible header piping and sparger 

external surfaces for the deluge systems located within filter 

plenums on a once per refueling cycle frequency. The visual 

inspection will include verification that the piping and spargers 

are in their proper position and that there are no obstructions 

to the desired spray patterns.

3. Perform internal visual inspections of sprinkler and deluge 

system piping to identify internal corrosion and obstructions to 

flow. If the presence of sufficient foreign organic or inorganic 

material to obstruct pipe or sprinklers is detected during pipe 

inspections, the material is removed and its source is 

determined and corrected where possible. Followup 

volumetric examinations will be performed if internal visual 

inspections detect age-related degradation in excess of what 

would be expected accounting for design, previous inspection 

experience, and inspection interval.

The internal visual inspections will consist of the following:

a. Wet pipe sprinkler systems – 50 percent of the wet pipe 

sprinkler systems in scope for license renewal will have 

visual internal inspections of piping performed every five 

years consistent with NFPA 25, 2011 Edition, 

Section 14.2.

Program to be enhanced no lat

six months prior to the period o

extended operation.

Inspections described in 

Enhancement 3.d.i and 3.d.ii, if 

required, will be completed eith

later than six months prior to th

PEO, or before the end of the l

refueling outage prior to the PE

whichever occurs later.

Additional schedule information 

identified in commitment.
A-9

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

b. Dry pipe sprinkler systems - Dry pipe sprinkler systems in 

scope for license renewal will have visual internal 

inspections of piping performed every five years 

consistent with NFPA 25, 2011 Edition, Section 14.2.

c. Deluge systems - Deluge systems in scope for license 

renewal, except for the charcoal filter deluge systems, will 

have visual internal inspections of piping performed every 

five years consistent with NFPA 25, 2011 Edition, Section 

14.2.

i. The in scope charcoal filter deluge systems will have 

visual internal inspections performed on one of the 11 

systems every five years. If degraded conditions are 

identified, the inspections will be expanded to include 

all 11 charcoal filter systems every five years.

d. Sprinkler and deluge systems that are normally dry but 

may be wetted as the result of testing or actuations will 

have additional tests and inspections on piping segments 

that cannot be drained or piping segments that allow 

water to collect.

i. These additional inspections, if required, will be 

performed in each five-year interval beginning five 

years prior to the period of extended operation.

ii. This additional inspection consists of either a flow test 

or flush sufficient to detect potential flow blockage or a 

visual inspection of 100 percent of the internal surface 

of piping segments that cannot be drained or piping 

segments that allow water to collect.

iii. In addition, in each five-year interval of the period of 

extended operation, 20 percent of the length of piping 

segments that cannot be drained or piping segments 

that allow water to collect is subject to volumetric wall 

thickness inspections.
A-10

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

4. Perform obstruction evaluations when degraded conditions are 

identified by visual inspections, flow testing, or volumetric 

examinations. The obstruction evaluations will include an 

extent of condition determination, need for increased 

inspections, and followup examinations if internal visual 

inspections detect age-related degradation in excess of what 

would be expected accounting for design, previous inspection 

experience, and inspection interval.

5. Perform flow tests for hose stations at the hydraulically most 

limiting locations for each zone of the system on a five-year 

frequency to demonstrate the capability to provide the design 

pressure at required flow.

6. Perform annual air tests on deluge systems supporting 

charcoal filter units excluding the “A” and “B” Auxiliary Electric 

Equipment Room Supply Air Filter units and the High 

Radiation Sampling System Filter unit. Perform visual internal 

inspections of the excluded filter units deluge systems in the 

event blockage was found on any deluge system that could be 

generic in nature.

7. Perform visual inspections of all charcoal filter unit deluge 

nozzles for proper orientation and verification that the nozzles 

are not obstructed on a 24 month frequency.

8. Include inspection for water leakage and loss of fluid in the 

glass bulbs of sprinkler heads, when performing visual 

inspections of sprinkler systems.

9. Include in main drain test acceptance criteria, the monitoring of 

flowing pressures from test to test. If there is a ten percent 

reduction in full flow pressure when compared to previously 

performed tests, an issue report shall be generated in the 

corrective action program to determine the cause and correct if 

necessary.

10. Maintain yard loop flow testing at a two year frequency until 

such time that the restricted section of piping from the pump 

house to Node 515 is restored to normal flow conditions.
A-11

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

18 Aboveground 

Metallic Tanks

Aboveground Metallic Tanks is an existing program that will be 

enhanced to:

1. Perform a visual inspection of the tank shell, roof, and bottom 

interior surfaces for signs of loss of material on one of the 

cycled condensate storage tanks within five years prior to the 

period of extended operation. This inspection shall include 

both wetted and non-wetted surfaces and may be either direct 

visual inspection from inside the tanks or volumetric 

examination from outside the tank. A volumetric examination 

from outside the tank will include 25 percent of the tank 

surface area. Should the one-time inspection identify 

degradation, periodic inspections with an inspection frequency 

based on the rate of degradation will be established for both 

tanks.

2. Perform a visual inspection of the exterior surfaces of both 

cycled condensate storage tanks for loss of material each 

refueling interval.

3. Perform a volumetric examination of the tank bottom for both 

cycled condensate storage tanks for signs of loss of material 

whenever the tanks are drained. At a minimum, an inspection 

shall be performed within 10 years prior to the period of 

extended operation and subsequent inspections shall be 

performed in each 10-year period during the period of 

extended operation. The next inspection scope will include 

100% of the accessible areas of each of the tank bottoms that 

are within 30 inches of the shell. Included in this scope are the 

patch plates that are directly exposed to the sand bed below. 

Additionally, 10 random locations of approximately one square 

foot each, outside of the 30 inch band, will be inspected. This 

inspection program will encompass approximately 20% of the 

tank bottom and will inspect all the susceptible areas which 

were found during the baseline inspections. Based on the 

results of this inspection, the scope will be reassessed for 

future tank bottom inspections, per the Corrective Action 

Program.

4. Perform an inspection of the caulking at the perimeter of the 

cycled condensate storage tank bases for signs of degradation 

each refueling interval (caulking inspections are supplemented 

with physical manipulation).

Program to be enhanced no lat

six months prior to the period o

extended operation.

Inspections described in 

Enhancements 1 and 3 will be 

completed either no later than s

months prior to the PEO, or be

the end of the last refueling out

prior to the PEO, whichever oc

later.

Additional schedule information 

identified in commitment.
A-12

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

19 Fuel Oil 

Chemistry

Fuel Oil Chemistry is an existing program that will be enhanced to:

1. Perform periodic (quarterly) sampling and analysis for water 

and sediment content, particulate concentration, and the levels 

of microbiological organisms for diesel fuel storage tanks 

0DO01T, 1DO01T, and 2DO01T.

2. Perform periodic (quarterly) sampling and analysis for water 

and sediment content, particulate concentration, and the levels 

of microbiological organisms for HPCS diesel fuel storage 

tanks 1DO02T and 2DO02T.

3. Perform periodic (quarterly) sampling and analysis for water 

and sediment content and the levels of microbiological 

organisms for diesel generator day tanks 0DO02T, 1DO05T, 

and 2DO05T.

4. Perform periodic (quarterly) sampling and analysis for water 

and sediment content and the levels of microbiological 

organisms for HPCS diesel day tanks 1DO04T and 2DO04T.

5. Perform periodic (quarterly) sampling and analysis for water 

and sediment content, particulate concentration, and the levels 

of microbiological organisms for diesel fire pump day tanks 

0FP01TA and 0FP01TB.

6. Perform periodic internal inspections of diesel fire pump day 

tanks 0FP01TA and 0FP01TB at least once during the 10-year 

period prior to the period of extended operation, and at least 

once every 10 years during the period of extended operation. 

Each diesel fuel tank will be drained and cleaned, the internal 

surfaces visually inspected (if physically possible), and, if 

evidence of degradation is observed during inspections, or if 

visual inspection is not possible, these diesel fuel tanks will be 

volumetrically inspected.

7. Perform volumetric inspection of diesel fuel storage tanks 

0DO01T, 1DO01T, and 2DO01T; HPCS diesel fuel storage 

tanks 1DO02T and 2DO02T; diesel generator day tanks 

0DO02T, 1DO05T, and 2DO05T; and HPCS diesel day tanks 

1DO04T and 2DO04T if evidence of degradation is observed 

during visual inspection, or if visual inspection is not possible.

Program to be enhanced no lat

six months prior to the period o

extended operation.

Inspections described in 

Enhancements 6 and 7 will be 

completed either no later than s

months prior to the PEO, or be

the end of the last refueling out

prior to the PEO, whichever oc

later.

Additional schedule information 

identified in commitment.
A-13

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

8. Perform periodic (quarterly) trending of water and sediment 

content, particulate concentration, and the levels of 

microbiological organisms for all fuel oil tanks within the scope 

of the program.

20 Reactor Vessel 

Surveillance

Reactor Vessel Surveillance is an existing program that will be 

enhanced to:

1. Establish a maximum fluence limit of 6.25E+17 n/cm2 (39.15 

EFPY) for monitoring the limiting Unit 1 axial welds to ensure 

that the axial weld failure probability does not exceed 5.02E-06 

per reactor year.

2. Complete a probabilistic axial weld failure analysis for Unit 1

that demonstrates the 60-year axial weld failure probability is 

no greater than 5.02E-06 per reactor year. Submit the 

analysis to the NRC for review and approval.

Enhancement 1 to be impleme

later than six months prior to th

period of extended operation.

Enhancement 2 to be complete

least three years prior to the lim

Unit 1 axial welds reaching the 

fluence limit of 6.25E+17 n/cm2 

EFPY).

21 One-Time 

Inspection

One-Time Inspection is a new condition monitoring program that will be 

used to verify the system-wide effectiveness of the Water Chemistry 

(A.2.1.2) program, Fuel Oil Chemistry (A.2.1.19) program, and 

Lubricating Oil Analysis (A.2.1.26) program which are designed to 

prevent or minimize aging to the extent that it will not cause a loss of 

intended function during the period of extended operation.

Program to be implemented no 

than six months prior to the per

extended operation.

One-time inspections will be 

performed within the 10 years p

the period of extended operatio

will be completed either no late

six months prior to the PEO, or 

the end of the last refueling out

prior to the PEO, whichever oc

later.
A-14

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

22 Selective 

Leaching

Selective Leaching is a new condition monitoring program that will 

include one-time inspections of a representative sample of susceptible 

components to determine if loss of material due to selective leaching is 

occurring.

Program to be implemented no 

than six months prior to the per

extended operation.

One-time inspections will be 

performed within the five years 

to the period of extended opera

and will be completed either no 

than six months prior to the PE

before the end of the last refue

outage prior to the PEO, which

occurs later. 

23 Unit 1 One-time 

Inspection of 

ASME Code 

Class 1 SmallBore Piping

Unit 1 One-time Inspection of ASME Code Class 1 Small-Bore Piping is 

a new condition monitoring program that will manage the aging effect of 

cracking in ASME Code Class 1 small-bore piping that is less than 

nominal pipe size (NPS) 4-inches, and greater than or equal to NPS 

1-inch.

Program to be implemented no 

than six months prior to the per

extended operation.

One-time Inspections will be 

performed within the six years 

the period of extended operatio

will be completed either no late

six months prior to the PEO, or 

the end of the last refueling out

prior to the PEO, whichever oc

later.

24 External Surfaces 

Monitoring of 

Mechanical 

Components

External Surfaces Monitoring of Mechanical Components is a new 

condition monitoring program that directs visual inspections of external 

surfaces of components be performed during system inspections and 

walkdowns.

Program to be implemented no 

than six months prior to the per

extended operation.

25 Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Internal Surfaces in Miscellaneous Piping and Ducting Components is 

new condition monitoring program that will consist of inspections of the 

internal surfaces of metallic and elastomeric components such as 

piping, piping components and piping elements, ducting components, 

tanks, heat exchanger components, elastomers, and other components 

that are exposed to environments of condensation, diesel exhaust, and 

waste water.

Program to be implemented no 

than six months prior to the per

extended operation.

26 Lubricating Oil 

Analysis

Existing program is credited. Ongoing 
A-15

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

27 Monitoring of 

NeutronAbsorbing 

Materials Other 

than Boraflex

Monitoring of Neutron-Absorbing Materials Other than Boraflex is an 

existing program that will be enhanced to:

1. Maintain the test coupon exposure such that it is bounding for 

the neutron-absorbing material in all spent fuel racks, by 

relocating the coupon tree to a different spent fuel rack cell 

location each cycle and by surrounding the coupons with a 

greater number of freshly discharged fuel assemblies than that 

of any other cell location.

Program to be enhanced no lat

six months prior to the period o

extended operation.

28 Buried and 

Underground 

Piping

Buried and Underground Piping is an existing program that will be 

enhanced to:

1. Manage cracking for stainless steel piping, utilizing a method 

that has been demonstrated to be capable of detecting 

cracking, whenever coatings are removed and expose the 

base material.

2. Ensure all underground carbon steel Essential Cooling Water 

System and Nonessential Cooling Water System piping and 

components within the scope of license renewal are coated in 

accordance with Table 1 of NACE SP0169-2007.

3. Define acceptable coating conditions as coating exhibiting 

either no evidence of degradation, or, the type and extent of 

coating damage evaluated as insignificant by: (a) an individual 

possessing a NACE Coating Inspector Program Level 2 or 3 

operator qualification, (b) an individual who has attended the 

Electric Power Research Institute (EPRI) Comprehensive 

Coatings Course and completed the EPRI Buried Pipe 

Condition Assessment and Repair Training Computer Based 

Training Course, or (c) a coatings specialist qualified in 

accordance with an ASTM standard endorsed in Regulatory 

Guide 1.54, Rev. 2, “Service Level I, II, and III Protective 

Coatings Applied to Nuclear Power Plants.”

4. Perform inspection quantities of buried piping within the scope 

of license renewal in accordance with LR-ISG-2015-01 

Table XI.M41-2 and LR-ISG-2015-01, Appendix B, “Evaluation 

and Technical Basis” section, items 4.a and 4.b, during each 

10-year period, beginning 10 years prior to the period of 

extended operation. The number of inspections of buried 

piping will be based upon the as-found results of cathodic 

Program to be enhanced no lat

six months prior to the period o

extended operation.

Enhancement 2 and inspection

described in Enhancements 4 a

will be completed either no late

six months prior to the PEO, or 

the end of the last refueling out

prior to the PEO, whichever oc

later

Additional schedule information 

identified in commitment.
A-16

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

protection system availability and effectiveness. The length of 

piping for each inspection will be based on the 

recommendations in LR-ISG-2015-01, Appendix B, “Evaluation 

and Technical Basis” section, item 4.c.

5. Perform direct visual inspections of underground Essential 

Cooling Water System and Nonessential Cooling Water 

System piping within the scope of license renewal during each 

10-year period, beginning 10 years prior to the period of 

extended operation.

6. When measured pipe wall thickness, projected to the end of 

the period of extended operation, does not meet the minimum 

pipe wall thickness requirements, the number of inspections 

within the affected piping categories will be doubled or 

increased by five (5), whichever is smaller. If adverse 

indications are found in the expanded sample, an analysis will 

be conducted to determine the extent of condition and extent 

of cause. The size of the followup inspections will be 

determined based on the analysis. Timing of the additional 

inspections will be based on the severity of the identified 

degradation and the consequences of leakage. The additional 

inspections will be performed within the same 10-year 

inspection interval in which the original degradation was 

identified, or within 4-years after the end of the 10-year interval 

if the degradation was identified in the latter half of the 10-year 

interval. Expansion of sample size may be limited by the 

extent of piping subject to the observed degradation 

mechanism or if the piping system or portion of the system is 

replaced.

7. Use only the -850mV relative to a CSE (copper/copper sulfate 

reference electrode), instant off criterion specified in NACE 

SP0169-2007 for acceptance criteria for steel piping and 

determination of cathodic protection system effectiveness in 

performing cathodic protection surveys. Alternatively, soil 

corrosion probes may also be used to demonstrate cathodic 

protection effectiveness during the annual surveys. An upper 

limit of -1200mV for pipe-to-soil potential measurements of 

coated pipes will also be established, so as to preclude 

potential damage to coatings.
A-17

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

8. Conduct an extent of condition evaluation if observed coating 

damage caused by non-conforming backfill has been 

evaluated as significant. The extent of condition evaluation will 

be conducted to ensure that the as-left condition of backfill in 

the vicinity of the observed damage will not lead to further 

degradation.

29 ASME Section XI, 

Subsection IWE

ASME Section XI, Subsection IWE is an existing program that will be 

enhanced to:

1. Provide guidance for proper specification of bolting material, 

lubricant and sealants, and installation torque or tension to 

prevent or mitigate degradation and failure of structural bolting.

2. If leakage from the reactor cavity pool drain line welds exists, 

then perform ultrasonic thickness measurements on the Unit 2 

drywell liner at 0 and 180 degrees for several feet below 

elevation 813. The inspections will begin in 2015 and a 

periodic inspection frequency will be established based on the 

inspection results.

Program to be enhanced no lat

six months prior to the period o

extended operation.

Additional schedule information 

identified in commitment.

30 ASME Section XI, 

Subsection IWL

ASME Section XI, Subsection IWL is an existing program that will be 

enhanced to:

1. Explicitly require that areas of concrete deterioration and 

distress be recorded in accordance with the guidance provided 

in ACI 349.3R.

2. Include quantitative acceptance criteria, based on the 

"Evaluation Criteria" provided in Chapter 5 of ACI 349.3R, that 

will be used to augment the qualitative assessment of the 

Responsible Engineer.

Program to be enhanced no lat

six months prior to the period o

extended operation.
A-18

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

31 ASME Section XI, 

Subsection IWF

ASME Section XI, Subsection IWF is an existing program that will be 

enhanced to:

1. Provide guidance for proper specification of bolting material, 

storage, lubricant and sealants, and installation torque or 

tension to prevent or mitigate degradation and failure of 

structural bolting. Requirements for high strength bolts shall 

include the preventive actions for storage, lubricants, and 

stress corrosion cracking potential discussed in Section 2 of 

RCSC (Research Council on Structural Connections) 

publication “Specification for Structural Joints Using ASTM 

A325 or A490 Bolts.” Lubricants that contain molybdenum 

disulfide (MoS2) shall not be applied to high strength bolts 

within the scope of license renewal. Bolting material with 

actual measured yield strength greater than or equal to 150 ksi 

or 1,034 MPa, in sizes greater than 1 inch nominal diameter 

shall not be used in supports for ASME Class 1, 2, and 3 

piping and components or supports for MC components.

2. Provide guidance, regarding the selection of supports to be 

inspected on subsequent inspections, when a support is 

repaired in accordance with the corrective action program. 

The enhanced guidance will ensure that the supports 

inspected on subsequent inspections are representative of the 

general population.

Program to be enhanced no lat

six months prior to the period o

extended operation.

32 10 CFR Part 50, 

Appendix J

Existing program is credited. Ongoing 

33 Masonry Walls Masonry Walls is an existing program that will be enhanced to:

1. Provide guidance for inspection of masonry walls for 

separation and gaps between the supports and masonry walls.

2. Require that personnel performing inspections and evaluations 

meet the qualifications described in ACI 349.3R.

Program to be enhanced no lat

six months prior to the period o

extended operation.
A-19

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

34 Structures 

Monitoring

Structures Monitoring is an existing program that will be enhanced to:

1. Add the following components and commodities:

a. Pipe, electrical, and equipment component support 

members

b. Pipe whip restraints and jet impingement shields

c. Panels, racks, cabinets, and other enclosures

d. Sliding surfaces

e. Sumps

f. Electrical cable trays and conduits

g. Electrical duct banks

h. Tube tracks

i. Transmission tower (including takeoff towers) and 

foundation (including cycled condensate storage tank 

foundations)

j. Penetration seals and sleeves

k. Blowout panels

l. Permanent drywell shielding

m. Transformer foundation

n. Bearing pads

o. Compressible joints

p. Hatches, plugs, handholes, and manholes

q. Metal components (decking, vent stack, and 

miscellaneous steel)

r. Building features – doors and seals, bird screens, louvers, 

windows, and siding

s. Concrete curbs, and anchors

t. Turbine Building smoke and heat vent housings

Program to be enhanced no lat

six months prior to the period o

extended operation.
A-20

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

2. Provide guidance for proper specification of bolting material, 

lubricant and sealants, and installation torque or tension to 

prevent or mitigate degradation and failure of structural bolting.

3. Revise storage requirements for high strength bolts to include 

recommendations of Research Council on Structural 

Connections (RCSC) Specification for Structural Joints Using 

High Strength Bolts, Section 2.0.

4. Require acceptance and evaluation of structural concrete 

using quantitative criteria based on Chapter 5 of ACI 349.3R.

5. Monitor raw water and ground water chemistry on a frequency 

not to exceed five years for pH, chlorides, and sulfates and 

verify that it remains non-aggressive, or evaluate results 

exceeding criteria to assess impact, if any, on below-grade 

concrete.

6. Monitor concrete for increase in porosity and permeability, 

inspection of accessible sliding surfaces for indication of 

significant loss of material due to wear or corrosion, debris, or 

dirt.

7. Evaluate the acceptability of inaccessible areas when 

conditions exist in accessible areas that could indicate the 

presence of, or result in, degradation to such inaccessible 

areas, and examine representative samples of the exposed 

portions of the below grade concrete when excavated for any 

reason.

8. Require that personnel performing inspections and evaluations 

meet the qualifications specified within ACI 349.3R with

respect to knowledge of inservice inspection of concrete and 

visual acuity requirements.

9. Clarify that loose bolts and nuts and cracked high strength 

bolts are not acceptable unless accepted by engineering 

evaluations.

10. Inspect the fiberglass outer covering for the permanent drywell 

shielding for signs of rips and tears. If a rip or tear is found, 

repair or replace the permanent drywell shielding.
A-21

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

35 RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants is an existing program that will be enhanced to:

1. Include monitoring of the following:

a. Submerged Core Standby Cooling System Pond and 

Intake Flume (includes earthen walls, south flume 

concrete retaining wall, and north flume sheet piling 

retaining wall)

b. Core Standby Cooling System outfall structure

c. Bar racks and miscellaneous steel

d. Shad net anchors

e. Lake Screen House (includes service water tunnel)

2. Monitor raw water and ground water chemistry at least once 

every five years for pH, chlorides, and sulfates and verify that it 

remains non-aggressive, or evaluate results exceeding criteria 

to assess impact, if any, on buried or submerged concrete.

3. Provide guidance for proper specification of bolting material, 

lubricant and sealants, and installation torque or tension to 

prevent or mitigate degradation and failure of structural bolting, 

and preventative actions for storage of materials to prevent 

stress corrosion cracking.

4. Require acceptance and evaluation of structural concrete 

using quantitative criteria based on Chapter 5 of ACI 349.3R.

5. Require inspection of accessible in scope portions of the 

Cooling Lake and Lake Screen House immediately following 

the occurrence of significant natural phenomena, which 

includes intense local rainfalls and large floods.

6. Require:

a. The evaluation of the acceptability of inaccessible areas 

when conditions exist in the accessible areas that could 

indicate the presence of, or result in, degradation to such 

inaccessible areas.

b. Examination of the exposed portions of the below grade 

concrete when excavated for any reason.

Program to be enhanced no lat

six months prior to the period o

extended operation.
A-22

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

36 Protective 

Coating 

Monitoring and 

Maintenance 

Program

Existing program is credited. Ongoing. 

37 Insulation 

Material for 

Electrical Cables 

and Connections 

Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

Insulation Material for Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements is a new 

program that will be used to manage reduced insulation resistance of 

the insulation material for non-EQ cables and connections. Accessible 

cables and connections located in adverse localized environments will 

be visually inspected at least once every 10 years for indications of 

reduced insulation resistance, such as embrittlement, discoloration, 

cracking, melting, swelling, or surface contamination.

Program to be implemented no 

than six months prior to the per

extended operation.

Initial inspections will be compl

either no later than six months 

the PEO, or before the end of t

refueling outage prior to the PE

whichever occurs later.

Additional schedule information 

identified in commitment.

38 Insulation 

Material for 

Electrical Cables 

and Connections 

Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements 

Used in 

Instrumentation 

Circuits

Insulation Material for Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Used in 

Instrumentation Circuits is a new program that will be used to manage 

the effects of reduced insulation resistance of non-EQ cable and 

connection insulation of the in scope portions of Neutron Monitoring, 

Process Radiation Monitoring and Area Radiation Monitoring Systems.

Calibration and cable tests will be performed and results will be 

assessed for reduced insulation resistance prior to the period of 

extended operation. Cable test frequency is based on engineering 

evaluation and is performed at least once every 10 years. Calibration 

and assessment of results is performed at least once every 10 years 

during the period of extended operation.

Program to be implemented no 

than six months prior to the per

extended operation.

Initial testing and assessment o

results will be completed either 

later than six months prior to th

PEO, or before the end of the l

refueling outage prior to the PE

whichever occurs later.

Additional schedule information 

identified in commitment.
A-23

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

39 Inaccessible 

Power Cables 

Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements is a new program that will be used to 

manage the effects of reduced insulation resistance of non-EQ, in 

scope, inaccessible power cables.

Cables will be tested using one or more proven tests for detecting 

deterioration of the insulation system. The cables will be tested at least 

once every six years. More frequent testing may occur based on test 

results and operating experience. Manholes associated with the cables 

included in this aging management program will be inspected for water 

collection with subsequent corrective actions (e.g., water removal), as 

necessary. Prior to the period of extended operation, the frequency of 

inspections for accumulated water will be established and adjusted 

based on plant specific operating experience with cable wetting or 

submergence, including water accumulation over time and event driven 

occurrences such as heavy rain or flooding. Operation of dewatering 

devices will be verified prior to any known or predicted heavy rain or 

flooding event. During the period of extended operation, the 

inspections will occur at least annually.

Program to be implemented no 

than six months prior to the per

extended operation.

Initial tests and inspections will 

completed either no later than s

months prior to the PEO, or be

the end of the last refueling out

prior to the PEO, whichever oc

later.

Additional schedule information 

identified in commitment.

40 Metal Enclosed 

Bus

Metal Enclosed Bus is an existing program that will be enhanced to:

1. Specify internal inspections will be performed for accessible 

non-segregated bus duct sections that are in scope for license 

renewal.

2. Clarify requirements for visual inspections of internal portions 

(bus enclosure assemblies); bus insulation; internal bus 

insulating supports; accessible gaskets, boots and sealants; 

and bus duct external surfaces.

3. Specify a sample size of 20 percent of the accessible bolted 

connection population, with a maximum sample size of 25, will 

be inspected for increased resistance of connection by either 

thermography or measuring the connection resistance using a 

micro ohmmeter.

4. Specify an inspection frequency of at least every 10 years.

Program to be enhanced no lat

six months prior to the period o

extended operation.

Additional schedule information 

identified in commitment.
A-24

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

41 Electrical Cable 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

Electrical Cable Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements program is a new program 

that will implement one-time testing of a representative sample (20 

percent with a maximum sample size of 25) of non-EQ electrical cable 

connections to ensure that either increased resistance of connection is 

not occurring or that the existing preventive maintenance program is 

effective such that a periodic inspection program is not required.

Program to be implemented no 

than six months prior to the per

extended operation.

One-time tests will be complete

either no later than six months 

the PEO, or before the end of t

refueling outage prior to the PE

whichever occurs later.

42 Service Level III 

and Service 

Level III 

Augmented 

Coatings 

Monitoring and 

Maintenance 

Program

Service Level III and Service Level III Augmented Coatings Monitoring 

and Maintenance Program is a new condition monitoring program that 

performs periodic visual inspections to verify the integrity of internal 

coatings designed to adhere to and protect the base metal.

Program to be implemented no 

than six months prior to the per

extended operation.

Baseline inspections will occur 

10-year period prior to the perio

extended operation, and will be 

completed either no later than s

months prior to the PEO, or be

the end of the last refueling out

prior to the PEO, whichever oc

later.

43 Fatigue 

Monitoring

Fatigue Monitoring is an existing program that will be enhanced to:

1. Impose administrative transient cycle limits corresponding to 

the limiting numbers of cycles used in the environmental 

fatigue calculations.

2. Evaluate the impact of the reactor coolant environment on 

Class 1 components including valves and pumps if they are 

more limiting than those considered in NUREG/CR-6260.

Program to be enhanced no lat

six months prior to the period o

extended operation.

Any additional environmental fa

evaluations will be completed n

than six months prior to the per

extended operation.

44 Concrete 

Containment 

Tendon Prestress

Concrete Containment Tendon Prestress is an existing condition 

monitoring program that will be enhanced to:

1. For each surveillance interval, trending lines will be updated 

through the period of extended operation as part of the 

regression analysis and compared to the predicted lower limit 

and minimum required values for each tendon group.

Program to be enhanced no lat

six months prior to the period o

extended operation.
A-25

Item 

Number

Program or 

Topic Commitment Enhancement or Implementation Schedu

45 Environmental 

Qualification (EQ) 

of Electric 

Components

Existing program is credited. Ongoing 

46 Operating 

Experience

Existing program is credited. Ongoing 

47 TLAA - Slip Joint 

Clamp

Prior to exceeding the limiting fluence value of 1.17E+20 n/cm2 at the 

Unit 1 jet pump slip joint clamp location, estimated to be at 50.7 EFPY, 

revise the analysis for the slip joint clamps for a higher acceptable 

fluence value or take other corrective action such as repair or 

replacement of the clamps to ensure acceptable clamp preload.

Procedure tracking the cumula

EFPY values to be enhanced n

than six months prior to the per

extended operation.

For the analysis option, if selec

the revised analysis must be 

submitted to the NRC for review 

least 2 years prior to exceeding 

EFPY. For the repair or replac

options, if selected, repair or 

replacement must be implemen

prior to exceeding 50.7 EFPY.

48 Unit 2 Inspection 

of ASME Code 

Class 1 SmallBore Piping 

Program

Unit 2 Inspection of ASME Code Class 1 Small-Bore Piping Program is 

a new condition monitoring program that will manage the aging effect of 

cracking in ASME Code Class 1 small-bore piping that is less than 

nominal pipe size (NPS) 4-inches, and greater than or equal to NPS 1-

inch.

Program to be implemented no 

than six months prior to the per

extended operation.

The one-time inspections and t

set of periodic inspections will b

performed within the six years 

the period of extended operatio

will be completed either no late

six months prior to the PEO, or 

the end of the last refueling out

prior to the PEO, whichever oc

later.

CHRONOLOGY

B-1

B. Chronology

This appendix lists chronologically the routine licensing correspondence between the staff of the 

United States (U.S.) Nuclear Regulatory Commission (NRC) (the staff) and Exelon Generation 

Company, LLC (Exelon or the applicant). This appendix also lists other correspondence on the 

staff’s review of the LaSalle County Station, Units 1 and 2 (LSCS), license renewal application 

(LRA) (under Docket Nos. 50-373 and 50-374).

Date Subject

December 9, 2014 LaSalle County Station, Units 1 and 2 (LSCS) – Application for Renewed Operating 

Licenses (Agencywide Documents Access and Management System (ADAMS) 

Accession No. ML14343A840)

December 9, 2014 LaSalle, Units 1 and 2 - License Renewal Application, Title Page – Section 3, 

Table 3.4.2-5 (ADAMS Accession No. ML14343A841)

December 9, 2014 LaSalle, Units 1 and 2 - License Renewal Application, Section 3.5 – End (ADAMS 

Accession No. ML14343A842)

December 11, 2014 Letter to Gallagher, M.G., Exelon. Subject: Receipt and Availability of the License 

Renewal Application for LaSalle County Station, Units 1 and 2 (TAC Nos. MF5347 and 

MF5346) (ADAMS Accession No. ML14337A267)

December 18, 2014 Federal Register Notice – Notice of Receipt and Availability of the LaSalle County 

Station, Units 1 and 2, License Renewal Application (FRN 2014-75598) (ADAMS 

Accession No. ML14336A372)

January 26, 2015 Letter to Gallagher, M.G., Exelon. Subject: Determination of Acceptability and 

Sufficiency for Docketing, and Opportunity for Hearing (ADAMS Accession 

No. ML15021A451)

February 3, 2015 Federal Register Notice – Opportunity to Request a Hearing and Petition for Leave to 

Intervene (FRN 80 FR 5822) (ADAMS Accession No. ML15020A430)

February 20, 2015 License Renewal Application Environmental Review Scoping Meetings for LaSalle 

County Station, Units 1 and 2 (ADAMS Accession No. ML15058A275)

March 10, 2015 Transcript of Public Meeting RE License Renewal Application of LaSalle, Units 1 and 2, 

Afternoon Session, March 10, 2015, Pages 1 – 63 (ADAMS Accession 

No. ML15083A538)

March 10, 2015 Transcript of Public Meeting RE License Renewal Application of LaSalle, Units 1 and 2, 

Evening Session, March 10, 2015, Pages 1 – 55. (ADAMS Accession 

No. ML15089A580)

March 27, 2015 Letter to Gallagher, M.G., Exelon. Subject: Corrected: Determination of Acceptability 

and Sufficiency for Docketing, Proposed Review Schedule, and Opportunity for a

Hearing Regarding the Application from Exelon Generation Company, LLC, for Renewal 

of the Operating Licenses for LaSalle County Station, Units 1 and 2 (TAC Nos. MF5347 

and MF5346) (ADAMS Accession No. ML15030A320)

March 30, 2015 LaSalle County Station, Units 1 and 2 License Renewal Application Online Reference 

Portal (TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15082A058)

April 1, 2015 Meeting Summary: Public Scoping Meetings for Environmental Review of LaSalle 

County Station (LSCS) Units 1 and 2, License Renewal Application (LRA) 

(TAC Nos. MF5567 AND MF5568) (ADAMS Accession No. ML15091A329)

May 8, 2015 Report: Scoping and Screening Methodology Report Regarding LaSalle County Station, 

Units 1 and 2 (ADAMS Accession No. ML15104A782)

May 14, 2015 Requests for Additional Information for the Review of the LaSalle County Station, 

Units 1 and 2 License Renewal Application – Set 1 (TAC Nos. MF5347 and MF5346) 

(ADAMS Accession No. ML15111A137)

May 29, 2015 Requests for Additional Information for the Review of the LaSalle County Station, 

Units 1 and 2 License Renewal Application – Set 2 (TAC Nos. MF5347 and MF5346)

(ADAMS Accession No. ML15125A198)
B-2

Date Subject

June 8, 2015 Response to NRC Requests for Additional Information, Set 1, dated May 14, 2015, 

related to the LaSalle County Station, Units 1 and 2, License Renewal Application 

(TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15159A980)

June 8, 2015 Requests for Additional Information for the Review of the LaSalle County Station, 

Units 1 and 2 License Renewal Application – Set 3 (TAC Nos. MF5347 and MF5346) 

(ADAMS Accession No. ML15131A413)

June 8, 2015 Summary of Telephone Conference Call Held on May 12, 2015, Between the 

U.S. Nuclear Regulatory Commission and Exelon Generation Co., LLC, Concerning 

Requests for Additional Information, Set 1 Pertaining To the LaSalle County Station

License Renewal Application (TAC Nos. MF5347 and MF5346) (ADAMS Accession 

No. ML15140A093)

June 8, 2015 Summary of Telephone Conference Call Held on May 13, 2015, Between the 

U.S. Nuclear Regulatory Commission and Exelon Generation Co., LLC, Concerning 

Requests for Additional Information, Set 2 Pertaining to the LaSalle County Station 

License Renewal Application (TAC Nos. MF5347 and MF5346) (ADAMS Accession 

No. ML15140A192)

June 19, 2015 Requests for Additional Information for the Review of the LaSalle County Station, 

Units 1 and 2 License Renewal Application – Set 4 (TAC Nos. MF5347 and MF5346) 

(ADAMS Accession No. ML15146A262)

June 25, 2015 Response to NRC Requests for Additional Information, Set 2, dated May 29, 2015 

related to the LaSalle County Station, Units 1 and 2, License Renewal Application 

(TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15176A348)

July 1, 2015 Response to NRC Requests for Additional Information, Set 3, dated June 8, 2015 

related to the LaSalle County Station, Units 1 and 2, License Renewal Application 

(TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15182A337)

July 6, 2015 Summary of Telephone Conference Call Held on May 20, 2015, Between the 

U.S. Nuclear Regulatory Commission and Exelon Generation Co., LLC, Concerning 

Requests for Additional Information, Set 3 Pertaining to the LaSalle County Station 

License Renewal Application (TAC Nos. MF5347 and MF5346) (ADAMS Accession 

No. ML15159A900)

July 7, 2015 Requests for Additional Information for the Review of the LaSalle County Station, 

Units 1 and 2 License Renewal Application – Set 5 (TAC Nos. MF5347 and MF5346) 

(ADAMS Accession No. ML15159A208)

July 7, 2015 Requests for Additional Information for the Review of the LaSalle County Station, 

Units 1 and 2 License Renewal Application – Set 6 (TAC Nos. MF5347 and MF5346) 

(ADAMS Accession No. ML15163A071)

July 15, 2015 Response to NRC Requests for Additional Information, Set 4, dated June 19, 2015 

related to the LaSalle County Station, Units 1 and 2, License Renewal Application 

(TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15196A421)

July 16, 2015 Request for Schedule Change Related to Advisory Committee on Reactor Safeguards 

(ACRS) Subcommittee Review of LaSalle County Station, Units 1 and 2, License 

Renewal Application (TAC Nos. MF5347 and MF5346) (ADAMS Accession 

No. ML15197A206)

July 27, 2015 Requests for Additional Information for the Review of the LaSalle County Station, 

Units 1 and 2 License Renewal Application

August 6, 2015 Response to NRC Requests for Additional Information, Set 5, dated July 7, 2015 related 

to the LaSalle County Station, Units 1 and 2, License Renewal Application 

(TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15218A421)

August 6, 2015 Response to NRC Requests for Additional Information, Set 6, dated July 7, 2015 related 

to the LaSalle County Station, Units 1 and 2, License Renewal Application 

(TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15218A424)

August 18, 2015 Requests for Additional Information for the Review of the LaSalle County Station, 

Units 1 and 2 License Renewal Application – Set 9 (TAC Nos. MF5347 and MF5346) 

(ADAMS Accession No. ML15204A630)
B-3

Date Subject

August 26, 2015 Response to NRC Requests for Additional Information, Set 7, dated July 27, 2015; and 

a Correction to Information associated with the Set 2 response to RAI 8.2.1.20-2, related 

to the LaSalle County Station, Units 1 and 2, License Renewal Application 

(TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15238B621)

August 27, 2015 Requests for Additional Information for the Review of the LaSalle County Station, 

Units 1 and 2 License Renewal Application – Set 10 (TAC Nos. MF5347 and MF5346) 

(ADAMS Accession No. ML15229A019)

August 28, 2015 Summary of Telecon Held on June 3, 2015, Between the NRC and Exelon Generation 

Co., LLC, Concerning Request for Additional Information Set 4 Pertaining to the LaSalle

County Station License Renewal Application (TAC Nos. MF5347 and MF5346) (ADAMS 

Accession No. ML15217A564)

August 28, 2015 Summary of Telecon Held on June 10, 2015, Between the NRC and Exelon Generation 

Co., LLC, Concerning Request for Additional Information Set 4 Pertaining to the LaSalle

County Station License Renewal Application (TAC Nos. MF5347 and MF5346) (ADAMS 

Accession No. ML15217A575)

August 28, 2015 Summary of Telecon Held on June 9, 2015, Between the NRC and Exelon Generation 

Co., LLC, Concerning Request for Additional Information Set 5 Pertaining to the LaSalle

County Station License Renewal Application (TAC Nos. MF5347 and MF5346) (ADAMS 

Accession No. ML15217A541)

August 28, 2015 Summary of Telecon Held on June 23, 2015, Between the NRC and Exelon Generation 

Co., LLC, Concerning Request for Additional Information Set 6 Pertaining to the LaSalle

County Station License Renewal Application (TAC Nos. MF5347 and MF5346) (ADAMS 

Accession No. ML15219A277)

August 28, 2015 Summary of Telecon Held on July 8, 2015, Between the NRC and Exelon Generation 

Co., LLC, Concerning Request for Additional Information Set 7 Pertaining to the LaSalle

County Station License Renewal Application (TAC Nos. MF5347 and MF5346) (ADAMS 

Accession No. ML15222A015)

August 28, 2015 Summary of Telecon Held on July 22, 2015, Between the NRC and Exelon Generation 

Co., LLC, Concerning Request for Additional Information Set 8 Pertaining to the LaSalle 

County Station License Renewal Application (TAC Nos. MF5347 and MF5346) (ADAMS 

Accession No. ML15222A008)

August 28, 2015 Summary of Telecon Held on August 11, 2015, Between the NRC and Exelon 

Generation Co., LLC, Concerning Request for Additional Information Set 9 Pertaining to 

the LaSalle County Station License Renewal Application (TAC Nos. MF5347 and 

MF5346) (ADAMS Accession No. ML15224A935)

August 28, 2015 Summary of Telecon Held on August 5, 2015, Between the NRC and Exelon Generation 

Co., LLC, Concerning Request for Additional Information Set 9 Pertaining to the LaSalle 

County Station License Renewal Application (TAC Nos. MF5347 and MF5346) (ADAMS 

Accession No. ML15222A006)

August 28, 2015 Requests for Additional Information for the Review of the LaSalle County Station, 

Units 1 and 2 License Renewal Application – Set 8 (TAC Nos. MF5347 and MF5346) 

(ADAMS Accession No. ML15195A338)

September 14, 2015 Requests for Additional Information for the Review of the LaSalle County Station, 

Units 1 and 2 License Renewal Application – Set 11 (TAC Nos. MF5347 and MF5346) 

(ADAMS Accession No. ML15244B353)

September 15, 2015 Response to NRC Requests for Additional Information, Set 9, dated August 18, 2015 

related to the LaSalle County Station, Units 1 and 2, License Renewal Application 

(TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15258A305)

September 17, 2015 Response to NRC Requests for Additional Information, Set 10, dated August 27, 2015 

related to the LaSalle County Station, Units 1 and 2, License Renewal Application 

(TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15260A319)

September 22, 2015 Letter to Gallagher, M.P., Exelon. Subject: Aging Management Programs Audit Report 

Regarding LaSalle County Station, Units 1 and 2 (TAC Nos. MF5347 and MF5346) 

(ADAMS Accession No. ML15196A045)
B-4

Date Subject

September 22, 2015 Report: Aging Management Programs Audit Report Regarding LaSalle County Station, 

Units 1 and 2 (TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15196A115)

September 28, 2015 Response to NRC Requests for Additional Information, Set 8, dated August 28, 2015 

related to the LaSalle County Station, Units 1 and 2, License Renewal Application 

(TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15271A341)

October 8, 2015 Response to NRC Request for Additional Information, Set 11, dated 

September 14, 2015 related to the LaSalle County Station, Units 1 and 2, License 

Renewal Application (TAC Nos. MF5347 and MF5346) (ADAMS Accession 

No. ML15281A319)

October 22, 2015 Schedule Revision for the Review of the LaSalle County Station, License Renewal 

Application (TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15208A052)

October 23, 2015 Requests for Additional Information for the Review of the LaSalle County Station, 

Units 1 and 2 License Renewal Application – Set 12 (TAC Nos. MF5347 and MF5346) 

(ADAMS Accession No. ML15271A021)

October 29, 2015 Response to NRC Requests for Additional Information, Set 12, dated October 23, 2015 

related to the LaSalle County Station, Units 1 and 2, License Renewal Application 

(TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15302A493)

November 3, 2015 Requests for Additional Information for the Review of the LaSalle County Station, 

Units 1 and 2 License Renewal Application – Set 13 (TAC Nos. MF5347 and MF5346) 

(ADAMS Accession No. ML15300A366)

November 18, 2015 LaSalle County Station, Units 1 and 2 License Renewal Scoping, Screening, and Aging 

Management Inspection Report 05000373/2015008; 05000374/2015008 (ADAMS 

Accession No. ML15323A064)

December 2, 2015 10 CFR 54.21(b) Annual Amendment to the LaSalle County Station, Units 1 and 2, 

License Renewal Application (TAC Nos. MF5347 and MF5346) (ADAMS Accession 

No. ML15336A288)

December 2, 2015 Corrections to the LaSalle County Station, Units 1 and 2, License Renewal Application 

(TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15336A220)

December 10, 2015 Response to NRC Requests for Additional Information, Set 13, dated November 3, 2015 

related to the LaSalle County Station, Units 1 and 2, License Renewal Application 

(TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15344A347)

December 11, 2015 Summary of Teleconference Held on September 24, 2015, Between the NRC and

Exelon Generation Co., LLC, Concerning RAI Set 10 Response Pertaining to the

LaSalle County Station License Renewal Application (TAC Nos. MF5347 and MF5346) 

(ADAMS Accession No. ML15272A400)

December 14, 2015 Requests for Additional Information for the Review of the LaSalle County Station, 

Units 1 and 2 License Renewal Application – Set 14 (TAC Nos. MF5347 and MF5346) 

(ADAMS Accession No. ML15301A189)

January 7, 2016 Responses to NRC Requests for Additional Information, Set 14, dated 

December 14, 2015, and Two Additional Commitment Implementation Schedule 

Clarifications, related to the LaSalle County Station, Units 1 and 2, License Renewal 

Application (TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML16007A130)

January 7, 2016 Summary of Teleconference Held on December 22, 2015, Between the NRC and

Exelon Generation Co., LLC, Concerning the LaSalle County Station License Renewal 

Application (TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML15357A281)

January 14, 2016 Supplemental Information Associated With Implementation of BWRVIP-25, "Core Plate 

Inspection and Flaw Evaluation Guidelines," Related To the LaSalle County Station, 

Units 1 and 2, License Renewal Application (TAC Nos. MF5347 AND MF5346) ADAMS 

Accession No. ML16014A173)

January 29, 2016 Summary of Teleconference Held on January 21, 2016, Between the U.S. Nuclear 

Regulatory Commission and Exelon Generation Co., LLC, Concerning RAI 4.2.10-1 

Response Pertaining to the LaSalle County Station, Units 1 and 2, License Renewal 

Application (TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML16021A325)
B-5

Date Subject

February 1, 2016 Update to Commitment 47 related to the LaSalle County Station, Units 1 and 2, License 

Renewal Application (TAC Nos. MF5347 AND MF5346) (ADAMS Accession 

No. ML16032A381)

February 16, 2016 Requests for Additional Information for the Review of the LaSalle County Station, 

Units 1 and 2 License Renewal Application – Set 15 (TAC Nos. MF5347 and MF5346) 

(ADAMS Accession No. ML15344A354)

February 25, 2016 Response to NRC Requests for Additional Information, Set 15, dated February 16, 2016

related to the LaSalle County Station, Units 1 and 2, License Renewal Application 

(TAC Nos. MF5347 and MF5346) (ADAMS Accession No. ML16056A232)

February 29, 2016 Safety Evaluation Report With Open Items Related to the License Renewal of LaSalle 

County Station, Units 1 and 2 (ADAMS Accession No. ML16053A439)

April 4, 2016 Exelon Generation Company, LLC Comments on the Safety Evaluation Report with 

Open Items, related to the LaSalle County Station, Units 1 and 2 License Renewal 

Application (ADAMS Accession No. ML16095A273)

April 13, 2016 Supplemental information associated with NRC issuance of LR-ISG-2015-01, “Changes 

to Buried and Underground Piping and Tank Recommendations,” related to the LaSalle 

County Station, Units 1 and 2, License Renewal Application (TAC Nos. MF5347 and 

MF5346) (ADAMS Accession No. ML16104A114)

June 2, 2016 Safety Evaluation Report Related to the License Renewal of LaSalle County Station, 

Units 1 and 2 (ADAMS Accession No. ML16126A503)

June 8, 2016 Second 10 CFR 54.21(b) Annual Amendment to the LaSalle County Station, Units 1 

and 2, License Renewal Application (TAC Nos. MF5347 and MF5346) (ADAMS 

Accession No. ML16160A329)

July 18, 2016 Report on the Safety Aspects of the License Renewal Application of the LaSalle County 

Station, Units 1 and 2 (ADAMS Accession No. ML16200A156)

PRINCIPAL CONTRIBUTORS

C-1

C. Principal Contributors

This appendix lists the principal contributors for the development of this safety evaluation report 

(SER) and their areas of responsibility.

Name Responsibility

Mitchell, Jeffrey Project Manager

Allik, Brian Reviewer – Mechanical and Materials

Brittner, Donald Reviewer – Operating Experience

Buford, Angela Reviewer – Structural

Casto, Greg Management Oversight

Cuadrado de Jesús, Samuel Reviewer – Structural

Dennig, Robert Management Oversight

Diaz-Sanabria, Yoira Management Oversight

Doutt, Cliff Reviewer – Electrical

Facco, Giovanni Reviewer – Mechanical and Materials

Fitzpatrick, Robert Reviewer – Scoping and Screening

Fu, Bart Reviewer – Mechanical and Materials

Gardner, William (Tony) Reviewer – Mechanical and Materials

Gavula, James Reviewer – Mechanical and Materials

Gettys, Evelyn Reviewer – Electrical

Hardgrove, Matthew Reviewer – Scoping and Screening

Hiser, Allen Senior Technical Advisor

Holston, William Reviewer – Mechanical and Materials

Homiack, Matthew Reviewer – Mechanical and Materials

Hovanec, Christopher Reviewer – Mechanical and Materials

Iqbal, Naeem Reviewer – Scoping and Screening

Jackson, Christopher Management Oversight

Kalikian, Varoujan (Roger) Reviewer – Mechanical and Materials

Klein, Alex Management Oversight

Kulesa, Gloria Management Oversight

Lehman, Bryce Reviewer – Structural

López Ferrer, Juan Reviewer – Structural

Lubinski, John Management Oversight

Lupold, Timothy Management Oversight

Marshall, Jane Management Oversight

Marshall, Michael Management Oversight

McGinty, Tim Management Oversight

Medoff, James Reviewer – Mechanical

Miller, Christopher Management Oversight

Min, Seung Reviewer – Mechanical and Materials 

Morey, Dennis Management Oversight

Nolan, Caty Reviewer – Mechanical
C-2

Name Responsibility

Obadina, Sarah Reviewer – Mechanical and Materials

Obodoako, Aloysius Reviewer – Mechanical and Materials

Otto, Ngola Reviewer – Scoping and Screening

Pettis, Robert Reviewer – Scoping and Screening

Plasse, Richard Project Manager

Prinaris, Andrew Reviewer – Structural

Reddy, Devender Reviewer – Scoping and Screening

Rogers, Bill Reviewer – Scoping and Screening Methodology

Sadollah, Mohammad (Mo) Reviewer – Electrical

Smith, Edward Reviewer – Scoping and Screening

Sweat, Tarico Reviewer – Scoping and Screening

Thomas, George Reviewer – Structural

Wise, John Reviewer – Mechanical and Materials

Wittick, Brian Management Oversight

Wong, Albert Reviewer – Mechanical and Materials

Yoo, Mark Reviewer – Mechanical and Materials

Zimmerman, Jacob Management Oversight
REFERENCES

D-1

D. References

This appendix lists the references used throughout this safety evaluation report (SER) for review 

of the license renewal application for LaSalle County Station, Units 1 and 2 (LSCS).

U.S. Nuclear Regulatory Commission Documents

Commission Order No. CLI-10-17, July 8, 2010.

Generic Letter (GL) 82-04, “Use of INPO SEE-IN Program,” March 9, 1982.

GL 88-01, “NRC Position on Intergranular Stress Corrosion Cracking (IGSCC) in BWR Austenitic Stainless Steel 

Piping,” January 25, 1988.

GL 88-14, “Instrument Air Supply System Problems Affecting Safety-Related Equipment,” August 8, 1988

GL 89-13, “Service Water System Problems Affecting Safety-Related Equipment,” July 18, 1989.

GL 96-03, “Relocation of the Pressure Temperature Limit Curves and Low Temperature Overpressure Protection 

System Limits,” January 31, 1996.

GL 98-05, “Boiling Water Reactor Licensees Use of the BWRVIP-05 Report to Request Relief from Augmented 

Examination Requirements on Reactor Pressure Vessel Circumferential Shell Welds,” November 10, 1998.

Generic Safety Issue (GSI)-190, “Fatigue Evaluation of Metal Components for 60-Year Plant Life,” 

December 10, 1999.

Inspection and Enforcement (IE) Bulletin 80-11, “Masonry Wall Design,” May 8, 1980.

Information Notice (IN) 87-67, “Lessons Learned from Regional Inspections of Licensee Actions in Response to IE 

Bulletin 80-11,” December 31, 1987.

IN 99-10, “Degradation of Prestressing Tendon Systems in Prestressed Concrete Containments,” October 7, 1999.

IN 2011-20, “Concrete Degradation by Alkali-Silica Reaction,” November 18, 2011.

Letter from W.H. Bateman, U.S. Nuclear Regulatory Commission (NRC), to B. Eaton, BWRVIP Chairman. 

Subject: Safety Evaluation of Proprietary EPRI Reports, BWRVIP RAMA Fluence Methodology Manual 

(BWRVIP-114), RAMA Fluence Methodology Benchmark Manual (BWRVIP-115), RAMA Fluence Methodology –

Susquehanna Unit 2 Surveillance Capsule Fluence Evaluation for Cycles 1 – 5 (BWRVIP-117), RAMA Fluence 

Methodology Procedures Manual (BWRVIP-121), and Hope Creek Flux Wire Dosimeter Activation Evaluation for 

Cycle 1 (TWE-PSE-001-R-001) (TAC No. MB9765), May 13, 2005.

Letter from J. Remer, NEI, to C.G. Miller, NRC. Subject: Response to NRC Questions Concerning GALL 

AMP XI.M17, Flow-Accelerated Corrosion, NSAC-202L Revision 4, November 5, 2014 (ADAMS Accession 

No. ML14309A702).

Attachment to the J. Remer letter, “Response to NRC Questions Concerning GALL AMP XI.M17, FlowAccelerated Corrosion, NSAC-202L Revision 4,” November 5, 2014 (ADAMS Accession No. ML14309A700).

License Renewal Interim Staff Guidance (LR-ISG)-2011-01, “Aging Management of Stainless Steel Structures and 

Components in Treated Borated Water,” Revision 1, December 18, 2012.

LR-ISG-2011-03, “Changes to the Generic Aging Lessons Learned (GALL) Report Revision 2 Aging Management 

Program XI.M41, ‘Buried and Underground Piping and Tanks,’” August 2, 2012. 

LR-ISG-2011-04, “Updated Aging Management Criteria for Reactor Vessel Internal Components for Pressurized 

Water Reactors,” June 3, 2013.

LR-ISG-2011-05, “Ongoing Review of Operating Experience,” March 16, 2012.

LR-ISG-2012-01, “Wall Thinning Due to Erosion Mechanisms,” May 1, 2013.
D-2

U.S. Nuclear Regulatory Commission Documents

LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and 

Corrosion under Insulation,” November 14, 2013.

LR-ISG-2013-01, “Aging Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on 

In-Scope Piping, Piping Components, Heat Exchangers, and Tanks,” November 6, 2014.

LR-ISG-2015-01, “Changes to Buried and Underground Piping and Tank Recommendations,” January 28, 2016.

NUREG-0519, “Safety Evaluation Report Related to the Operation of LaSalle County Station, Units 1 and 2,” 

March 1981.

NUREG-0519, Supplement 2, “Safety Evaluation Report Related to the Operation of LaSalle County Station, 

Units 1 and 2,” February 1982.

NUREG-0519, Supplement 3, “Safety Evaluation Report Related to the Operation of LaSalle County Station, 

Units 1 and 2,” April 1982.

NUREG-0519, Supplement 5, “Safety Evaluation Report Related to the Operation of LaSalle County Station, 

Units 1 and 2,” August 1983.

NUREG-0519, Supplement 7, “Safety Evaluation Report Related to the Operation of LaSalle County Station, 

Units 1 and 2,” December 1983.

NUREG-0519, Supplement 8, “Safety Evaluation Report Related to the Operation of LaSalle County Station, 

Units 1 and 2,” March 1984.

NUREG-0612, “Control of Heavy Loads at Nuclear Power Plants: Resolution of Generic Technical Activity A-36,” 

July 1980.

NUREG-0619, “BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking,” November 1980.

NUREG-0737, “Clarification of TMI Action Plan Requirements,” November 1980.

NUREG-1339, “Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants,” 

June 1990.

NUREG-1437, Supplement 57, “Generic Environmental Impact Statement for License Renewal of Nuclear Power 

Plants, Supplement 57, Regarding LaSalle County Station, Units 1 and 2, Draft Report for Comment,“

February 2016.

NUREG-1552, “Fire Barrier Penetration Seals in Nuclear Power Plants,” Supplement 1, January 1999

NUREG-1800, “Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants,” 

Revision 2, December 2010.

NUREG-1801, “Generic Aging Lessons Learned (GALL) Report,” Revision 2, December 2010.

NUREG/CR-6260, “Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant 

Components,” February 1995.

NUREG/CR-6909, “Effect of LWR Coolant Environments on the Fatigue Life of Reactor Materials,” February 2007.

Regulatory Guide (RG) 1.99, “Radiation Embrittlement of Reactor Vessel Materials,” Revision 2, May 1988.

RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants,” Revision 1, 

March 1978.

RG 1.35.1, “Determining Prestressing Forces for Inspection of Prestressed Concrete Containments,” July 1990.

RG 1.43, “Control of Stainless Steel Weld Cladding of Low-Alloy Steel Components,” Revision 1, March 2011.

RG 1.54, “Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants,” Revision 2, 

October 2010.

RG 1.160, “Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,” Revision 2, March 1997.

RG 1.188, “Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses,”

Revision 1, September 2005.
D-3

U.S. Nuclear Regulatory Commission Documents

RG 1.189, “Fire Protection for Nuclear Power Plants,” Revision 2, October 2009.

RG 1.190, “Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence,” March 2001.

Safety Evaluation Report, “NRC Evaluation of the Consequences of Postulated Failures of 1 Hour Fire Rated 

Darmatt KM-1 Fire Barrier under Seismic Loading at LaSalle County Station, Units 1 and 2,” March 29, 1996.

Regulations

Atomic Energy Act of 1954, as amended (42 U.S.C. 2011 et seq.)

U.S. Code of Federal Regulations (CFR), “Domestic Licensing of Production and Utilization Facilities,” Part 50, 

Title 10, “Energy,” Office of the Federal Register, National Archives and Records Administration, 2012.

CFR, “Reporting of Defects and Noncompliance,” Part 21, 2014.

CFR, “Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions,” Part 51, 

2014.

CFR, “Reactor Site Criteria,” Part 100, 2014.

CFR, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants,” Part 54, 2014.

CFR, “Financial Protection Requirements and Indemnity Agreements,” Part 140, 2014.

National Environmental Policy Act of 1969, as amended (42 U.S.C. 4321 et seq.)

Industry Codes and Standards, By Source

American Concrete Institute (ACI):

ACI 318, “Building Code Requirements for Reinforced Concrete and Commentary,” 2002.

ACI 349.3R-02, “Evaluation of Existing Nuclear Safety Related Concrete Structures,” June 2002.

American National Standards Institute, Inc./International Society of Automation (ANSI/ISA):

ANSI/ISA-7.0.01-1996, “Quality Standard for Instrument Air,” November 1996.

American Society for Metals (ASM):

ASM International, “Atlas of Fatigue Curves,” 1986.

J.R. Davis, ASM Specialty Handbook: Nickel, Cobalt, and Their Alloys, ASM International, 2000.

J.R. Davis, Corrosion of Aluminum and Aluminum Alloys, ASM International, 1999.

American Society of Mechanical Engineers (ASME):

ASME Code Section III, Subsection NB-3600.

ASME Code Section Xl, “Rules for In-Service Inspection of Nuclear Power Plant Components.”

ASME Code B30.2, “Overhead and Gantry Cranes (Top Running Bridge, Single or Multiple Girder, Top Running 

Trolley Hoist),” 2011.

ASME Code OM-S/G-1998, Part 17, “Performance Testing of Instrument Air System in Light-Water Reactor Power 

Plant,” 1998.

ASME NOG-1-2004, “Rules for Construction of Overhead and Gantry Cranes (Top Running Bridge, Multiple 

Girder),” May 16, 2005.

American Society for Testing and Materials (ASTM):

ASTM B209-14, “Standard Specification for Aluminum and Aluminum-Alloy Sheet and Plate,” November 2014.

ASTM B308, “Standard Specification for Aluminum-Alloy 6061-T6 Standard Structural Profiles,” June 2010.
D-4

Industry Codes and Standards, By Source

ASTM C227, “Standard Test Method for Potential Alkali Reactivity of Cement-Aggregate Combinations 

(Mortar-Bar Method),” March 2010.

ASTM C295, “Standard Guide for Petrographic Examination of Aggregates for Concrete,” May 2012.

ASTM E185-82, “Standard Practice for Conducting Surveillance Tests for Light-Water Cooled Nuclear Power 

Reactor Vessels,” January 1, 1982.

Crane Manufacturers Association of America (CMAA)

CMAA Specification 70, 2000.

Electric Power Research Institute (EPRI):

EPRI Boiling Water Reactor Vessel and Internals Project (BWRVIP)-05, “Reactor Pressure Vessel Shell Weld 

Inspection Guidelines,” September 1995.

BWRVIP-14-A, “BWR Vessel and Internals Project, Evaluation of Crack Growth in BWR Stainless Steel RPV 

Internals,” September 2008. Proprietary information. Not publicly available.

BWRVIP-18 A, “BWR Vessel and Internals Project, BWR Core Spray Internals Inspection and Flaw Evaluation 

Guidelines,” Revision 1, February 2005. Proprietary information. Not publicly available.

BWRVIP-25, “BWR Core Plate Inspection and Flaw Evaluation Guidelines,” December 1996. Proprietary 

information. Not publicly available.

BWRVIP-26-A, “BWR Top Guide Inspection and Flaw Evaluation Guidelines,” November 2004.

BWRVIP-27-A, “BWR Vessel and Internals Project, BWR Standby Liquid Control System/Core Plate ΔP Inspection 

and Flaw Evaluation Guidelines,” August 2003. Proprietary information. Not publicly available.

BWRVIP-38, “BWR Shroud Support Inspection and Flaw Evaluation Guidelines,” September 1997.

BWRVIP-41, “BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines,” September 2005.

BWRVIP-42-A, “BWR Vessel and Internals Project Boiling Water Reactor Low Pressure Coolant Injection and 

Flaw Evaluation Guidelines,” February 2005.

BWRVIP-47-A, “BWR Lower Plenum Inspection and Flaw Evaluation Guidelines,” November 2004. Proprietary 

information. Not publicly available.

BWRVIP-48-A, “BWR Vessel and Internals Project, Vessel ID Attachment Weld Inspection and Flaw Evaluation 

Guidelines,” November 2004. Proprietary information. Not publicly available.

BWRVIP-49-A, “BWR Vessel and Internals Project, Instrument Penetration Inspection and Flaw Evaluation 

Guidelines,” March 2002. Proprietary information. Not publicly available.

BWRVIP-74-A, “Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines,” June 2003. Proprietary 

information. Not publicly available.

BWRVIP-75-A, “BWR Vessel and Internals Project, Technical Basis for Revisions to Generic Letter 88-01

Inspection Schedules,” October 2005. Proprietary information. Not publicly available.

BWRVIP-76, Revision 1, “BWR Core Shroud Inspection and Flaw Evaluation Guidelines,” May 2011. Proprietary 

information. Not publicly available.

BWRVIP-76-A, “BWR Core Shroud Inspection and Flaw Evaluation Guidelines,” November 2009. Proprietary 

information. Not publicly available.

BWRVIP-86-A, “Updated BWR Integrated Surveillance Program (ISP) Implementation Plan," October 2002. 

Proprietary information. Not publicly available.

BWRVIP-86, Revision 1-A, “Updated BWR Integrated Surveillance Program (ISP) Implementation Plan,” 

October 2012. Proprietary information. Not publicly available.

BWRVIP-99-A, “Crack Growth Rates in Irradiated Stainless Steels in BWR Internal Components,” October 2008. 

Proprietary information. Not publicly available.
D-5

Industry Codes and Standards, By Source

BWRVIP-100-A, “BWR Vessel and Internals Project, Updated Assessment of the Fracture Toughness of Irradiated 

Stainless Steel for BWR Core Shrouds,” August 2006. Proprietary information. Not publicly available.

BWRVIP-114NP-A, “RAMA Fluence Methodology Theory Manual,” June 2009.

BWRVIP-115NP-A, “RAMA Fluence Methodology Benchmark Manual – Evaluation of Regulatory Guide 1.190 

Benchmark Problems,” December 2009.

BWRVIP-117NP-A, “RAMA Fluence Methodology Plant Application – Susquehanna Unit 2 Surveillance Capsule 

Fluence Evaluation for Cycles 1 – 5,” December 2009.

BWRVIP-121NP-A, “RAMA Fluence Methodology Procedures Manual,” June 2009.

BWRVIP-135, “BWRVIP ISP Data Source Book and Plant Evaluations,” Revision 2, October 2009. Proprietary 

information. Not publicly available.

BWRVIP-135, “BWRVIP ISP Data Source Book and Plant Evaluations,” Revision 3, December 15, 2014.

Proprietary information. Not publicly available.

BWRVIP-183 “BWR Vessel and Internals Project, Top Guide Grid Beam Inspection and Flaw Evaluation 

Guidelines,” December 2007.

BWRVIP-190, “BWR Vessel and Internals Project, Volume 1, ’BWR Water Chemistry Guidelines – Mandatory, 

Needed, and Good Practice Guidance and Volume 2: BWR Water Chemistry Guidelines – Technical Basis,’”

Revision 1, April 24, 2014. Proprietary information. Not publicly available.

BWRVIP-250NP, “Testing and Evaluation of the LaSalle Unit 1 120° Surveillance Capsule,” October 28, 2011.

BWRVIP-276, “Evaluation to Justify Core Plate Bolt Inspection Elimination,” September 2013.

EPRI Letter 2011-206, “Project No. 704 – BWRVIP 250NP: BWR Vessel and Internals Project, Testing and

Evaluation of the LaSalle Unit 1 120° Surveillance Capsule,” November 18, 2011 (Agencywide Documents Access 

and Management System (ADAMS) Accession No. ML11326A290).

EPRI Letter 2013-188, “Project No. 704 – BWRVIP 275NP: BWR Vessel and Internals Project, Testing and 

Evaluation of the Susquehanna Unit 1 120° Surveillance Capsule,” October 24, 2013 (ADAMS Accession 

No. ML13302A187).

EPRI TR-1007820, “Closed Cooling Water Chemistry Guideline, Revision 1: Revision 1 to TR-107396, Closed 

Cooling Water Chemistry Guideline,” April 2004.

EPRI NP-5769, “Degradation and Failure of Bolting in Nuclear Power Plants,” May 1988.

EPRI TR-1003057, “License Renewal Electrical Handbook,” December 2001.

EPRI TR-1010639, “Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 4,” 

January 2006.

EPRI TR-1013475, “Plant Support Engineering: License Renewal Electrical Handbook,” Revision 1 to EPRI 

TR-1003057, February 2007.

EPRI TR-104213, “Bolted Joint Maintenance & Applications Guide,” December 1995.

EPRI TR-1011837, “Residual Chromium Effects on Flow-Accelerated Corrosion of Carbon Steel,” March 27, 2006.

EPRI NSAC-202L-R2, “Recommendations for an Effective Flow Accelerated Corrosion Program,” Revision 2, 

April 8, 1999.

EPRI NSAC-202L-R3, “Recommendations for an Effective Flow Accelerated Corrosion Program,” Revision 3, 

August 10, 2007.

EPRI NSAC-202L-R4, “Recommendations for an Effective Flow Accelerator Corrosion Program,” Revision 4, 

November 26, 2013.

General Electric (GE) Reports:

GE-NE-523-A71-0594-A, Revision 1, “Alternate BWR Feedwater Nozzle Inspection Requirements,” May 2000.

GE NEDC-32399-P, “Basis for GE RTNDT Estimation Method,” September 1994.
D-6

Industry Codes and Standards, By Source

GE NEDC-32983P-A, “General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluations,” 

Revision 2, January 2006. Proprietary information. Not publicly available.

GE NEDC-33178P-A, “Licensing Topical Report GE Hitachi Nuclear Energy Methodology for Development of 

Reactor Pressure Vessel Pressure Temperature Curves,” June 2009.

GE NEDO-10029, “An Analytical Study on Brittle Fracture of GE-BWR Vessels Subject to the Design Basis 

Accident,” June 1969. Proprietary information. Not publicly available.

GE NEDO-24057-P, “Assessment of Reactor Internals Vibration in BWR/4 and BWR/5 Plants,” November 1977.

GE NEDO-32983-A, “General Electric Methodology for RPV Fast Neutron Flux Evaluations,” Revision 2, 

January 2006.

GE Letter to EPRI, “Relaxation of Core Plate Rim Hold-down Bolts,” June 29, 2006 (GE-EN-0000-0055-6793).

GEH Safety Communication (SC) 12-12, “Jet Pump Slip Joint Damage.”

GEH SC 12-14, “Jet Pump Slip Joint Installation.”

National Association of Corrosion Engineering (NACE) International:

NACE International Publication 05107, “Report on Corrosion Probes in Soil or Concrete,” 2007.

NACE SP0169-2007, “Control of External Corrosion on Underground or Submerged Metallic Piping Systems,” 

March 2007.

NACE website at http://www.naceinstitute.org/Certification.

National Fire Protection Association (NFPA):

NFPA 25, “Standard for Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems,” 2008, 

2011, and 2014.

Nuclear Energy Institute (NEI):

NEI 95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54 – The License Renewal 

Rule,” Revision 6, June 2005.

NUMARC 93-01, “Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,” 

Revision 2, April 1996.

Other Sources

B.F. Brown, “Stress-Corrosion Cracking in High Strength Steels and in Titanium and Aluminum Alloys,” Naval 

Research Laboratory, 1972.

Federal Register, page 64943 (56 FR 64943), December 13, 1991.

60 FR 22461, May 8, 1995.

61 FR 28467, June 5, 1996.

LaSalle County Station, Unit 1, Pressure/Temperature Limits Report, January 3, 2014 (ADAMS Accession 

No. ML13358A365).

Ranganath, S., “Fracture Mechanics Evaluation of a Boiling Water Reactor Vessel Following a Postulated Loss of 

Coolant Accident,” Fifth International Conference on Structural Mechanics in Reactor Technology, Berlin, 

Germany, August 1979.

The staff reviewed the following website: http://www.tubes-international.com/tygon_tubing.html.




NUREG

-2205 Safety Evaluation Report Related to the License Renewal of 

LaSalle County Station, Units 1 and 2