Safety Evaluation Report 

Related to the License 

Renewal of Limerick 

Generating Station, 

Units 1 and 2

Office of Nuclear Reactor Regulation

NUREG-2171
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Safety Evaluation Report 

Related to the License 

Renewal of Limerick 

Generating Station, 

Units 1 and 2

Docket Nos. 50-352 and 50-353

Manuscript Completed: September 2014

Date Published: September 2014

Office of Nuclear Reactor Regulation

NUREG-2171

iii

ABSTRACT

This safety evaluation report (SER) documents the technical review of the Limerick Generating 

Station (LGS), Units 1 and 2, license renewal application (LRA) by the United States Nuclear 

Regulatory Commission (NRC) staff (the staff). By letter dated June 22, 2011, Exelon 

Generation Company, LLC submitted the LRA in accordance with Title 10 of the Code of 

Federal Regulations Part 54, “Requirements for Renewal of Operating Licenses for Nuclear 

Power Plants.” Exelon requests renewal of the LGS Units 1 and 2 operating licenses

(Operating License Nos. NPF-39 and NPF-85) for a period of 20 years beyond the current 

expiration at midnight October 26, 2024, and June 22, 2029, respectively.

LGS is located approximately 21 miles northwest of Philadelphia, PA. The NRC issued the

LGS Units 1 and 2 construction permits on June 19, 1974, and the operating licenses for LGS 

Unit 1 on August 8, 1985, and LGS Unit 2 on August 25, 1989. LGS Units 1 and 2 are of a 

boiling-water reactor design. General Electric supplied the nuclear steam supply system and 

Bechtel originally designed and constructed the balance of the plant. LGS Units 1 and 2 both 

have a licensed power output of 3,515 megawatts thermal.

v

TABLE OF CONTENTS

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

LIST OF TABLES....................................................................................................................xiii

ABBREVIATIONS ....................................................................................................................xv

SECTION 1 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 of Open Items.............................................................................. 1-7

1.6 Summary of Confirmatory Items .................................................................. 1-8

1.7 Summary of Proposed License Conditions .................................................. 1-8

SECTION 2 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 Implementation Procedures and Documentation 

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

2.1.3.2 Quality Controls Applied to LRA Development .................... 2-5

2.1.3.3 Training............................................................................... 2-6

2.1.3.4 Conclusion of Scoping and Screening Program Review...... 2-6

2.1.4 Plant Systems, Structures, and Components Scoping 

Methodology .................................................................................... 2-7

2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1)..... 2-7

2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2)..... 2-9

2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3)... 2-18

2.1.4.4 Plant-Level Scoping of Systems and Structures................ 2-20

2.1.4.5 Mechanical Component Scoping....................................... 2-21

2.1.4.6 Structural Component Scoping ......................................... 2-23

2.1.4.7 Electrical Component Scoping .......................................... 2-24

2.1.4.8 Conclusion for Scoping Methodology ................................ 2-25

2.1.5 Screening Methodology ................................................................... 2-25

2.1.5.1 General Screening Methodology....................................... 2-25

2.1.5.2 Mechanical Component Screening.................................... 2-27

2.1.5.3 Structural Component Screening ...................................... 2-28

2.1.5.4 Electrical Component Screening ....................................... 2-29

2.1.5.5 Conclusion for Screening Methodology............................. 2-29

2.1.6 Summary of Evaluation Findings ..................................................... 2-30

2.2 Plant-Level Scoping Results...................................................................... 2-30

2.2.1 Introduction...................................................................................... 2-30

2.2.2 Summary of Technical Information in the Application....................... 2-30

2.2.3 Staff Evaluation ............................................................................... 2-30

2.2.4 Conclusion....................................................................................... 2-31

2.3 Scoping and Screening Results: Mechanical Systems............................... 2-31

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System.................. 2-32
vi

2.3.1.1 Reactor Coolant Pressure Boundary................................. 2-33

2.3.1.2 Reactor Pressure Vessel .................................................. 2-34

2.3.1.3 Reactor Vessel Internals ................................................... 2-35

2.3.2 Engineered Safety Features ............................................................ 2-36

2.3.2.1 Containment Atmosphere Control System ........................ 2-36

2.3.2.2 Core Spray System........................................................... 2-37

2.3.2.3 High Pressure Coolant Injection System ........................... 2-37

2.3.2.4 Reactor Core Isolation Cooling System............................. 2-38

2.3.2.5 Residual Heat Removal System........................................ 2-39

2.3.2.6 Standby Gas Treatment System ....................................... 2-41

2.3.3 Auxiliary Systems ............................................................................ 2-41

2.3.3.1 Auxiliary Steam System .................................................... 2-43

2.3.3.2 Closed Cooling Water System .......................................... 2-44

2.3.3.3 Compressed Air System ................................................... 2-45

2.3.3.4 Control Enclosure Ventilation System ............................... 2-45

2.3.3.5 Control Rod Drive System................................................. 2-47

2.3.3.6 Cranes and Hoists ............................................................ 2-48

2.3.3.7 Emergency Diesel Generator Enclosure Ventilation 

System.............................................................................. 2-48

2.3.3.8 Emergency Diesel Generator System ............................... 2-50

2.3.3.9 Fire Protection System...................................................... 2-52

2.3.3.10 Fuel Handling and Storage System................................. 2-57

2.3.3.11 Fuel Pool Cooling and Cleanup System.......................... 2-57

2.3.3.12 Nonsafety-Related Service Water System ...................... 2-58

2.3.3.13 Plant Drainage System ................................................... 2-59

2.3.3.14 Primary Containment Instrument Gas System................. 2-60

2.3.3.15 Primary Containment Leak Testing System..................... 2-62

2.3.3.16 Primary Containment Ventilation System ........................ 2-62

2.3.3.17 Process Radiation Monitoring System............................. 2-64

2.3.3.18 Process and Post-Accident Sampling System................. 2-65

2.3.3.19 Radwaste System ........................................................... 2-66

2.3.3.20 Reactor Enclosure Ventilation System ............................ 2-67

2.3.3.21 Reactor Water Cleanup System...................................... 2-69

2.3.3.22 Safety-Related Service Water System ............................ 2-69

2.3.3.23 Spray Pond Pump House Ventilation System.................. 2-71

2.3.3.24 Standby Liquid Control System ....................................... 2-73

2.3.3.25 Traversing Incore Probe System..................................... 2-74

2.3.3.26 Water Treatment and Distribution System....................... 2-74

2.3.4 Steam and Power Conversion Systems........................................... 2-75

2.3.4.1 Circulating Water System.................................................. 2-76

2.3.4.2 Condensate System.......................................................... 2-77

2.3.4.3 Condenser and Air Removal System ................................ 2-77

2.3.4.4 Extraction Steam System.................................................. 2-78

2.3.4.5 Feedwater System ............................................................ 2-79

2.3.4.6 Main Steam System.......................................................... 2-80

2.3.4.7 Main Turbine..................................................................... 2-81

2.4 Scoping and Screening Results: Structures............................................... 2-82

2.4.1 220 and 500 kV Substations ............................................................ 2-83

2.4.1.1 Summary of Technical Information in the Application........ 2-83

2.4.1.2 Staff Evaluation................................................................. 2-84
vii

2.4.1.3 Conclusion ........................................................................ 2-84

2.4.2 Admin Building Shop and Warehouse.............................................. 2-84

2.4.2.1 Summary of Technical Information in the Application........ 2-84

2.4.2.2 Staff Evaluation................................................................. 2-85

2.4.2.3 Conclusion ........................................................................ 2-85

2.4.3 Auxiliary Boiler and Lube Oil Storage Enclosure.............................. 2-85

2.4.3.1 Summary of Technical Information in the Application........ 2-85

2.4.3.2 Staff Evaluation................................................................. 2-86

2.4.3.3 Conclusion ........................................................................ 2-86

2.4.4 Circulating Water Pump House........................................................ 2-86

2.4.4.1 Summary of Technical Information in the Application........ 2-86

2.4.4.2 Staff Evaluation................................................................. 2-86

2.4.4.3 Conclusion ........................................................................ 2-87

2.4.5 Component Supports Commodities Group....................................... 2-87

2.4.5.1 Summary of Technical Information in the Application........ 2-87

2.4.5.2 Staff Evaluation................................................................. 2-87

2.4.5.3 Conclusion ........................................................................ 2-87

2.4.6 Control Enclosure ............................................................................ 2-88

2.4.6.1 Summary of Technical Information in the Application........ 2-88

2.4.6.2 Staff Evaluation................................................................. 2-88

2.4.6.3 Conclusion ........................................................................ 2-89

2.4.7 Cooling Towers................................................................................ 2-89

2.4.7.1 Summary of Technical Information in the Application........ 2-89

2.4.7.2 Staff Evaluation................................................................. 2-89

2.4.7.3 Conclusion ........................................................................ 2-90

2.4.8 Diesel Oil Storage Tank Structures.................................................. 2-90

2.4.8.1 Summary of Technical Information in the Application........ 2-90

2.4.8.2 Staff Evaluation................................................................. 2-90

2.4.8.3 Conclusion ........................................................................ 2-91

2.4.9 Emergency Diesel Generator Enclosure .......................................... 2-91

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

2.4.9.2 Staff Evaluation................................................................. 2-92

2.4.9.3 Conclusion ........................................................................ 2-92

2.4.10 Piping and Component Insulation Commodity Group..................... 2-92

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

2.4.10.2 Staff Evaluation............................................................... 2-92

2.4.10.3 Conclusion ...................................................................... 2-92

2.4.11 Primary Containment ..................................................................... 2-93

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

2.4.11.2 Staff Evaluation............................................................... 2-93

2.4.11.3 Conclusion ...................................................................... 2-93

2.4.12 Radwaste Enclosure...................................................................... 2-93

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

2.4.12.2 Staff Evaluation............................................................... 2-94

2.4.12.3 Conclusion ...................................................................... 2-94

2.4.13 Reactor Enclosure ......................................................................... 2-94

2.4.13.1 Summary of Technical Information in the Application...... 2-94

2.4.13.2 Staff Evaluation............................................................... 2-95

2.4.13.3 Conclusion ...................................................................... 2-95

2.4.14 Service Water Pipe Tunnel ............................................................ 2-95
viii

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

2.4.14.2 Staff Evaluation............................................................... 2-95

2.4.14.3 Conclusion ...................................................................... 2-96

2.4.15 Spray Pond and Pump House........................................................ 2-96

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

2.4.15.2 Staff Evaluation............................................................... 2-96

2.4.15.3 Conclusion ...................................................................... 2-97

2.4.16 Turbine Enclosure.......................................................................... 2-97

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

2.4.16.2 Staff Evaluation............................................................... 2-97

2.4.16.3 Conclusion ...................................................................... 2-97

2.4.17 Yard Facilities ................................................................................ 2-97

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

2.4.17.2 Staff Evaluation............................................................... 2-98

2.4.17.3 Conclusion ...................................................................... 2-98

2.5 Scoping and Screening Results: Electrical................................................. 2-98

2.5.1 Electrical and Instrumentation and Controls Commodity Groups ..... 2-99

2.5.1.1 Summary of Technical Information in the Application........ 2-99

2.5.1.2 Staff Evaluation................................................................. 2-99

2.5.1.3 Conclusion ...................................................................... 2-101

2.6 Conclusion for Scoping and Screening .................................................... 2-101

SECTION 3 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 1s .......................................................... 3-2

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

3.0.2 Staff’s Review Process ...................................................................... 3-4

3.0.2.1 Review of AMPs.................................................................. 3-5

3.0.2.2 Review of AMR Results ...................................................... 3-6

3.0.2.3 UFSAR Supplement............................................................ 3-7

3.0.2.4 Documentation and Documents Reviewed.......................... 3-7

3.0.3 Aging Management Programs ........................................................... 3-8

3.0.3.1 AMPs Consistent with the GALL Report............................ 3-11

3.0.3.2 AMPs Consistent with the GALL Report with Exceptions 

or Enhancements.............................................................. 3-80

3.0.4 QA Program Attributes Integral to Aging Management Programs .. 3-169

3.0.4.1 Summary of Technical Information in the Application...... 3-169

3.0.4.2 Staff Evaluation............................................................... 3-170

3.0.4.3 Conclusion ...................................................................... 3-171

3.0.5 Operating Experience for Aging Management Programs ............... 3-171

3.0.5.1 Summary of Technical Information in Application............ 3-171

3.0.5.2 Staff Evaluation............................................................... 3-171

3.0.5.3 UFSAR Supplement........................................................ 3-178

3.0.5.4 Conclusion ...................................................................... 3-179

3.1 Aging Management of Reactor Vessel, Internals and Reactor Coolant 

System .................................................................................................... 3-180

3.1.1 Summary of Technical Information in the Application..................... 3-180

3.1.2 Staff Evaluation ............................................................................. 3-180

3.1.2.1 AMR Results Consistent with the GALL Report............... 3-203
ix

3.1.2.2 AMR Results Consistent with the GALL Report for 

Which Further Evaluation is Recommended ................... 3-217

3.1.2.3 AMR Results Not Consistent with or Not Addressed in 

the GALL Report............................................................. 3-225

3.1.3 Conclusion..................................................................................... 3-229

3.2 Aging Management of Engineered Safety Features Systems .................. 3-229

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

3.2.2 Staff Evaluation ............................................................................. 3-230

3.2.2.1 AMR Results Consistent with the GALL Report............... 3-241

3.2.2.2 AMR Results Consistent with the GALL Report for 

Which Further Evaluation is Recommended ................... 3-249

3.2.2.3 AMR Results Not Consistent with or Not Addressed in 

the GALL Report............................................................. 3-251

3.2.3 Conclusion..................................................................................... 3-255

3.3 Aging Management of Auxiliary Systems................................................. 3-255

3.3.1 Summary of Technical Information in the Application..................... 3-256

3.3.2 Staff Evaluation ............................................................................. 3-256

3.3.2.1 AMR Results Consistent with the GALL Report............... 3-278

3.3.2.2 AMR Results Consistent with the GALL Report for 

Which Further Evaluation is Recommended ................... 3-300

3.3.2.3 AMR Results Not Consistent with or Not Addressed in 

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

3.3.3 Conclusion..................................................................................... 3-319

3.4 Aging Management of Steam and Power Conversion Systems ............... 3-319

3.4.1 Summary of Technical Information in the Application..................... 3-319

3.4.2 Staff Evaluation ............................................................................. 3-320

3.4.2.1 AMR Results Consistent with the GALL Report............... 3-329

3.4.2.2 AMR Results Consistent with the GALL Report for 

Which Further Evaluation is Recommended ................... 3-335

3.4.2.3 AMR Results Not Consistent with or Not Addressed in 

the GALL Report............................................................. 3-338

3.4.3 Conclusion..................................................................................... 3-341

3.5 Aging Management of Structures and Component Supports ................... 3-341

3.5.1 Summary of Technical Information in the Application..................... 3-342

3.5.2 Staff Evaluation ............................................................................. 3-342

3.5.2.1 AMR Results Consistent with the GALL Report............... 3-359

3.5.2.2 AMR Results Consistent with the GALL Report for 

Which Further Evaluation is Recommended ................... 3-366

3.5.2.3 AMR Results Not Consistent with or Not Addressed in 

the GALL Report............................................................. 3-380

3.5.3 Conclusion..................................................................................... 3-393

3.6 Aging Management of Electrical and Instrumentation and Controls 

System .................................................................................................... 3-393

3.6.1 Summary of Technical Information in the Application..................... 3-393

3.6.2 Staff Evaluation ............................................................................. 3-394

3.6.2.1 AMR Results Consistent with the GALL Report............... 3-400

3.6.2.2 AMR Results Consistent with the GALL Report for 

Which Further Evaluation is Recommended ................... 3-405

3.6.2.3 AMR Results Not Consistent with or Not Addressed in 

the GALL Report............................................................. 3-410
x

3.6.3 Conclusion..................................................................................... 3-413

3.7 Conclusion for Aging Management Review Results................................. 3-413

SECTION 4 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

4.1.2 Staff Evaluation ................................................................................. 4-3

4.1.3 UFSAR Supplement ........................................................................ 4-19

4.1.4 Conclusion....................................................................................... 4-19

4.2 Reactor Vessel Neutron Embrittlement...................................................... 4-19

4.2.1 Neutron Fluence .............................................................................. 4-20

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

4.2.1.2 Staff Evaluation................................................................. 4-21

4.2.1.3 UFSAR Supplement.......................................................... 4-23

4.2.1.4 Conclusion ........................................................................ 4-24

4.2.2 Upper-Shelf Energy ......................................................................... 4-24

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

4.2.2.2 Staff Evaluation................................................................. 4-24

4.2.2.3 UFSAR Supplement.......................................................... 4-25

4.2.2.4 Conclusion ........................................................................ 4-26

4.2.3 Adjusted Reference Temperature .................................................... 4-26

4.2.3.1 Summary of Technical Information in the Application........ 4-26

4.2.3.2 Staff Evaluation................................................................. 4-27

4.2.3.3 UFSAR Supplement.......................................................... 4-27

4.2.3.4 Conclusion ........................................................................ 4-28

4.2.4 Pressure – Temperature (P-T) Limits............................................... 4-28

4.2.4.1 Summary of Technical Information in the Application........ 4-28

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

4.2.4.3 UFSAR Supplement.......................................................... 4-29

4.2.4.4 Conclusion ........................................................................ 4-29

4.2.5 Axial Weld Inspection ...................................................................... 4-29

4.2.5.1 Summary of Technical Information in the Application........ 4-29

4.2.5.2 Staff Evaluation................................................................. 4-30

4.2.5.3 UFSAR Supplement.......................................................... 4-30

4.2.5.4 Conclusion ........................................................................ 4-30

4.2.6 Circumferential Weld Inspection ...................................................... 4-31

4.2.6.1 Summary of Technical Information in the Application........ 4-31

4.2.6.2 Staff Evaluation................................................................. 4-31

4.2.6.3 UFSAR Supplement.......................................................... 4-32

4.2.6.4 Conclusion ........................................................................ 4-33

4.2.7 Reactor Vessel Reflood Thermal Shock .......................................... 4-33

4.2.7.1 Summary of Technical Information in the Application........ 4-33

4.2.7.2 Staff Evaluation................................................................. 4-33

4.2.7.3 UFSAR Supplement.......................................................... 4-34

4.2.7.4 Conclusion ........................................................................ 4-34

4.3 Metal Fatigue............................................................................................. 4-34

4.3.1 ASME Code Section III, Class 1 Fatigue Analysis............................ 4-34

4.3.1.1 Summary of Technical Information in the Application........ 4-34

4.3.1.2 Staff Evaluation................................................................. 4-35

4.3.1.3 UFSAR Supplement.......................................................... 4-39

4.3.1.4 Conclusion ........................................................................ 4-39
xi

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

Stress Calculations ........................................................................ 4-40

4.3.2.1 Summary of Technical Information in the Application........ 4-40

4.3.2.2 Staff Evaluation................................................................. 4-40

4.3.2.3 UFSAR Supplement.......................................................... 4-44

4.3.2.4 Conclusion ........................................................................ 4-44

4.3.3 Environmental Fatigue Analyses for RPV and Class 1 Piping.......... 4-45

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

4.3.3.2 Staff Evaluation................................................................. 4-45

4.3.3.3 UFSAR Supplement.......................................................... 4-57

4.3.3.4 Conclusion ........................................................................ 4-58

4.3.4 Reactor Vessel Internals (RVI) Fatigue Analyses............................. 4-58

4.3.4.1 Summary of Technical Information in the Application........ 4-58

4.3.4.2 Staff Evaluation................................................................. 4-58

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

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

4.3.5 High-Energy Line Break (HELB) Analyses Based Upon Fatigue...... 4-62

4.3.5.1 Summary of Technical Information in the Application........ 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

4.4 Environmental Qualification of Electric Equipment..................................... 4-64

4.4.1 Summary of Technical Information in the Application....................... 4-64

4.4.2 Staff Evaluation ............................................................................... 4-64

4.4.3 UFSAR Supplement ........................................................................ 4-65

4.4.4 Conclusion....................................................................................... 4-65

4.5 Containment Liner Plate and Penetration Fatigue Analyses ...................... 4-66

4.5.1 Summary of Technical Information in the Application....................... 4-66

4.5.2 Staff Evaluation ............................................................................... 4-66

4.5.3 UFSAR Supplement ........................................................................ 4-68

4.5.4 Conclusion....................................................................................... 4-68

4.6 Other Plant-Specific TLAAs ....................................................................... 4-68

4.6.1 Reactor Enclosure Crane Cyclic Loading Analysis........................... 4-68

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

4.6.1.2 Staff Evaluation................................................................. 4-69

4.6.1.3 UFSAR Supplement.......................................................... 4-69

4.6.1.4 Conclusion ........................................................................ 4-70

4.6.2 Emergency Diesel Generator Enclosure Cranes............................. 4-70

4.6.2.1 Summary of Technical Information in the Application........ 4-70

4.6.2.2 Staff Evaluation................................................................. 4-70

4.6.2.3 UFSAR Supplement.......................................................... 4-71

4.6.2.4 Conclusion ........................................................................ 4-71

4.6.3 RPV Core Plate Rim Hold-down Bolt Loss of Preload..................... 4-71

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

4.6.3.2 Staff Evaluation................................................................. 4-72

4.6.3.3 UFSAR Supplement.......................................................... 4-72

4.6.3.4 Conclusion ........................................................................ 4-72

4.6.4 Main Steam Line Flow Restrictors Erosion...................................... 4-73

4.6.4.1 Summary of Technical Information in the Application........ 4-73

4.6.4.2 Staff Evaluation................................................................. 4-73
xii

4.6.4.3 UFSAR Supplement.......................................................... 4-74

4.6.4.4 Conclusion ........................................................ 4-74

4.6.5 Jet Pump Auxiliary Spring Wedge Assembly .................................. 4-74

4.6.5.1 Summary of Technical Information in the Application........ 4-74

4.6.5.2 Staff Evaluation................................................................. 4-75

4.6.5.3 UFSAR Supplement.......................................................... 4-77

4.6.5.4 Conclusion ........................................................................ 4-78

4.6.6 Jet Pump Restrainer Bracket Pad Repair Clamps........................... 4-78

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

4.6.6.2 Staff Evaluation................................................................. 4-78

4.6.6.3 UFSAR Supplement.......................................................... 4-80

4.6.6.4 Conclusion ........................................................................ 4-80

4.6.7 Refueling Bellows and Support Cyclic Loading Analysis .................. 4-80

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

4.6.7.2 Staff Evaluation................................................................. 4-81

4.6.7.3 UFSAR Supplement.......................................................... 4-82

4.6.7.4 Conclusion ........................................................................ 4-82

4.6.8 Downcomers and MSRV Discharge Piping...................................... 4-82

4.6.8.1 Summary of Technical Information in the Application........ 4-82

4.6.8.2 Staff Evaluation................................................................. 4-83

4.6.8.3 UFSAR Supplement.......................................................... 4-87

4.6.8.4 Conclusion ........................................................................ 4-87

4.6.9 Jet Pump Slip Joint Repair Clamps.................................................. 4-87

4.6.9.1 Summary of Technical Information in the Application........ 4-87

4.6.9.2 Staff Evaluation................................................................. 4-88

4.6.9.3 UFSAR Supplement.......................................................... 4-89

4.6.9.4 Conclusion ........................................................................ 4-89

4.6.10 Fuel Pool Girder Loss of Prestress ................................................ 4-89

4.6.10.1 Summary of Technical Information in the Application...... 4-89

4.6.10.2 Staff Evaluation............................................................... 4-90

4.6.10.3 UFSAR Supplement........................................................ 4-91

4.6.10.4 Conclusion ...................................................................... 4-91

4.6.11 RHR and Core Spray Suction Strainer Fatigue Analysis ................ 4-91

4.6.11.1 Summary of Technical Information in the Application...... 4-91

4.6.11.2 Staff Evaluation............................................................... 4-91

4.6.11.3 UFSAR Supplement........................................................ 4-93

4.6.11.4 Conclusion ...................................................................... 4-93

4.7 Conclusion for TLAAs................................................................................ 4-93

SECTION 5 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS ... 5-1

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

Appendices

APPENDIX A: Limerick Generating Station, Units 1 and 2 License Renewal 

 Commitments ...............................................................................................A-1

APPENDIX B: Chronology...................................................................................................B-1

APPENDIX C: Principal Contributors..................................................................................C-1

APPENDIX D: References....................................................................................................D-1
xiii

LIST OF TABLES

Table 1.4-1 Current Interim Staff Guidance......................................................................... 1-7

Table 3.0.3-1 Aging Management Programs.......................................................................... 3-8

Table 3.1-1 Staff Evaluation for Reactor Vessel, Reactor Vessel Internals and 

 Reactor Coolant System Components in the SRP-LR .................................. 3-181

Table 3.2-1 Staff Evaluation for Engineered Safety Features Systems Components 

 in the GALL Report..................................................................................... 3-2311

Table 3.3-1 Staff Evaluation for Auxiliary Systems Components in the GALL Report...... 3-257

Table 3.4-1 Staff Evaluation for Steam and Power Conversion Systems Components 

 in the GALL Report....................................................................................... 3-321

Table 3.5-1 Staff Evaluation for Structures and Component Supports Components 

 in the GALL Report....................................................................................... 3-343

Table 3.6-1 Staff Evaluation for Electrical and Instrumentation and Controls 

 Components in the GALL Report.................................................................. 3-395

xv

ABBREVIATIONS

AAI applicant action item

ACI American Concrete Institute

ACRS Advisory Committee on Reactor Safeguards

ADAMS Agencywide Documents Access and Management System

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

ASCE American Society of Civil Engineers

ASME American Society of Mechanical Engineers

AST alternate source term

ASTM American Society for Testing and Materials

ATWS anticipated transient without scram

B&W Babcock and Wilcox

BTP branch technical position

BWR boiling-water reactor

BWRVIP Boiling Water Reactor Vessel Integrity Project

CAP corrective action program

CASS cast austenitic stainless steel

CFR Code of Federal Regulations

CLB current licensing basis

CMAA Crane Manufacturers Association of America

CMRT certified material test record

CRD control rod drive

CRL component record list

CSC containment spray cooling

CS core spray

CST condensate storage tank

Cu copper

CUF cumulative usage factor

CuFen environmentally adjusted fatigue usage factor

CW circulating water

DBA design-basis accident

DBE design-basis event

EAF environmentally assisted fatigue

ECCS emergency core cooling system

EDG emergency diesel generator

EFPY effective full-power year

EMA equivalent margins analysis

EPRI Electric Power Research Institute

EQ environmental qualification
xvi

ESF engineered safety features

ESW emergency service water

Fen environmental fatigue life correction factor

FERC Federal Energy Regulatory Commission

FIV flow induced vibration

FR Federal Register

ft-lb foot-pound

GALL Generic Aging Lessons Learned Report

GDC general design criteria or general design criterion

GE General Electric

GEIS generic environmental impact statement

GL generic letter

GSI generic safety issue

HELB high-energy line break

HPCI high-pressure coolant injection

HPSI high-pressure safety injection

HVAC heating, ventilation, and air conditioning

I&C instrumentation and controls

IASCC irradiation assisted stress corrosion cracking

ICMH in-core monitoring housing

ID inside diameter

IGSCC intergranular stress corrosion cracking

ILRT integrated leak rate test

IN information notice

INPO Institute of Nuclear Power Operations

IPA integrated plant assessment

ISG interim staff guidance

ISI inservice inspection

ISP Integrated Surveillance Program

kV kilovolt

LBB leak-before-break

LER licensee event report

LGS Limerick Generating Station

LLRT local leak rate test

LOCA loss-of-coolant accident

LPCI low-pressure coolant injection

LPRM low-power range monitor

LRA license renewal application

LTOP low-temperature overpressure protection

MC metal containment

MEB metal enclosed bus

MIC microbiologically influenced corrosion

MoS2 molybdenum disulfide
xvii

MSIP mechanical stress improvement process

MSIV main steam isolation valve

MSRV main steam relief valve

MUR measurement uncertainty recapture

n/cm2 neutrons per square centimeter

NDE nondestructive examination

NEI Nuclear Energy Institute

NFPA National Fire Protection Association

Ni nickel

NPS nominal pipe size

NRC U.S. Nuclear Regulatory Commission

NRR Office of Nuclear Reactor Regulation

OBE operational basis earthquake

OE operating experience

OI open item

PCIG primary containment instrument gas

PDL Plastics Design Library

pH potential of hydrogen

P&ID plant piping and instrumentation drawing

PoF probability of failure

P-T pressure-temperature

PTS pressurized thermal shock

PVC polyvinyl chloride

PWR pressurized-water reactor

PWSCC primary water stress corrosion cracking

QA quality assurance

QAP quality assurance program

RAI request for additional information

RAMA Radiation Analysis Modeling Application

RCIC reactor core isolation cooling

RCP reactor coolant pump

RCPB reactor coolant pressure boundary

RCS reactor coolant system

RCSC Research Council for Structural Connections

RG regulatory guide

RHR residual heat removal

RHRSW residual heat removal service water

RI-ISI risk-informed inservice inspection

RPV reactor pressure vessel

RTNDT reference temperature nil ductility transition

RVI reactor vessel internals

RWCU reactor water cleanup
xviii

SBO station blackout

SC structure and component

SCC stress corrosion cracking

SDC shutdown cooling

SDV scram discharge volume

SER safety evaluation report

SGTS standby gas treatment system

SLC standby liquid control

SOER significant operating experience reports

SPC suppression pool cooling

SPU stretch power uprate

SRP standard review plan

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

Power Plants”

SRV safety relief valve

SSC system, structure, and component

SSE safe-shutdown earthquake

SW service water

TIP traversing in-core probe

TLAA time-limited aging analysis

TS technical specifications

TTA tolyltriazole

UFSAR updated final safety analysis report

USE upper-shelf energy

UT ultrasonic examination

UV ultraviolet

VFLD vessel flange leak detector

WLI water level instrumentation

WTD water treatment and distribution

yr year

Zn zinc
1-1

SECTION 1

INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

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

Limerick Generating Station (LGS), Units 1 and 2, as filed by Exelon Generation Company, LLC

(Exelon or the applicant). By letter dated June 22, 2011, Exelon submitted its application to the 

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

licenses for an additional 20 years. 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 (10 

CFR) Part 54, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants.”

The NRC project manager for the license renewal review is Robert Kuntz. Mr. Kuntz may be 

contacted by telephone at 301-415-3733 or by email at robert.kuntz@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: Robert Kuntz, Mail Stop 011-F1

In its June 22, 2011, submission letter, the applicant requested renewal of the operating 

licenses issued under Section 103 (Operating Licenses No. NPF-39 and NPF-85) of the Atomic 

Energy Act of 1954, as amended, for LGS Units 1 and 2 for a period of 20 years beyond the 

current expiration at midnight October 26, 2024, and June 22, 2029, respectively. LGS is 

located approximately 21 miles northwest of Philadelphia, PA. The NRC issued the LGS

Units 1 and 2 construction permits on June 19, 1974, and the operating license for LGS Unit 1

on August 8, 1985, and LGS Unit 2 on August 25, 1989. LGS Units 1 and 2 are of a

boiling-water reactor design. General Electric supplied the nuclear steam supply system and 

Bechtel originally designed and constructed the balance of the plant. LGS Units 1 and 2 both

have a licensed power output of 3,515 megawatts thermal. The updated final safety analysis 

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

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

issues and an environmental review. The NRC regulations in 10 CFR Part 54 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 LGS 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 July 11, 2012. 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, Rockville, MD 20852-2738 (301-415-4737 or 800-397-4209), and at 

Pottstown Regional Public Library, 500 East High Street, Pottstown, PA 19464-5656. In 
1-2

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

on the NRC website 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 proposed operation of Units 1 

and 2 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), issued 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 SER conclusions 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 LGS Units 1 and 2. The staff plans to issue a draft, plant-specific GEIS supplement. 

The final, plant-specific GEIS supplement will then be issued after consideration of public 

comment on the draft plant-specific GEIS.

1.2 License Renewal Background

Pursuant to 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, 

page 64943, of the Federal Register (FR) (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 

license renewal. However, during the demonstration program, the staff found that adverse 

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

and that the scope of the review did not allow sufficient credit for management programs, 
1-3

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 May 8, 1995, (60 FR 22461), amended 10 CFR Part 54 establishes a simpler, 

more stable, and more predictable regulatory process 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 

(IPA) 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.

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 the NRC’s 

regulations for fire protection, environmental qualification (EQ), pressurized thermal shock 

(PTS), anticipated transient without scram (ATWS), and station blackout (SBO).

Pursuant to 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. Pursuant to 10 CFR 54.21(a), a license renewal applicant must

demonstrate that the aging effects will be managed such that the intended function(s) of those 

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

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.
1-4

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

a summary description of the applicant’s programs and activities for managing aging effects 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 (RG) 1.188, “Standard Format and Content for 

Applications to Renew Nuclear Power Plant Operating Licenses.” This RG 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 in 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 fully used the process defined in NUREG-1801, Revision 2, “Generic 

Aging Lessons Learned (GALL) Report,” issued 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 also is 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 

Regulations on environmental protection are contained in 10 CFR Part 51. 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. Pursuant to 10 CFR CFR 51.53(c)(3)(i), a 

license renewal applicant may incorporate these generic findings in its environmental report. In 

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

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

In accordance with the National Environmental Policy Act of 1969 and 10 CFR Part 51, the staff 

is reviewing the plant-specific environmental impacts of license renewal, including whether there 

is new and significant information not considered in the GEIS. As part of its scoping process, 

the staff held a public meeting on September 22, 2011, at the Sunnybrook Ballroom, 50 North 

Sunnybrook Road, Pottstown, PA 19464, to identify plant-specific environmental issues. The 

draft plant-specific GEIS supplement will document the results of the environmental review and 

will make a preliminary recommendation as to the license renewal action. The staff will hold
1-5

another public meeting to discuss the draft plant-specific GEIS supplement. After considering 

comments on the draft, the staff will publish the final plant-specific Supplement to the GEIS 

separately from this report.

1.3 Principal Review Matters

Requirements for renewal of operating licenses for nuclear power plants are described in 

10 CFR Part 54. The staff’s technical review of the LRA was in accordance with NRC guidance 

and 10 CFR Part 54 requirements. The license renewal standards are set forth in 

10 CFR 54.29, “Standards for Issuance of a Renewed License.” 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, to account for the 

expiration term of the proposed renewed license.” On this issue, the applicant stated in the 

LRA:

10 CFR 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 (B-101) for LGS 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 number SNM-1926. 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 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 IPA, (b) a description of any CLB changes during the staff’s 

review of the LRA, (c) an evaluation of TLAAs, and (d) an 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).
1-6

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 June 14, 2012, the 

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

during the staff’s review of the LRA. This submission satisfies 10 CFR 54.21(b) requirements.

Pursuant to 10 CFR 54.22, “Contents of Application – Technical Specifications,” the NRC 

requires that the LRA include changes or additions to the technical specifications (TS) 

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

Appendix D, the applicant stated that it had not identified any TS changes necessary for 

issuance of the renewed LGS Units 1 and 2 operating licenses. This statement adequately 

addresses the 10 CFR 54.22 requirements.

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,”

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.

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 

incorporated into such license renewal guidance documents as the SRP-LR and the 

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

Table 1.4-1 Current Interim Staff Guidance

ISG Issue

(Approved ISG Number)

Purpose SER Section

“Staff Guidance for Preparing 

Severe Accident Mitigation 

Alternatives Analyses”

(LR-ISG-2006-03)

This ISG is related to severe 

accident management alternatives 

for environmental impact 

statements

N/A for the SER

“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

1.5 Summary of Open Items

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

July 11, 2012, the staff had identified the following open items (OI) when it issued the SER with 

Open Items on July 30, 2012. 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. The staff 

has assigned a unique identifying number to each OI.

Open Item 3.0.3.2.13-1 ASME Code Section XI, Subsection IWE

LGS Units 1 and 2 have seen corrosion in the suppression pool liner and downcomers. The 

applicant’s proposed aging management of the suppression pool liner and downcomers is within 

the scope of the American Society of Mechanical Engineers (ASME) Code Section XI, 

Subsection IWE program. As described in SER Section 3.0.3.2.13, the staff had an open item 

for aging management of the suppression pool liner and downcomers. Specifically, the open 

item was related to the following concerns:

 • The applicant has developed an acceptance criterion for the degradation of the 

downcomers; however, this criterion is not identified in the AMP or the associated 

procedures.

• The criteria used for selecting locations for recoating (i.e., criteria for coating 

degradation, general corrosion, and pitting corrosion) may not be adequate. In addition, 

it is not clear how the coating degradation can be effectively identified for each liner plate 

underwater in the suppression pool. Also, the applicant’s proposed criteria for 

augmented inspection is not consistent with the ASME Code, Section XI, Subsection 

IWE requirement that detailed visual and ultrasonic thickness measurement be 

completed on 100 percent of surface areas subjected to accelerated corrosion or areas 

where the absence or repeated loss of coatings has resulted in substantial corrosion or 

pitting. 

Based on its audit and review of the application, and review of the applicant’s response to the 

open item, the staff finds that the program elements for which the applicant claimed consistency 
1-8

with the GALL Report are consistent with the corresponding program elements of GALL Report 

AMP. Open Item 3.0.3.2.13-1 is closed.

Open Item 3.0.5.1 Operating Experience for Aging Management Programs

LR-ISG-2011-05 states that enhancements to the existing programmatic activities for the 

ongoing review of operating experience that are necessary for license renewal should be put in 

place no later than the date the renewed operating licenses are issued. The applicant 

described several enhancements; however, it planned to implement them after issuance of the 

renewed licenses. As discussed in SER Section 3.0.5, the staff could not determine whether 

operating experience related to aging management and age-related degradation will be 

considered in the period between issuance of the renewed licenses and implementation of the 

enhancements. In response, the applicant stated that the enhancements to the Operating 

Experience program will be implemented no later than the date when the renewed operating 

licenses are issued and conducted on an ongoing basis throughout the terms of the renewed 

licenses. The staff finds this implementation schedule acceptable because it is consistent with 

the guidance in LR-ISG-2011-05. Implementation of these enhancements will ensure that the 

applicant fully considers all available information to inform the aging management activities on 

an ongoing basis throughout the terms of the renewed licenses. Open Item 3.0.5-1 is closed.

1.6 Summary of Confirmatory Items

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

July 11, 2012 the staff determines that no confirmatory items exist that would require a formal 

response from the applicant.

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.

The first license condition requires the applicant to include the UFSAR supplement required by 

10 CFR 54.21(d) in the next UFSAR update, required by 10 CFR 50.71(e), following the 

issuance of the renewed licenses. The applicant may make changes to the programs and 

activities described in the UFSAR supplement, provided the applicant evaluates such changes 

in accordance with the criteria set forth in 10 CFR 50.59 and otherwise complies with the 

requirements in that section.

The second license condition requires future activities described in the UFSAR supplement to 

be completed before the period of extended operation. In its SER with Open Items issued on 

July 30, 2012, the staff proposed that the applicant shall complete these activities no later than 

six months before the period of extended operation, and shall notify the NRC in writing when 

implementation of these activities is complete. In particular, the NRC is directing the applicant 

to complete certain license renewal activities no later than 6 months prior to PEO in order to 

ensure the completion of its inspection requirements under NRC Inspection Procedure 

(IP) 71003, “Post-Approval Site Inspection for License Renewal.” Through this IP, the staff 

verifies that the license renewal commitments and selected AMPs are satisfactorily 

implemented, the description of the AMPs and related activities are, or will be, contained in the 

UFSAR, and the description of the programs is consistent with the programs implemented by 

the licensee. Notwithstanding the “Enhancement or Implementation Schedule” detailed in 
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Appendix A, “Limerick Generating Station, Units 1 and 2, License Renewal Commitments,” to 

this SER and the NRC staff’s findings presented in various sections of the SER, the scheduler 

requirements proposed in the second license condition shall take precedence.

In a letter dated October 12, 2012, the applicant provided its comments on this license 

condition. The applicant stated that this proposed license condition would require completion of 

most activities described in the license renewal commitment list six months earlier than it had 

committed to perform these activities. The applicant further stated that the proposed license 

condition creates consequences that the staff may not have intended or appreciated. 

Specifically, the current operating licenses for Units 1 and 2 expire on October 26, 2024, and 

June 22, 2029, respectively, and the applicant performs its refueling outages in the spring. A 

license condition requiring that the activities be completed at least six months prior to entering 

the PEO would mean that the applicant would not have the opportunity to perform inspections 

during the last scheduled refueling outage prior to PEO for Units 1 or 2. Thus, the applicant 

concluded that by not allowing aging management activities to be performed in the last refueling 

outage prior to the PEO, there are additional undesirable consequences. For example, certain 

aging management programs specifically require that inspections be done close to the PEO to 

allow more time for aging effects to develop and be detected by inspection.

The staff reviewed the applicant’s comments and supporting basis and found that certain 

aspects of the proposed license condition could preclude scheduling actions to both obtain 

better performance of the specific aging management program activities and make more use of 

outage work periods. On this basis, the proposed second license condition was revised to state

that:

The applicant’s UFSAR supplement submitted pursuant to 10 CFR 54.21(d), as revised 

during the license renewal application review process, describes certain programs to be 

implemented and activities to be completed prior to the period of extended operation. 

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

programs no later than 6 months prior to PEO.

b. The applicant shall complete those activities as noted in Commitment Nos. 18, 19, 

20, 22, 23, 24, 28, 29, 30, 38, 39, 40, 41, 42, 43, and 47 of Appendix A of 

NUREG-XXXX, “Limerick Safety Evaluation Report for License Renewal,” by the 

6-month date prior to PEO or the end of the last refueling outage prior to the PEO, 

whichever occurs later. 

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.

2-1

SECTION 2

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 (10 CFR) 54.21, “Contents of Application –

Technical Information,” requires Exelon Generation Company, LLC (Exelon or the applicant) to 

identify the structures, systems, 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) that identifies and lists those structures and 

components (SCs), contained in the SSCs 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, “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 2.1, “Scoping and Screening Methodology,” describes the methodology used by 

the applicant to identify the SSCs at the Limerick Generating Station (LGS), Units 1 and 2,

within the scope of license renewal (scoping) and the SCs subject to an AMR (screening).

LRA Section 2.1.1, “Introduction,” states, in part, that the applicant had considered the following 

in developing the scoping and screening methodology described in LRA Section 2:

 • 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,” issued June 2005 

(NEI 95-10) 

2.1.3 Scoping and Screening Program Review 

The staff of the U.S. Nuclear Regulatory Commission (NRC) (the staff) evaluated the applicant’s 

scoping and screening methodology in accordance with the guidance contained in 

NUREG-1800, Revision 2, “Standard Review Plan for Review of License Renewal Applications 

for Nuclear Power Plants,” (SRP-LR), Section 2.1, “Scoping and Screening Methodology.” The 

following regulations provide the basis for the acceptance criteria the staff used to assess the 
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adequacy of the scoping and screening methodology that the applicant used 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 

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

subject to an AMR

The staff reviewed the information in LRA Section 2.1 to ensure 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 the 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 LGS site

during the week of September 19–23, 2011. 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, topical reports, and implementing 

procedures that described the applicant’s scoping and screening methodology. The staff 

conducted detailed discussions with the applicant on the development of the license renewal

application, the quality practices the applicant used during LRA development, and the training of 

the applicant’s staff that participated in 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 the safety-related service water (SW) system and the turbine 

building. In addition, the staff performed walkdowns of selected portions of the essential 

SW system, fuel pool cooling and cleanup system, emergency diesel generator (EDG) fuel oil 

transfer subsystem, EDG air start subsystem, and the turbine building, 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 Implementation Procedures and Documentation Sources for Scoping and 

Screening

The staff reviewed the applicant’s scoping and screening implementing procedures, as 

documented in the “Scoping and Screening Methodology Audit Report Regarding the Limerick 

Generating Station, Units 1 and 2,” dated December 9, 2011, to verify that the process used to 

identify SSCs within the scope of license renewal and SCs subject to an AMR was consistent 

with the SRP-LR. Additionally, the staff reviewed the scope of CLB documentation and the 

process the applicant used, relative to the requirements of 10 CFR 54.4, “Scope,” and 

10 CFR 54.21, and it confirmed that the applicant adequately implemented its procedural 

guidance during the scoping and screening process.

2.1.3.1.1 Summary of Technical Information in the Application 

In LRA Section 2.1, the applicant addressed the following information sources for the license 

renewal scoping and screening process:

 • updated final safety analysis report (UFSAR)
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 • fire protection evaluation report

 • environmental qualification (EQ) master list

 • maintenance rule database

 • design baseline documents

 • component record list (CRL)

 • other CLB references, such as NRC safety evaluation reports (SERs), licensing 

correspondence, engineering drawings, and engineering evaluations and calculations

2.1.3.1.2 Staff Evaluation 

Scoping and Screening Implementation 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 

consistent with the requirements of the rule, and with the guidance in the SRP-LR and 

Regulatory Guide (RG) 1.188, “Standard Format and Content for Applications To Renew 

Nuclear Plant Operating Licenses,” which endorses the use of NEI 95-10. The staff finds the 

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

implementing procedures and AMRs is consistent with the rule, the SRP-LR, and the 

NRC-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 staff positions documented in the SRP-LR, and the information in the 

applicant’s responses dated January 27, 2012, to the staff’s requests for additional information 

(RAIs), dated January 5, 2012.

After reviewing the LRA and supporting documentation, the staff determined that the scoping 

and screening methodology instructions are consistent with the methodology description 

provided in LRA Section 2.1. The applicant’s 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 CLB Information. Regulations in 10 CFR 54.21(a)(3) require for each structure and 

component determined to be subject to an AMR to demonstrate 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 CLB is defined in 10 CFR 54.3(a), in part, as the set 

of NRC requirements applicable to a specific plant and an applicant’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. 
2-4

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 that the 

applicant used, including the UFSAR, design-basis information, and plant piping and 

instrumentation drawings (P&IDs). In addition, the staff determined that the applicant had used 

additional sources of plant information pertinent to the scoping and screening process, including 

the CRL, analyses, and reports. 

The staff determined that the applicant’s primary repository for system identification and 

component safety classification information was the CRL, UFSAR, and P&IDs. During the audit, 

the staff discussed the applicant’s administrative controls for the CRL 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 staff concludes 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 the applicant used during the scoping and screening process provided a controlled 

source of system and component data to support scoping and screening evaluations.

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 list of documents used to support scoping evaluations. The staff determined that the design 

documentation sources, required to be used by the applicant’s implementing procedures, 

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

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

The staff determined additional information would be required to complete its review. The staff 

noted that several plant systems discussed in the UFSAR are not identified in the LRA. During 

the audit, discussions with the applicant indicated that systems nomenclature had been 

organized to correspond with the system information contained in NUREG-1801, “Generic Aging 

Lessons Learned (GALL) Report.” Therefore, the staff issued RAI 2.1-2, dated January 5, 2012, 

requesting the applicant to provide a description of the process used to identify systems to be 

included within the scope of license renewal in accordance with 10 CFR 54.4(a) and to provide 

a discussion on the process used to identify systems listed in the UFSAR with system names 

discussed in the GALL Report.

The applicant responded to RAI 2.1-2, by letter dated January 27, 2012, stating that the

comprehensive list of plant systems and structures contained in the plant component record 

database was evaluated and arranged into logical groupings for license renewal evaluation, and 

the groupings were defined as license renewal systems and structures.

The applicant’s response to RAI 2.1-2 further stated that the distinction between plant systems 

and license renewal systems falls into several categories. The categories are summarized as 

follows: 

 • GALL Report system names used to identify and group together plant systems or structures 

for license renewal
2-5

 • plant system and structure descriptive titles modified to encompass various descriptive 

nomenclature used across multiple plant documents

 • plant systems and structures described in the UFSAR that perform the same function 

grouped together to facilitate a streamlined license renewal evaluation, where appropriate

In addition, the applicant’s response to RAI 2.1-2 stated that a review of this issue was 

performed, and it was concluded that the scoping methodology correctly identified the SSCs 

that should be included within the scope of license renewal in accordance with 10 CFR 54.4(a). 

The response also stated that there are no additional scoping evaluations required or additional 

SSCs to be included, and no additions or changes to LRA Table 2.2-1 have been identified as a 

result of the applicant’s review.

The staff reviewed the response to RAI 2.1-2 and determined that the applicant had provided a 

description of the process used to identify systems within the scope of license renewal and had, 

in some instances, collected plant systems and identified the collection to be in alignment with 

the terminology used in the GALL Report. In addition, the staff determined that the applicant 

had performed a review of the issue and concluded that all SSCs had been appropriately 

evaluated for inclusion within the scope of license renewal in accordance with the requirements 

of 10 CFR 54.4(a). RAI 2.1-2 is resolved.

2.1.3.1.3 Conclusion 

Based on its review of LRA Section 2.1, the detailed scoping and screening implementing 

procedures, the applicant’s response to RAI 2.1-2, 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

2.1.3.2.1 Staff Evaluation 

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

screening methodology used to develop the LRA was adequately implemented. The applicant 

used the following quality control processes during the LRA development:

 • Scoping and screening activities were performed using controlled documents and 

procedures.

 • Databases were used to guide and support screening and scoping and generate license 

renewal documents.

 • Scoping and screening activities were conducted, documented, reviewed, and approved in 

accordance with controlled procedures.

During the scoping and screening methodology audit, the staff performed a sample review of 

reports and LRA development procedures and guides, the applicant’s documentation of the 

activities performed to assess the quality of the LRA, and held discussions with the applicant’s 

license renewal personnel. The staff determined that the applicant’s activities provide 
2-6

assurance that LRA development activities were performed consistently with the applicant’s 

license renewal program requirements.

2.1.3.2.2 Conclusion 

Based on 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 assurance 

activities provide assurance that LRA development activities were performed in accordance with 

the applicant’s license renewal program requirements.

2.1.3.3 Training

2.1.3.3.1 Staff Evaluation 

The staff reviewed the applicant’s training processes to ensure that the guidelines and 

methodology for the scoping and screening activities were adequately implemented. As 

outlined in the implementing procedure, the applicant requires training for personnel 

participating in the development of the LRA. The activities conducted by the applicant included 

the following:

 • training of personnel participating in license renewal to the applicable project procedures 

and other relevant license renewal information, as appropriate to their functions

 • license renewal and subject matter expert training, including:

‒ 10 CFR Part 54

‒ relevant NRC and industry guidance documents

‒ lessons learned from previous license renewals

‒ applicable procedures

During the scoping and screening methodology audit, the staff reviewed the applicant’s written 

procedures. On a sampling basis, the staff reviewed completed qualification and training 

records and completed checklists for a sample of the applicant’s license renewal personnel.

2.1.3.3.2 Conclusion 

Based on 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 Conclusion of Scoping and Screening Program Review 

Based on its review of LRA Section 2.1, review of the applicant’s detailed 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, the results from the scoping and screening methodology audit, and the 

applicant’s response to RAI 2.1-2, the staff concludes that the applicant’s scoping and screening 
2-7

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 2.1.5, “Scoping Procedure,” describes the applicant’s methodology used to identify 

SSCs within the scope of license renewal in accordance with 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, are nonsafety-related whose failure could prevent accomplishment of a safety-related 

function, or perform a function that demonstrates compliance with the NRC’s regulations for the 

following: 

• 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 (PTS) (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 the 

Reduction of Risk from Anticipated Transients without Scram (ATWS) Events for 

Light-Water-Cooled Nuclear Power Plants”)

• station blackout (SBO) (10 CFR 50.63, “Loss of All Alternating Current Power”)

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

Components Subject to Aging Management Review, and Implementation Results,” states that 

the scoping methodology used by LGS is 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) 

2.1.4.1.1 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)(1) in LRA Section 2.1.5.1, 

“Safety-Related – 10 CFR 54.4(a)(1).” LRA Section 2.1.5.1 states that at LGS the safety-related 

plant components are identified in the CRL database and were classified using a controlled 

procedure, with classification criteria consistent with the 10 CFR 54.4(a)(1) criteria. The 

classification criteria have been evaluated in a license renewal basis document as described in 

LRA Section 2.1.3.2 and accounted for during the license renewal scoping process.

2.1.4.1.2 Staff Evaluation

As required by 10 CFR 54.4(a)(1), the applicant must consider all safety-related SSCs relied 

upon to remain functional during and following a design-basis event (DBE) to ensure the 

integrity of the reactor coolant pressure boundary (RCPB), the ability to shut down the reactor 

and maintain it in a safe shutdown condition, or the capability to prevent or mitigate the 
2-8

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 100.11, “Determination of 

Exclusion Area, Low Population Zone, and Population Center Distance,” as applicable.

With regard to the identification of DBEs, SRP-LR Section 2.1.3, “Review Procedures,”

recommends that the set of DBEs as defined in the rule is not limited to Chapter 15 (or 

equivalent) of the UFSAR. Examples of DBEs that may not be described in this chapter of the 

UFSAR include external events, such as floods, storms, earthquakes, tornadoes, or hurricanes, 

and internal events, such as a high-energy line break (HELB). Information on DBEs, as defined 

in 10 CFR 50.49(b)(1), may be found in license conditions within the CLB, the NRC’s 

regulations, NRC orders or exemptions, or any chapter of the facility UFSAR. These sources 

also should be reviewed to identify that they are relied upon to remain functional during and 

following DBEs, 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 LGS. 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 LGS Units 1 and 2 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.

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 that 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 LGS 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 safety-related SW system and the turbine building to provide 

additional assurance that the applicant adequately implemented its scoping methodology with 

respect to 10 CFR 54.4(a)(1). The staff confirmed that the applicant developed the scoping 

results for each of the sampled systems consistently with the methodology, identified the SSCs 

credited for performing intended functions, and adequately described the basis for the results, 

as well as the intended functions. The staff also confirmed that the applicant had identified and 

used pertinent engineering and licensing information to identify the SSCs required to be within 

the scope of license renewal in accordance with the 10 CFR 54.4(a)(1) criteria.

The staff noted during its review that the applicant had used the “Q” field in the CRL to identify 

safety-related SSCs within the scope of license renewal in accordance with 10 CFR 54.4(a)(1) 

and that the applicant’s procedure used to populate the “Q” field in the CRL refers to 

10 CFR Part 100, “Reactor Site Criteria.” The staff further noted during its review that LGS is an 

alternate source term (AST) plant such that 10 CFR 50.67, “Accident Source Term,” not 10 CFR 
2-9

Part 100, is applicable. Therefore, the staff issued RAI 2.1-1, dated January 5, 2012, requesting 

the applicant to provide clarification on this apparent discrepancy.

The applicant responded to RAI 2.1-1, by letter dated January 27, 2012, and stated that the 

change to AST did not involve any physical changes to the plant or require any changes to the 

quality classification of plant components and that the design changes only involved changes to 

analytical methodology used for the analysis of DBAs and associated dose consequences to 

offsite receptors and control room personnel. The response further stated that changes to the 

LGS CRL after approval of the AST were reviewed, and no components were identified that 

require additional evaluation for license renewal; therefore, no additional scoping evaluations 

are required to be performed to address the 10 CFR 54.4(a)(1)(iii) criteria.

The response to RAI 2.1-1 further stated that the dose guidelines for DBAs were changed from 

10 CFR 100 to 10 CFR 50.67, as described in the LGS Units 1 and 2 UFSAR, Chapter 15, as 

well as the description of requirements for safety-related components in LGS Units 1 and 2 

UFSAR Section 3.2.3. The applicable LGS procedures also were revised to reflect this change 

with the exception of procedure CC-MA-304. The response also stated that an issue report has 

been created in the corrective action program to provide the proper reference to 10 CFR 50.67 

in procedure CC-MA-304 and that this change in dose guidelines did not affect any component 

quality classifications and did not preclude the identification of SSCs that should have been 

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

The staff reviewed the response to RAI 2.1-1 and determined that although the applicant’s 

definition of safety-related referred to 10 CFR Part 100 instead of 10 CFR 50.67, the applicant’s 

component quality classification was correct and no SSCs had been excluded from the scope of 

license renewal as a result. RAI 2.1-1 is resolved.

2.1.4.1.3 Conclusion

Based on its review of the LRA and the applicant’s implementing procedures and reports, 

reviews of a system on a sampling basis, discussions with the applicant, and review of the 

information provided in the response to RAI 2.1-1, the staff concludes that the applicant’s 

methodology for identifying safety-related SSCs, relied upon to remain functional during and 

following DBEs, and 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) 

2.1.4.2.1 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 1.5, “Application Structure,” states that the LRA was structured in accordance with 

RG 1.188, “Standard Format and Content for Applications To Renew Nuclear Plant Operating 

Licenses,” and NEI 95-10, “Industry Guideline for Implementing the Requirements of 

10 CFR Part 54 – the License Renewal Rule,” Revision 6.

LRA Section 2.1.5.2, “Nonsafety-Related Affecting Safety-Related – 10 CFR 54.4(a)(2),” states

that the LGS Units 1 and 2 UFSAR and other CLB documents were reviewed to identify 
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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 were included within the scope of license renewal.

For nonsafety-related piping directly connected to safety-related piping, the nonsafety-related 

piping was assumed to provide structural support to the safety-related piping, unless otherwise 

confirmed by a review of the installation details. Also, nonsafety-related piping was included 

in-scope for 10 CFR 54.4(a)(2), up to one of the bounding conditions described in NEI 95-10, 

Appendix F.

Nonsafety-related piping and components that contain water, oil, or steam, and are located 

inside structures that contain safety-related SSCs, were included in-scope for potential spatial 

interaction under 10 CFR 54.4(a)(2), unless located in an excluded room. High-energy lines 

located within structures that contain safety-related equipment were included in the scope of 

license renewal, under 10 CFR 54.4 (a)(1) or (a)(2), depending on their safety classification. 

Safety-related high-energy lines were included in the scope of license renewal under 

10 CFR 54.4(a)(1), and nonsafety-related high-energy lines were included in the scope of 

license renewal under 10 CFR 54.4 (a)(2). Potential spatial interaction because of leakage or 

spray was assumed for system pressure as low as atmospheric. Supports for all 

nonsafety-related SSCs within these structures were included in the scope of license renewal.

2.1.4.2.2 Staff Evaluation

RG 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 states that the applicant’s methodology is consistent with the guidance 

contained in NEI 95-10, Revision 6, Appendix F. 

In addition, the recommendations discussed in the SRP-LR Section 2.1.3.1.2 are that the 

applicant need not consider hypothetical failures, but rather should base its 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 industrywide 

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 documented 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 described the method used to identify nonsafety-related SSCs, 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 CRL, and other CLB documents to identify the 
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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 reviewed 

the applicant’s CLB information, primarily contained in the UFSAR, related to missiles, crane 

load drops, flooding, and high-energy line breaks (HELBs) and determined that the applicant 

had included the applicable nonsafety-related SSCs within the scope of license renewal. The 

staff determined that the applicant’s methodology for identifying and including nonsafety-related 

systems that perform functions that support safety-related intended functions, 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 described 

the method used to identify nonsafety-related SSCs, 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-related 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 NEI 95-10, Revision 6, Appendix F (base-mounted 

component, flexible connection, buried piping exiting the ground, inclusion to the free end of 

nonsafety-related piping, or inclusion of the entire piping run)

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 described 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 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 containing active or passive safety-related SSCs. 

The staff determined that the applicant had identified all nonsafety-related SSCs, containing 

liquid or steam, and located in spaces containing safety-related SSCs and included the 

nonsafety-related SSCs within the scope of license renewal, unless the applicant determined 

that the failure of a nonsafety-related SC would not result in the loss of a 10 CFR 54.4(a)(1) 

intended function. The staff also determined that based on plant and industry operating 

experience, the applicant excluded the nonsafety-related SSCs containing air or gas from the 
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scope of license renewal, with the exception of portions attached to safety-related SSCs and 

required for structural support. 

During its review, the staff noted that, although the LRA shows the auxiliary boiler building is 

in-scope in accordance with 10 CFR 54.4(a)(2), because of its proximity to the reactor enclosure 

and its location above the auxiliary boiler pipe tunnel (which contains safety-related pipe), the 

adjacent lube oil building, also located above the auxiliary boiler pipe tunnel, is not included 

within the scope of license renewal. Therefore, the staff requested, in RAI 2.1-3, that the 

applicant perform a review of this issue and provided a discussion and basis for not including 

the nonsafety-related lube oil building, located above the auxiliary boiler pipe tunnel, within the 

scope of license renewal in accordance with 10 CFR 54.4(a)(2).

The applicant responded to RAI 2.1-3, by letter dated January 27, 2012, and stated that the 

auxiliary boiler enclosure, auxiliary boiler pipe tunnel, fuel oil pump house enclosure, and lube 

oil enclosure are nonsafety-related and non-Category I structures as described within the 

Limerick UFSAR. The response further stated that the auxiliary boiler enclosure and the 

auxiliary boiler pipe tunnel are both adjacent to the safety-related seismic Category 1 reactor 

enclosure that is in-scope under 10 CFR 54.4(a)(1) and that the auxiliary boiler enclosure and 

the auxiliary boiler pipe tunnel also are in-scope under 10 CFR 54.4(a)(2) since a failure of 

either the auxiliary boiler enclosure or the auxiliary boiler pipe tunnel could potentially impair the 

integrity of the adjacent in-scope reactor enclosure. The response also stated that the 

nonsafety-related lube oil storage enclosure is not located immediately adjacent to a

10 CFR 54.4 (a)(1) structure and its failure would not prevent the accomplishment of any 

10 CFR 54.4(a)(1) SSC intended function; therefore, the lube oil storage enclosure is not 

in-scope for license renewal. 

The applicant’s response to RAI 2.1-3 contained the revised LRA Section 2.4.3, “Auxiliary Boiler 

and Lube Oil Storage Enclosure,” which was revised to remove the statement “and over the 

Auxiliary Boiler Pipe Tunnel.”

The staff reviewed the applicant’s response to RAI 2.1-3 and determined that the applicant had 

revised LRA Section 2.4.3 to clarify that the nonsafety-related auxiliary boiler enclosure is within 

the scope of license renewal in accordance with 10 CFR 54.4(a)(2) because it is adjacent to the 

reactor enclosure, which is in the scope of license renewal in accordance with 

10 CFR 54.4(a)(1). The revision also removed the second reason for including the auxiliary 

boiler enclosure within the scope of license renewal (being over the auxiliary boiler pipe tunnel) 

since the auxiliary boiler pipe tunnel is a nonsafety-related structure. The staff agrees that not 

including the auxiliary boiler enclosure within the scope of license renewal caused by its position 

above the nonsafety-related auxiliary boiler pipe tunnel is appropriate. The staff determined that 

this rationale was also applicable to the nonsafety-related lube oil storage enclosure, which is 

located above the nonsafety-related auxiliary boiler pipe tunnel but is not adjacent to the reactor 

enclosure; therefore, it does not have the potential to affect a structure that is within the scope 

of license renewal in accordance with 10 CFR 54.4(a)(1). As a result, the staff determined that 

the applicant had provided a basis for not including the lube oil storage enclosure within the 

scope of license renewal. RAI 2.1-3 is resolved.

During the scoping and screening methodology audit, the staff reviewed the license renewal 

application, license renewal implementing procedures, license renewal drawings, and applicable 

UFSAR sections. During the review of the applicant’s drawing and discussions with the 

applicant, the staff determined that when the nonsafety-related pipe did not contain the number 
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of supports to develop an equivalent anchor (six in total) before a branch connection in the 

nonsafety-related pipe attached to safety-related SCs, the applicant did not consistently identify 

the remaining required supports on all branch connections. Specifically, the applicant stated 

that in some cases the branch lines and supports are included within the scope of license 

renewal and in other cases are not included within the scope of license renewal. Therefore, by 

letter dated January 5, 2012, the staff issued RAI 2.1-4 requesting the applicant to perform a 

review of this issue and provide a discussion and the basis for the position of not including 

nonsafety-related pipe, attached to safety-related SCs, up to and including the first anchor or 

bounding condition, within the scope of license renewal in accordance with 10 CFR 54.4(a)(2).

The applicant responded to RAI 2.1-4, by letter dated January 27, 2012, which states, in part:

During the audit, it was identified that in-scope nonsafety-related Unit 1, Primary 

Containment Instrument Gas (PCIG) system piping connected to safety-related 

piping did not include the required supports to develop an equivalent seismic 

anchor prior to a branch connection off the nonsafety-related pipe. Therefore, the 

license renewal 10 CFR 54.4(a)(2) boundary for the structural support intended 

function at the branch connection was not extended to all of the piping supports 

required to develop the equivalent anchor. Further review of this piping 

configuration identified that the license renewal 10 CFR 54.4(a)(2) boundary 

needed to be extended to include several feet of additional piping and associated 

piping supports. This change does not result in additional function/component/

material combinations within the aging management review for the PCIG system 

as shown in LRA Table 3.3.2-14.

The methodology used for the determination of safety-related/nonsafety-related 

interfaces is described in LRA Section 2.1.5.2. For nonsafety-related piping 

directly connected to safety-related piping, the nonsafety-related piping was 

assumed to provide structural support to the safety-related piping, and is included 

within the scope of license renewal for 10 CFR 54.4(a)(2). An extent of condition 

review performed for all systems within the scope of license renewal identified six 

additional instances within the scoping performed for the LRA, where the 

10 CFR 54.4(a)(2) boundary at a branch connection was not extended to all of the 

piping supports required to develop an equivalent seismic anchor or bounding 

criteria described in NEI 95-10, Appendix F. All of the locations are within the 

PCIG system. Extension of the 10 CFR 54.4(a)(2) boundary at these branch 

connections results in adding nine valve bodies and several sections of piping and 

piping components within the scope of license renewal. The review also identified 

the need to add two function/component/material combinations to the aging 

management review for the PCIG system.

The staff reviewed the response to RAI 2.1-4 and determined that the applicant had reviewed 

the method and its implementation used to identify the portions of nonsafety-related pipe 

(attached to safety-related pipe) and supports required to establish an equivalent anchor, when 

the nonsafety-related pipe included branch connections. The applicant also stated that, 

following its review, it found that it had not consistently evaluated nonsafety-related pipe 

containing branch connections. This review resulted in the applicant identifying and including

additional portions of nonsafety-related pipe and supports within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(2). On the basis of these actions, RAI 2.1-4 is resolved.
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During the scoping and screening methodology audit, the staff reviewed the applicant’s 

implementing procedure that describes the process used to identify nonsafety-related SSCs, 

whose failure could potentially affect the performance of the intended function of safety-related 

SSCs, for inclusion within the scope of license renewal. The staff determined that the 

applicant’s implementing procedure, when discussing nonsafety-related pipe directly attached to 

safety-related SCs, does not require that a portion of the nonsafety-related pipe (and applicable 

anchors or bounding conditions on the nonsafety-related side of the interface) to be included 

within the scope of license renewal. Instead, the implementing procedure allows for an anchor 

directly at the nonsafety-related/safety-related interface, or close to the interface (on the 

safety-related side of the interface) to be used as the last anchor within the scope of license 

renewal. Therefore, the staff issued RAI 2.1-5, by letter dated January 5, 2012, requesting the 

applicant to perform a review of this issue and provide a discussion and basis for the use of an 

implementing procedure that does not require including nonsafety-related pipe, attached to 

safety-related SCs, up to and including the first anchor or bounding condition, beyond the 

nonsafety-related/safety-related interface, within the scope of license renewal in accordance 

with 10 CFR 54.4(a)(2).

The applicant responded to RAI 2.1-5, by letter dated January 27, 2012, which states, in part:

The methodology used for the determination of safety-related to nonsafety-related 

interfaces is described in LRA Section 2.1.5.2. For nonsafety-related piping 

directly connected to safety-related piping, the nonsafety-related piping was 

assumed to provide structural support to the safety-related piping, and is included 

within the scope of license renewal for 10 CFR 54.4(a)(2) up to and including the 

first anchor or bounding condition past the safety-related to nonsafety-related 

interface. The procedure for scoping and the scoping basis document for the 

determination of 10 CFR 54.4(a)(2) SSCs are consistent with this methodology. 

The procedure for the development of license renewal boundary drawings is not 

consistent with this methodology. This procedure provides several examples of 

drawing notes where the credited anchor is located on the safety-related piping 

and the nonsafety-related attached piping beyond the safety-related to 

nonsafety-related interface is not included in-scope for structural support. 

An extent of condition review, performed for all systems within the scope of license 

renewal, determined that there are no instances within the scoping performed for 

the preparation of the LRA, where an anchor or bounding condition on 

safety-related piping was credited for determining the license renewal boundary for 

piping that has a safety-related to nonsafety-related interface. Therefore, the 

review concluded that use of the scoping methodology as described in the 

procedure for the development of license renewal boundary drawings did not 

preclude the identification of systems, structures, and components (SSCs) which 

should have been included within the scope of license renewal in accordance with 

10 CFR 54.4(a)(2). No additional scoping evaluations are required to address the 

10 CFR 54.4(a)(2) criteria and there are no additional SSCs to be included within 

the license renewal scope as a result of this review.

The staff reviewed the response to RAI 2.1-5 and determined that although the applicant’s 

procedure for developing the license renewal boundary drawings provides several examples of 

drawing notes in which the credited anchor is located on the safety-related piping, and the 

nonsafety-related attached piping beyond the safety-related to nonsafety-related interface is not 
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included in-scope for structural support. This approach is not in agreement with the method 

described in the LRA or the applicant’s 10 CFR 54.4(a)(2) implementing procedure. The staff 

determined that the applicant had performed a review of all nonsafety-related pipe attached to 

safety-related pipe and confirmed that, in all cases, an appropriate portion of nonsafety-related 

pipe and support beyond the safety-related nonsafety-related interface was included within the 

scope of license renewal in accordance with the method described in the LRA and the 

10 CFR 54.4(a)(2) implementing procedure, and that the method described in the license 

renewal boundary drawing procedure had not been used. The staff determined that this met the 

requirements of 10 CFR 54.4(a)(2). RAI 2.1-5 is resolved.

During the scoping and screening methodology audit the applicant stated that if the first anchor 

or bounding condition was determined to be beyond the area of potential spatial interaction for 

spray or leakage within the structure or room (space), the portion of nonsafety-related pipe, 

attached to a safety-related SC, included within the scope of license renewal was continued 

outside the space, up to and including an anchor or bounding condition identified on the 

boundary drawing. However, the applicant stated that if the anchor or bounding condition was 

within the space, the applicant included the pipe up to the boundary of the space, but did not 

specifically identify the anchor or bounding condition on the boundary drawing. The staff was 

not able to determine the process the applicant used to confirm that an anchor or bounding 

condition existed within a space, if an anchor or bounding condition was not specifically 

identified. Therefore, the staff issued RAI 2.1-6, by letter dated January 5, 2012, requesting the 

applicant to perform a review of this issue and provide a discussion on the process used to 

verify that an anchor or bounding condition exists within the area of potential spatial interaction 

or nonsafety-related pipe attached to safety-related SCs, and, therefore, no additional pipe, 

anchors or bounding conditions needed to be included within the scope of license renewal 

outside the area of potential spatial interaction.

The applicant responded to RAI 2.1-6, by letter dated January 27, 2012, which states, in part:

The methodology for evaluating nonsafety-related SSCs affecting safety-related 

SSCs is described in LRA Section 2.1.5.2. For nonsafety-related piping directly 

connected to safety-related piping, the nonsafety-related piping was assumed to 

provide structural support to the safety-related piping. The nonsafety-related 

piping was included in-scope for 10 CFR 54.4(a)(2) up to an anchor or bounding 

condition. Failure in the nonsafety-related piping beyond this boundary would not 

impact structural support for the safety-related piping. If the connected 

nonsafety-related piping system contains fluid, then the in-scope boundary was 

extended beyond the anchor or bounding condition caused by the potential for

spatial interaction out to a point where there is no longer a spatial relationship. 

LRA Table 2.1-1 defines the Leakage Boundary intended function. 

Nonsafety-related components required to maintain mechanical and structural 

integrity to prevent spatial interactions that could cause failure of safety-related 

SSCs have a Leakage Boundary intended function. This function includes the 

required structural support when the nonsafety-related piping is also attached to 

safety-related piping.

The Leakage Boundary intended function is shown on the license renewal 

drawings in red. When the SSCs, in-scope for structural support, are enveloped by 

the SSCs in-scope for spatial interaction, the location of the structural support 

endpoint has not been identified on the license renewal boundary drawing. When 
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the location of the structural endpoint extends past the spatial envelope, the 

intended function of Structural Support is applied and a note is added to the license 

renewal boundary drawing.

An extent of condition review was performed on all license renewal boundary 

drawings associated with all systems within the scope of license renewal to identify 

the seismic anchors or bounding conditions within the areas of potential spatial 

interaction. This review confirmed that the scoping methodology was correctly 

implemented and that the seismic anchors or bounding conditions were within the 

areas of potential spatial interaction as shown on the license renewal boundary 

drawings except as described below. As a result of this review, the following (a)(2) 

structural support boundaries needed to be extended beyond the spatial envelope 

to include a seismic anchor or boundary condition.

The applicant’s response to RAI 2.1-6 provided a summary of the structural support boundaries 

required to extend beyond the spatial envelope to include a seismic anchor or boundary 

condition, which included the following:

 • Condensate system – The (a)(2) scoping boundary for the 10-inch HBC-108 stainless steel 

piping was incorrectly identified at the Unit 1, Reactor Enclosure wall on [the applicable] 

license renewal boundary. The scoping boundary should have extended through the wall 

beyond the spatial envelope to just inside the Radwaste Enclosure to the credited anchor. 

This additional piping is in-scope with a structural support intended function only since 

leakage is not a concern within the Radwaste Enclosure because the Radwaste Enclosure 

does not house safety-related SSCs.

 • Safety-related service water system – The (a)(2) scoping boundary for 3-inch HBD carbon 

steel piping associated with the Unit 1 residual heat removal (RHR) heat exchanger tube 

corrosion monitoring subsystem was identified incorrectly on [the applicable] license renewal 

boundary drawing. The scoping boundary should have extended up to and included the 

base mounted specimen chamber and specimen chamber service water pump. The piping, 

specimen chamber, and specimen chamber service water pump are added to license 

renewal scope only for structural support intended function, since this equipment is 

abandoned, has been confirmed to be drained, and does not create a spatial interaction 

concern. 

The staff reviewed the response to RAI 2.1-6 and determined that the information contained in 

the LRA and the applicant’s 10 CFR 54.4(a)(2) implementing procedure, related to 

nonsafety-related piping directly connected to safety-related piping, specifically when a portion 

of the nonsafety-related pipe was also included within the scope of license renewal because of

the potential for spatial interaction with safety-related SSCs, was in accordance with the 

requirements of 10 CFR 54.4(a)(2). The staff determined that the applicant had confirmed that 

the method documented in the LRA and the 10 CFR 54.4(a)(2) implementing procedure was 

correct and performed an extent of condition review to confirm that the method described in the 

LRA and the 10 CFR 54.4(a)(2) procedure had been applied. The applicant performed an 

extent of condition review and determined that to be in accordance with the method described in 

the LRA and the 10 CFR 54.4(a)(2) implementing procedure, two boundaries were required to 

be extended beyond the area of potential spatial interaction with safety-related SSCs to include 

additional nonsafety-related pipe and supports within the scope of license renewal. The staff 

determined that this met the requirements of 10 CFR 54.4(a)(2). RAI 2.1-6 is resolved.
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During the scoping and screening methodology audit, the staff noted that the applicant identified 

containment boundaries in the scope of license renewal, including the ceiling of the suppression 

pool. The staff also noted that there is abandoned nonsafety-related structural and 

miscellaneous steel (including the Q-deck) attached to the safety-related diaphragm slab. The 

applicant had determined not to include the abandoned nonsafety-related structural and 

miscellaneous steel within the scope of license renewal. Therefore, the staff issued RAI 2.1-7, 

by letter dated January 5, 2012, requesting the applicant to perform a review of this issue and 

provide a discussion and basis for the position of not including abandoned nonsafety-related

structural and miscellaneous steel, attached to safety-related structures, within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(2).

The applicant responded to RAI 2.1-7, by letter dated January 27, 2012, which states, in part:

Miscellaneous steel is included in LRA Table 2.4-11 as a component type within 

the scope of license renewal and subject to aging management review. LGS 

LRA Section 2.4.11, Primary Containment, page 2.4-46 states: “The 

Containment Structure performs intended functions delineated in 10 CFR 54.4 

and is in-scope for license renewal in its entirety, except for the metal decking 

and abandoned steel under the diaphragm slab, which does not perform an 

intended function.” The design documents show that the subject metal decking 

serves no structural purpose and was designed as a form to support placement 

of concrete during construction. The metal decking is supported by structural 

steel, which is within the scope of license renewal in accordance with 

10 CFR 54.4 (a)(1) and 10 CFR 54.4(a)(2). The abandoned steel shown on a 

drawing for the diaphragm slab is limited to an abandoned monorail, which is 

supported by other structural steel and bolting, which are within the scope of 

license renewal in accordance with 10 CFR 54.4 (a)(1) and 10 CFR 54.4(a)(2). 

The metal decking and abandoned monorail steel under the diaphragm slab do 

not perform any intended function and they are supported by structural steel and 

bolting, which is within the scope of license renewal in accordance with 

10 CFR 54.4 (a)(1) and 10 CFR 54.4(a)(2). The decision to not include the metal 

decking and abandoned monorail steel under the diaphragm slab within the 

scope of license renewal is consistent with the methodology discussed in 

Section 2.1.3.3 of the LRA. This is also consistent with the industry guidelines as 

described within NEI 95-10 Appendix F and as applied to other items such as 

nonsafety-related air and gas system piping and components, where the piping is 

not in-scope but whose supports are in-scope. A review of this issue was 

performed and it was concluded that the scoping methodology correctly identified 

the systems, structures, and components (SSCs), which should be included 

within the scope of license renewal in accordance with 10 CFR 54.4(a)(2).

However, the metal decking on the underside of the Primary Containment 

diaphragm slab has been visually examined during the Containment lSI IWL 

examinations of the underside of the concrete diaphragm slab. The decking is 

now included within the scope of license renewal, as component type “Metal 

Decking” and subject to aging management using the Structures Monitoring 

aging management program during the inspections of the adjacent support steel. 

In addition, since the abandoned monorail steel is the only abandoned steel 

beneath the diaphragm slab and represents a small fraction of the steel under 
2-18

the diaphragm slab, the remainder of which is in-scope, the abandoned monorail 

steel is now included in-scope for completeness, as component type “Metal 

Components: All structural members (includes abandoned monorail steel)” and 

is subject to the Structures Monitoring aging management program.

The staff reviewed the response to RAI 2.1-7 and determined that that applicant had reviewed 

the scoping evaluation of the abandoned steel in containment, which included metal decking 

and abandoned monorail steel under the diaphragm slab, and subsequently included the 

abandoned steel within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). 

RAI 2.1-7 is resolved. 

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). 

2.1.4.2.3 Conclusion

Based on its review of the LRA and the applicant’s implementing procedures and reports, 

selected system reviews and walkdowns, discussions with the applicant, and review of the 

information provided in the response to RAIs 2.1-3, 2.1-4, 2.1-5, 2.1-6 and 2.1-7, 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 

10 CFR 54.4(a)(2), and, therefore, is acceptable.

2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3) 

2.1.4.3.1 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 2.1.3.4, “Scoping for Regulated Events,” states that the technical basis documents 

were prepared to address license renewal scoping of SSCs relied on in safety analyses or plant 

evaluations to perform a function that demonstrates compliance with the NRC’s regulations for 

fire protection, EQ, ATWS, and SBO, and that the NRC’s regulations for pressurized thermal 

shock are not applicable to the LGS boiling-water reactor (BWR) design.

LRA Section 2.1.5.3, “Regulated Events – 10 CFR 54.4(a)(3),” states that 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 technical basis documents, described in LRA 

Section 2.1.3.4, identifies the systems and structures relied upon to demonstrate compliance 

with the applicable regulation. The technical basis documents also identify the source 

documentation used to determine the scope of components within the system credited to 

demonstrate compliance with each of the applicable regulated events. 

The LRA states that the guidance provided by the technical basis documents were incorporated 

into the system and structure scoping evaluations to determine the SSCs credited for each of 

the four applicable regulations. SSCs credited in the four applicable regulations have been 
2-19

classified as satisfying 10 CFR 54.4(a)(3) criteria and have been included within the scope of 

license renewal.

2.1.4.3.2 Staff Evaluation 

The staff reviewed LRA Sections 2.1.3.4 and 2.1.5.3 that described the method used to identify, 

and 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 NRC’s 

regulations for fire protection, EQ, ATWS, and SBO. As part of this review, during the scoping 

and screening methodology audit, the staff had discussions with the applicant, reviewed 

implementing procedures and the technical basis documents, license renewal drawings, and 

scoping results reports. The staff determined that the applicant had evaluated the CLB to 

identify SSCs that perform functions addressed in 10 CFR 54.4(a)(3), and included these SSCs 

within the scope of license renewal as documented in the scoping 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 described the method used to identify SSCs within the scope of license renewal 

in accordance with 10 CFR 54.4(a)(3) (fire protection – 10 CFR 50.48). The implementing 

procedure described 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 fire protection technical basis 

document. 

Based on its review of the CLB documents and the sample review, the staff determined that the 

applicant’s methodology was adequate for identifying and including SSCs credited in allowing 

functions that perform fire protection within the scope of license renewal, in accordance with the 

requirements of 10 CFR 54.4(a)(3).

Environmental Qualification (EQ). The staff reviewed the applicant’s implementing procedure 

and technical basis document that described the method used to identify SSCs within the scope 

of license renewal in accordance with 10 CFR 54.4(a)(3) (EQ – 10 CFR 50.49). The 

implementing procedure described 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, LGS 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 EQ technical basis document. Based on its review of the CLB documents and the sample 

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 (ATWS). The staff reviewed the applicant’s implementing 

procedure and technical basis document that described the method used to identify SSCs within 

the scope of license renewal in accordance with 10 CFR 54.4(a)(3) (ATWS – 10 CFR 50.62). 

The implementing procedure described a process that considered CLB information, including 

the UFSAR and the ATWS technical basis document. The staff reviewed portions of the 
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applicable portions of 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 

ATWS technical basis document. Based on its review of the CLB documents and the sample 

review of scoping reports, 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 (SBO). The staff reviewed the applicant’s implementing procedure and 

technical basis document that described the method used to identify SSCs within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(3) (SBO – 10 CFR 50.63). The 

implementing procedure described a process that considered CLB information, including the 

UFSAR and the SBO technical basis document. The staff reviewed applicable portions of the 

LRA, CLB information, applicable portions of the UFSAR, commitments and analyses that 

demonstrate compliance with 10 CFR 50.63, 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 

SBO technical basis document. Based on its review of the CLB documents and the sample 

review of scoping reports, 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).

Pressurized Thermal Shock (PTS). Regulations in 10 CFR 54.4(3) state that SSCs relied upon 

in safety analyses or plant evaluations to perform a function that demonstrates compliance with 

the NRC‘s regulations, include, among others, PTS (10 CFR 50.61) are within the scope of 

license renewal. The regulation contained in 10 CFR 50.61 only applies to pressurized-water 

reactor (PWR) type reactors and, therefore, are not applicable to LGS Units 1 and 2.

2.1.4.3.3 Conclusion 

Based on its review of the LRA and the applicant’s implementing procedures and reports, 

reviews of systems on a sampling basis, and discussions with the applicant, the staff concludes 

that the applicant’s methodology for identifying and including SSCs, relied upon 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

2.1.4.4.1 Summary of Technical Information in the Application 

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 2.1.1. The LRA 

states that the initial step in the scoping process was to define the entire plant in terms of 

systems and structures. These systems and structures were evaluated against the scoping 

criteria in 10 CFR 54.4(a)(1), (a)(2), and (a)(3) to determine if they perform or support a 

safety-related intended function, perform functions that demonstrate compliance with the 

requirement of one of the five regulations described in 10 CFR 54.4(a)(3), provide structural 

support for safety-related SSCs, or have the potential for spatial interactions with safety-related 

SSCs. For the systems and structures determined to be within the scope of license renewal, 
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the intended functions that are the bases for including them within the scope of license renewal

also were identified.

The LRA further stated that if any portion of a system or structure met the scoping criteria of 

10 CFR 54.4, the system or structure was included in the scope of license renewal. Mechanical 

systems and structures were then further evaluated to determine those mechanical and 

structural components that perform or support the identified intended functions. 

2.1.4.4.2 Staff Evaluation 

The staff reviewed the applicant’s methodology for identifying SSCs within the scope of license 

renewal to verify it met the requirements of 10 CFR 54.4. The applicant had developed 

implementing procedures that described the processes used to identify the systems and 

structures subject to 10 CFR 54.4 review and to determine if the system or structure performed 

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 onsite 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.

2.1.4.4.3 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, acceptable.

2.1.4.5 Mechanical Component Scoping

2.1.4.5.1 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 2.1.1 states that the in-scope boundaries of mechanical systems and structures 

were developed and are described in LRA Sections 2.3 and 2.4. These boundaries also are 

depicted on the license renewal boundary drawings.

LRA Section 2.1.5.5 “Scoping Boundary Determination – Mechanical Systems,” states that for 

mechanical systems, the mechanical components that support the system-intended functions 

were included in the scope of license renewal and are depicted on the applicable system piping 

and instrumentation diagram. Mechanical system piping and instrumentation diagrams are 
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marked up to create license renewal boundary drawings showing the components within the 

scope of license renewal. Components required to support a safety-related function, or a 

function that demonstrates compliance with one of the five regulations described in 

10 CFR 54.4(a)(3), are identified on the system piping and instrumentation diagrams by green 

highlighting. Nonsafety-related components connected to safety-related components and that 

are required to provide structural support at the safety/nonsafety interface, or components 

whose failure could prevent satisfactory accomplishment of a safety-related function because of

spatial interaction with safety-related SSCs, are identified by red highlighting. A computer sort 

and download of associated system components from the CRL database confirms the scope of 

components in the system. Plant walkdowns were performed when required for additional 

confirmation.

2.1.4.5.2 Staff Evaluation

The staff evaluated LRA Sections 2.1.1 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 implementing procedures’ guidance the applicant used was 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 scoping methodology outlined in 

the LRA and the implementing procedures and whether the scoping results were consistent with 

CLB requirements. The staff determined that the applicant’s procedure was consistent with the 

description provided in the LRA Sections 2.1.1 and 2.1.5.5 and the guidance contained in the 

SRP-LR, Section 2.1, and was adequately implemented. 

On a sampling basis, the staff reviewed the applicant’s scoping reports for the safety-related 

SW system and the process used to identify mechanical components that met the scoping 

criteria of 10 CFR 54.4. The staff reviewed the implementing procedures, confirmed that the 

applicant had identified and 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 identified intended functions and the process used to identify 

system component types. The staff confirmed 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 confirmed the results in accordance with the implementing procedures. The staff 

confirmed that the applicant’s license renewal personnel verifying the results had performed 

independent reviews of the scoping reports and applicable license renewal drawings to ensure 

accurate identification of the system intended functions. 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 confirmed 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).
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2.1.4.5.3 Conclusion

Based on its review of the LRA, scoping implementing procedures, and the sampling system 

review of mechanical 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, acceptable. 

2.1.4.6 Structural Component Scoping

2.1.4.6.1 Summary of Technical Information in the Application 

LRA Section 2.1.5.5 “Scoping Boundary Determination – Structures,” states that for structures, 

the structural components that support the intended functions are included in the scope of 

license renewal. The structural components are identified from a review of applicable plant 

design drawings of the structure. Plant walkdowns were performed when required for additional 

confirmation. A single site plan layout drawing is marked up to create a license renewal 

boundary drawing showing the in-scope structures.

2.1.4.6.2 Staff Evaluation 

The staff evaluated LRA Sections 2.1.1 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 implementing procedures’ guidance the applicant used was 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 the implementing procedures, and whether the scoping results were consistent 

with CLB requirements. The staff determined that the applicant’s procedure was consistent with 

the description provided in the LRA Sections 2.1.1 and 2.1.5.5 and the guidance contained in 

the SRP-LR, Section 2.1 and was adequately implemented. 

On a sampling basis, the staff reviewed the applicant’s scoping reports for the turbine building 

and the process used to identify structural systems and components that met the scoping 

criteria of 10 CFR 54.4. The staff reviewed the implementing procedures, confirmed that the 

applicant had identified and 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 turbine building’s identified intended functions and the process used to 

identify structural component types. Additionally, the staff determined that the applicant had 

confirmed the results in accordance with the implementing procedures. The staff confirmed that 

the applicant’s license renewal personnel verifying the results had performed independent 

reviews of the scoping reports and the applicable license renewal drawings to ensure accurate 

identification of the system intended functions. The staff confirmed that the structures 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 confirmed 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).
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2.1.4.6.3 Conclusion 

Based on its review of information in the LRA, the scoping implementation procedure, and 

review of structural scoping results, the staff concludes that the applicant’s methodology for 

identification of the structures and structural components within the scope of license renewal is 

in accordance with the requirements of 10 CFR 54.4 and, therefore, acceptable.

2.1.4.7 Electrical Component Scoping

2.1.4.7.1 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). 

LRA Section 2.1.1 states that electrical and instrumentation and control (I&C) systems were 

scoped like mechanical systems and structures per the scoping criteria in 10 CFR 54.4(a)(1), 

(a)(2), and (a)(3). Electrical and I&C components within electrical and I&C systems that are 

within the scope of license renewal were included in the scope of license renewal. Likewise, 

electrical and I&C components in mechanical systems within the scope of license renewal were 

included in the scope of license renewal. Consequently, further system evaluations to 

determine which electrical components were required to perform or support the system intended 

functions were not performed during the scoping process.

LRA Section 2.1.5.5 “Scoping Boundary Determination – Electrical and I&C Systems,” states

that 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 was used for electrical 

equipment. All electrical components in systems within the scope of license renewal were 

included in the scope of license renewal. Electrical components within the scope of license 

renewal were placed into commodity groups and evaluated as commodities during the 

screening process as described in LRA Section 2.1.6.

2.1.4.7.2 Staff Evaluation 

The staff evaluated LRA Sections 2.1.1 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 procedures’ guidance the applicant used 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 the implementing procedures, and whether the scoping results were consistent 

with CLB requirements. The staff determined that the applicant’s procedure was consistent with 

the description provided in the LRA Sections 2.1.1 and 2.1.5.5 and the guidance contained in 

the SRP-LR, Section 2.1, and was adequately implemented. 

The staff noted that after the scoping of electrical and I&C components was performed, the 

electrical components within the scope of license renewal 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. 
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The electrical commodities included cable connections, fuse holders, high-voltage insulators, 

insulation material for electrical cables and connections, metal enclosed bus (MEB), switchyard 

bus and connections, and transmission conductors and connectors.

As part of this review, the staff discussed the methodology with the applicant, reviewed the 

implementing procedures developed to support the review, and evaluated the scoping results 

for a sample of SSCs identified within the scope of license renewal. The staff reviewed the 

implementing procedures, confirmed that the applicant had identified and used pertinent 

engineering and licensing information, and discussed the methodology and results with the 

applicant. Additionally, the staff determined that the applicant had independently confirmed the 

results in accordance with the implementing procedures. The staff confirmed that the 

applicant’s license renewal personnel verifying the results had performed independent reviews 

of the scoping reports and the applicable license renewal drawings to ensure accurate 

identification of the system intended functions. The staff confirmed that the electrical SSCs the 

applicant identified were evaluated against the criteria of 10 CFR 54.4(a)(1), (a)(2), and (a)(3). 

The staff determined that the applicant 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, in accordance with 

10 CFR 54.4(a).

2.1.4.7.3 Conclusion 

Based on its review of information contained in the LRA, scoping implementing procedures, and 

a sampling review of electrical scoping results, the staff concludes that the applicant’s 

methodology for identifying electrical components within the scope of license renewal is in 

accordance with the requirements of 10 CFR 54.4, and therefore, acceptable.

2.1.4.8 Conclusion for Scoping Methodology

Based on its review of the LRA, 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 that are safety-related, whose 

failure could affect safety-related intended functions, and 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

After identifying systems and structures within the scope of license renewal, the applicant 

implemented a process for identifying SCs subject to an AMR, in accordance with 

10 CFR 54.21.

2.1.5.1.1 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. LRA 

Section 2.1.6.1, “Identification of Structures and Components Subject to an AMR,” states that 
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SCs 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 in the scope of license renewal that are subject 

to an AMR.

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 identifying passive 

structures and components. Most passive structures and components are long-lived. In the few 

cases in which a passive component was determined not to be long-lived, such determination 

was documented in the screening evaluation and, if applicable, on the associated license 

renewal boundary drawing.

2.1.5.1.2 Staff Evaluation 

As required by 10 CFR 54.21, each LRA must contain an IPA that identifies SCs 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 the applicant used to identify the mechanical, structural,

and electrical SSCs 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 the 

safety-related SW system and the turbine building. 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 screening methodology for 

mechanical, structural, and electrical SCs is discussed in SER Sections 2.1.5.2, 2.1.5.3,

and 2.1.5.4.

2.1.5.1.3 Conclusion 

Based on its 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, which are subject to an AMR. The staff 

concludes that the applicant’s process for determining the SCs subject to an AMR is consistent 

with the requirements of 10 CFR 54.21 and is, therefore, acceptable.
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2.1.5.2 Mechanical Component Screening

2.1.5.2.1 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. LRA Section 2.1.6.1, “Identification of Structures and Components Subject to an

AMR – Mechanical Systems,” states that for mechanical systems within the scope of license 

renewal, the completed scoping packages include written descriptions and marked-up system 

piping and instrumentation diagrams that clearly identify the in-scope system boundary for 

license renewal. The marked-up system piping and instrumentation diagrams are called 

boundary drawings for license renewal. These system boundary drawings were reviewed to 

identify the passive, long-lived components, and the identified components then were entered 

into the license renewal database. Component listings from the CRL database also were 

reviewed to confirm that all system components were considered. In cases in which the system 

piping and instrumentation diagram did not provide sufficient detail (e.g., some large 

vendor-supplied components), the associated component drawings or vendor manuals also 

were reviewed. Plant walkdowns were performed when required for confirmation. The 

identified list of passive, long-lived system components was benchmarked against previous 

license renewal applications containing a similar system.

2.1.5.2.2 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 confirmed 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 if the screening methodology outlined in the 

LRA and implementing procedures was adequately implemented. During the scoping and 

screening methodology audit, the staff reviewed the safety-related SW system screening report 

and discussed the report with the applicant and confirmed proper implementation of the 

screening process. 

2.1.5.2.3 Conclusion 

Based on 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, acceptable.
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2.1.5.3 Structural Component Screening

2.1.5.3.1 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 an AMR in accordance with the requirements of 

10 CFR 54.21. LRA Section 2.1.6.1, “Identification of Structures and Components Subject to an

AMR – Containments, Structures, and Component Supports,” states that for structures within 

the scope of license renewal, the completed scoping packages include written descriptions of 

the structure. If only selected portions of the structure are within the scope of license renewal, 

the portions within the scope of license renewal are described in the scoping evaluation. The 

associated structure drawings were reviewed to identify the passive, long-lived SCs, and the 

identified SCs then were entered into the license renewal database. Component listings from 

the CRL database were also reviewed to confirm that all structural components were 

considered. Plant walkdowns were performed when required for confirmation. The identified 

list of passive, long-lived structures and components was benchmarked against previous license 

renewal applications.

2.1.5.3.2 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 confirmed 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 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 if the screening methodology outlined in the 

LRA and implementing procedures was adequately implemented. During the scoping and 

screening methodology audit, the staff reviewed the turbine building screening report and 

discussed the report with the applicant and confirmed proper implementation of the screening 

process. 

2.1.5.3.3 Conclusion 

Based on 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, acceptable. 
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2.1.5.4 Electrical Component Screening

2.1.5.4.1 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 an AMR in accordance with the requirements of 

10 CFR 54.21. LRA Section 2.1.6.1, “Identification of Structures and Components Subject to an

AMR – Electrical and I&C Commodities,” states that screening of electrical and I&C 

commodities within the electrical, I&C, and mechanical systems within the scope of license 

renewal used a bounding approach as described in NEI 95-10. Electrical and I&C components 

for the systems within the scope of license renewal were assigned to commodity groups. The 

commodities subject to an AMR were identified by applying the criteria of 10 CFR 54.21(a)(1). 

This method provided the most efficient way to determine the electrical commodities subject to 

an AMR, since many electrical and I&C components and commodities are active and, therefore,

not subject to an AMR. 

2.1.5.4.2 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. 

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 they were 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 if 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, discussed the 

report with the applicant, and confirmed proper implementation of the screening process. 

2.1.5.4.3 Conclusion 

Based on its review of the LRA, the screening implementation procedure, drawings, discussion 

with the applicant, and a sample of the results of the screening methodology, the staff 

concludes that the applicant’s methodology to identify electrical SSCs 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, acceptable.

2.1.5.5 Conclusion for Screening Methodology

Based on 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.
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2.1.6 Summary of Evaluation Findings 

Based on 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 sample 

system reviews, and the applicant’s responses dated January 27, 2012, to the staff’s RAIs 

dated January 5, 2012, the staff confirms that the applicant’s scoping and screening 

methodology is consistent with the requirements of 10 CFR 54.4 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 systems and structures 

within the scope of license renewal and SCs requiring 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 

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 upon 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 plant mechanical systems, structures, and electrical and 

I&C systems 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.

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 the SER Section 2.1. To

verify the applicant properly implemented its methodology, the staff’s review focused on the

implementation results shown in LRA Table 2.2-1, “Plant Level Scoping Results,” to confirm that

there were no omissions of plant-level systems and structures within the scope of license

renewal.

The staff determined if the applicant properly identified the systems and structures within 

the scope of license renewal in accordance with 10 CFR 54.4. The staff reviewed systems 

and structures that the applicant did not identify as within the scope of license renewal to 

verify if the systems and structures have any intended functions requiring their inclusion 
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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.”

In RAI 2.2-1, dated March 9, 2012, the staff noted Table 2.2-1 provides the results of 

applying the license renewal scoping criteria to the systems, structures, and commodities. 

The license renewal scoping criteria was described in LRA Section 2.1. The following 

UFSAR systems could not be located in LRA Table 2.2-1: plant monitoring system 

(UFSAR Section 1.2.4.3.1.7, “Plant Monitoring System” (PMS)), area radiation monitoring 

system (UFSAR Section 7.1.2.1.12, “Area Radiation Monitoring System”), emergency 

response facility data system (UFSAR Section 7.1.2.1.46, “Emergency Response Facility 

Data System”), and chemistry laboratory air supply and exhaust systems (UFSAR Section 

9.4.3.2.4, “Chemistry Laboratory Expansion”). The applicant was requested to justify the 

exclusion of the previously noted systems from Table 2.2-1.

In its response, by letter dated March 20, 2012, the applicant provided the following 

clarifications of where the above systems are located:

 • The emergency response facilities data system and plant monitoring system are subsystems 

of the miscellaneous I&C system, which is described in Table 2.2-1 as not being within the 

scope of license renewal.

 • The chemistry laboratory air supply and exhaust systems is a subsystem of the 

miscellaneous ventilation system, which is described in Table 2.2-1 as not being within the 

scope of license renewal. 

 • The area radiation monitoring system is a subsystem of the plant leak detection and 

radiation monitoring system, which is included in LRA Table 2.2-1 as being within the scope 

of license renewal.

Based on its review, the staff finds the applicant’s response to RAI 2.2-1 acceptable 

because the applicant explained that these systems are subsystems within systems that 

are included in Table 2.2-1. Therefore, the staff’s concern described in RAI 2.2-1 is 

resolved.

2.2.4 Conclusion 

The staff reviewed LRA Section 2.2, the RAI 2.2-1 response, 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 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:

 • reactor vessel, internals, and reactor coolant system (RCS)

 • engineered safety features (ESF) systems

 • auxiliary systems
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 • steam and power conversion systems

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, 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 included in the scope of license renewal all

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 the functions are 

performed with moving parts or a change in configuration or properties or 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 RCS SCs subject to an AMR for 

license renewal. The applicant described the supporting SCs of reactor vessel, internals, and 

RCS in the following LRA sections:

 • 2.3.1.1, “Reactor Coolant Pressure Boundary”

 • 2.3.1.2, “Reactor Pressure Vessel”

 • 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.
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2.3.1.1 Reactor Coolant Pressure Boundary

2.3.1.1.1 Summary of Technical Information in the Application 

The RCPB consists of those systems and components that contain or transport fluids coming 

from, or going to, the reactor core. The reactor recirculation system provides coolant flow 

through the core. The reactor recirculation system consists of the two recirculation pump loops 

external to the reactor vessel. Each external loop contains one motor-driven recirculation pump 

and provides the piping path to the reactor vessel jet pumps. The reactor recirculation system is 

mainly within primary containment; however, the system has instrumentation lines that 

penetrate containment, with tubing, valves, and transmitters in the reactor building outside the 

primary containment. 

The intended functions of the RCPB within the scope of license renewal include the following:

 • maintains integrity of RCPB

 • provides isolation and integrity of primary containment

 • provides structural support or restraint to SSCs in scope for license renewal

 • senses process conditions and generates reactor protection system (RPS ) or ESF actuation 

signals

 • provides capability to trip recirculation pumps

 • provides the flow path to, maintains the pressure boundary of, and receives isolation signal 

from the standby liquid control (SLC) injection

LRA Table 2.3.1-1 identifies the RCPB component types within the scope of license renewal 

and subject to an AMR.

2.3.1.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.1 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.1.1.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the reactor coolant pressure boundary components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has 

adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).
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2.3.1.2 Reactor Pressure Vessel

2.3.1.2.1 Summary of Technical Information in the Application 

The reactor pressure vessel (RPV) is a vertical, cylindrical pressure vessel of welded 

construction designed by General Electric (GE). The RPV has a cylindrical shell, bottom head, 

and upper head. Both the upper head and upper shell have a forged flange welded to them for 

vessel closure. The upper head is secured to the RPV by studs, nuts, and washers. The RPV 

vessel flanges are sealed by two concentric rings designed to prevent leakage through the inner 

or outer seal at any operating condition.

The intended functions of the RPV within the scope of license renewal include the following:

 • maintains the RCPB

 • provides a barrier to radiation release

 • contains and supports the reactor core, internals, and coolant moderator 

 • provides a floodable volume in which the core can be adequately cooled in the event of a 

breach in the RCPB

 • provides structural support or restraint to SSCs in scope for license renewal

 • provides the flow path for SLC system injection

The RPV evaluation boundary consists of the vessel shell, heads, closure flanges, vessel 

closure bolting, nozzles, safe ends, safe end extensions, nozzle caps, nozzle flanges (including 

blank flanges), in-core penetrations (housings), internal attachments (jet pump riser support 

pads, core spray (CS) brackets, steam dryer holddown brackets, guide rod brackets, 

surveillance specimen brackets, steam dryer support brackets, and feedwater sparger 

brackets), stabilizer brackets, support skirt and refueling bellows bracket, control rod drive

(CRD) stub tubes and housings, and associated pressure boundary bolting.

LRA Table 2.3.1-2 identifies the RPV component types within the scope of license renewal and 

subject to an AMR.

2.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.1 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.1.2.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the RPV components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the system 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).
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2.3.1.3 Reactor Vessel Internals

2.3.1.3.1 Summary of Technical Information in the Application 

The reactor vessel internal components include the core (including fuel assemblies and control 

rod assemblies, control rod guide thermal sleeves, guide rods, in-core dry tubes, in-core guide 

tubes), core support structure (control rode guide tubes, core plate and holddown bolts, fuel 

supports, shroud, shroud support, access hole covers, and top guide), CS lines, rings, nozzles, 

thermal sleeves and spargers, differential pressure line, feedwater spargers, jet pump 

assemblies and instrumentation, low-pressure coolant injection (LPCI) couplings, steam dryer, 

shroud head, and steam dryer assembly.

The intended functions of the reactor vessel internals (RVIs) within the scope of license renewal 

include the following:

 • maintain the RCPB

 • contain and support the reactor core, internals, and coolant moderator

 • provide a floodable volume in which the core can be adequately cooled in the event of a 

breach in the RCPB

 • maintain core geometry to ensure control rods and emergency core cooling systems (ECCS) 

can perform their safety functions

 • provide active nuclear fuel and cladding

 • provide emergency reactor shutdown capability

 • provide negative reactivity to achieve and maintain shutdown

 • distribute coolant

The RVIs evaluation boundary includes the core support subcomponents and other reactor 

vessel internal components. UFSAR Figure 3.9-4 provides the details of the RV internals.

LRA Table 2.3.1-3 identifies the RVIs component types within the scope of license renewal and 

subject to an AMR.

2.3.1.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.3 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.1.3.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the RVIs components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the system 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).
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2.3.2 Engineered Safety Features 

LRA Section 2.3.2 identifies the ESF SCs subject to an AMR for license renewal. The applicant 

described the supporting SCs of the ESFs in the following LRA sections:

 • 2.3.2.1, “Containment Atmosphere Control System”

 • 2.3.2.2, “Core Spray System”

 • 2.3.2.3, “High-Pressure Coolant Injection System”

 • 2.3.2.4, “Reactor Core Isolation Cooling System”

 • 2.3.2.5, “Residual Heat Removal System”

 • 2.3.2.6, “Standby Gas Treatment System”

The staff’s findings on review of LRA Sections 2.3.2.1 – 2.3.2.6 are in SER 

Sections 2.3.2.1 –2.3.2.6.

2.3.2.1 Containment Atmosphere Control System

2.3.2.1.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.1 states that the purpose of the containment atmosphere control system is 

for inerting primary containment with nitrogen, purging containment with air to permit 

maintenance, limiting differential pressure between the drywell and suppression chamber, 

monitoring of containment temperature, pressure, hydrogen and oxygen levels, and controlling 

combustible gas concentrations after a loss-of-coolant accident (LOCA). The containment 

atmosphere control system is comprised of the liquid nitrogen supply subsystem that is common 

to LGS Units 1 and 2, containment inerting and purging subsystem, containment vacuum relief 

subsystem, combustible gas analyzer subsystem, and containment hydrogen recombiner 

subsystem and instrumentation used to monitor containment temperature and pressure.

The intended functions of the containment atmosphere control system are to sense process 

conditions and generate signals for reactor trip or ESF actuation, provide primary containment 

boundary, provide emergency heat removal from primary containment and provide containment 

pressure control, control combustible gas mixtures in the primary containment atmosphere, and 

resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The containment atmosphere control system is relied on in safety 

analyses or plant evaluations to perform a function that demonstrates compliance with the 

NRC‘s regulations for EQ (10 CFR 50.49), fire protection (10 CFR 50.48), and SBO 

(10 CFR 50.63).

LRA Table 2.3.2-1 identifies the containment atmosphere control system component types that 

are within the scope of license renewal and subject to an AMR.

2.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.1 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.
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2.3.2.1.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the containment atmosphere control system components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant 

has adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.2.2 Core Spray System 

2.3.2.2.1 Summary of Technical Information in the Application 

The intended functions of the CS system within the scope of license renewal include the 

following:

 • provides emergency core cooling

 • provides primary containment isolation and integrity

 • provides an injection flowpath into the vessel for high-pressure coolant injection (HPCI)

 • provides secondary containment boundary

 • senses process conditions and generates RPS or ESF actuation signals

The CS evaluation boundary includes the CS suction strainers in the suppression pool through 

the upstream side of the CS discharge outboard containment isolation valve; beyond this point 

is considered part of the RCPB.LRA Table 2.3.2-2 identifies the CS system component types 

within the scope of license renewal and subject to an AMR.

2.3.2.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.2 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.2.2.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the CS system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.2.3 High-Pressure Coolant Injection System

2.3.2.3.1 Summary of Technical Information in the Application 

The HPCI system is designed to pump water into the RPV over a wide range of pressures. The 

HPCI system uses a steam turbine to drive a booster and main pump. To assist with RPV 

depressurization, the driving steam is taken from upstream of the main steam isolation valve
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(MSIV). Water is delivered to the RPV though one of the CS spargers and one of the feedwater 

headers to the feedwater spargers. The HPCI system normally takes suction from the 

condensate storage tank (CST), but can take suction from the suppression pool. The HPCI

pump is located sufficiently below both suction sources to provide flooded pump suction and to 

meet net positive suction head requirements.

The intended functions of the HPCI system within the scope of license renewal include the 

following:

 • provides emergency core cooling

 • provides primary containment isolation and integrity

 • senses process conditions and generates RPS or ESF actuation signals

LRA Table 2.3.2-3 identifies the HPCI system component types that are within the scope of 

license renewal and subject to an AMR.

2.3.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.3 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.2.3.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the HPCI system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.2.4 Reactor Core Isolation Cooling System 

2.3.2.4.1 Summary of Technical Information in the Application 

The reactor core isolation cooling (RCIC) system consists of a turbine, pump, piping, valves, 

accessories, and instrumentation capable of delivering makeup water to the RPV to maintain 

sufficient reactor water inventory and adequate core cooling. The RCIC is automatically 

initiated at a predetermined low reactor water level. The RCIC turbine steam supply comes 

from the RPV just upstream of the MSIV valves. 

During normal modes of operation the turbine-driven pump takes suction from the condensate 

CST and injects into the RPV through one of the feedwater headers to feedwater spargers. 

There is automatic suction source switchover to the suppression pool when the CST is 

exhausted.

The intended functions of the RCIC system within the scope of license renewal include the 

following:

 • provides high-pressure coolant flow to the reactor vessel
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 • removes residual heat from the RCS

 • provides primary containment isolation and integrity

 • senses process conditions and generates RPS or ESF actuation signals

LRA Table 2.3.2-4 identifies the RCIC system component types within the scope of license 

renewal and subject to an AMR.

2.3.2.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3..2.4 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.2.4.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the RCIC system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.2.5 Residual Heat Removal System 

2.3.2.5.1 Summary of Technical Information in the Application 

The residual heat removal (RHR) system is a four loop system. Each loop has its own 

motor-driven pump, piping, valves, instrumentation, controls, and a suction source from the 

suppression pool, and is capable of discharging water to the RPV or back to the suppression 

pool. In addition, loops A and B have heat exchangers, the ability to take suction from the 

reactor recirculation system suction or from the spent fuel pool. The safety-related SW system 

cools the heat exchangers. Loops A and B also can discharge to reactor recirculation 

discharge. Additionally, the pumps in loops C and D can be aligned by crossties for use as 

alternates to the pumps in loops A and B, respectively.

A spool piece is permanently installed on the shutdown cooling piping for making connection to 

the fuel pool cooling system so that RHR can provide assistance to cooling the fuel pool.

The RHR system has six modes of operation:

 • LPCI

 • suppression pool cooling (SPC)

 • containment spray cooling (CSC)

 • shutdown cooling (SDC)

 • alternate decay heat removal 

 • fuel pool cooling
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The intended functions of the RHR system within the scope of license renewal include the 

following:

 • removes residual heat from the RCS

 • provides primary containment isolation and integrity

 • provides emergency core cooling

 • provides emergency heat removal and pressure control to containment

 • maintains suppression pool temperature below that required to condense steam after a 

LOCA

 • provides additional cooling capacity for fuel pool

LRA Table 2.3.2-5 identifies the residual heat removal system component types that are within 

the scope of license renewal and subject to an AMR.

2.3.2.5.2 Staff Evaluation

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 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 staff’s review identified an area in which additional information was necessary to complete 

the review of the applicant’s scoping and screening results. In a letter dated February 17, 2012, 

the staff issued RAI 2.3.2.5-1, noting an inconsistency between units on the color coded green 

scoping for valves 1175A and 2175B compared to corresponding valves 2175A and 1175B and 

adjacent piping and pipe caps color coded red.

In a letter dated March 5, 2012, the applicant stated that the test connections containing tail 

pipe, pipe caps, and valves 1175B and 2175A are correctly highlighted in red as shown on 

drawings LR-M-51 sheets 3, zone G-6, and 5, zone G-3. The test connections containing 

valves 1175A and 2175B were inadvertently shown highlighted in green on drawings LR-M-51,

sheet 1, zone G-3, and sheet 7, zone G-6, and should be shown highlighted in red. Drawing 

LR-M-51 sheets 1 and 7 will be revised to show the correct highlighting.

Based on its review, the staff finds the applicant’s response to RAI 2.3.2.5-1 acceptable. The 

applicant clarified the discrepancy in the highlighting of RHR/CSC system components and 

revised the drawing in question. No new systems or components were included in the scope of 

license renewal as a result of this RAI response. Therefore, the staff’s concern described in 

RAI 2.3.2.5-1 is resolved.

2.3.2.5.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the RHR components within the scope of license renewal, as 
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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 stated in 10 CFR 54.21(a)(1).

2.3.2.6 Standby Gas Treatment System 

2.3.2.6.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.6 states that the standby gas treatment system (SGTS) filters halogen and 

particulate concentrations in gases that are potentially present in secondary containment 

following DBAs. The system automatically initiates, isolates, and maintains a negative pressure 

in secondary containment during these conditions.

The intended functions of the SGTS are to provide a secondary containment boundary, control 

and treat radioactive materials released to the secondary containment, and resist 

nonsafety-related SSC failure that could prevent satisfactory accomplishment of a safety-related 

function. The SGTS is relied upon in safety analyses or plant evaluations to perform a function 

that demonstrates compliance with the NRC’s regulations for fire protection (10 CFR 50.48) and 

EQ (10 CFR 50.49).

LRA Table 2.3.2-6 identifies the SGTS component types within the scope of license renewal 

and subject to an AMR.

2.3.2.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.6 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.2.6.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the SGTS components within the scope of license renewal, as required 

by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the system 

components subject to an AMR in accordance with the requirements stated 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:

 • 2.3.3.1, “Auxiliary Steam System”

 • 2.3.3.2, “Closed Cooling Water System”

 • 2.3.3.3, “Compressed Air System”

 • 2.3.3.4, “Control Enclosure Ventilation System”

 • 2.3.3.5, “Control Rod Drive System”

 • 2.3.3.6, “Cranes and Hoists”
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 • 2.3.3.7, “Emergency Diesel Generator Enclosure Ventilation System”

 • 2.3.3.8, “Emergency Diesel Generator System”

 • 2.3.3.9, “Fire Protection System”

 • 2.3.3.10, “Fuel Handling and Storage”

 • 2.3.3.11, “Fuel Pool Cooling and Cleanup System”

 • 2.3.3.12, “Nonsafety-Related Service Water System”

 • 2.3.3.13, “Plant Drainage System”

 • 2.3.3.14, “Primary Containment Instrument Gas System”

 • 2.3.3.15, “Primary Containment Leak Testing System”

 • 2.3.3.16, “Primary Containment Ventilation System”

 • 2.3.3.17, “Process Radiation Monitoring System”

 • 2.3.3.18, “Process and Post-Accident Sampling System”

 • 2.3.3.19, “Radwaste System”

 • 2.3.3.20, “Reactor Enclosure Ventilation System”

 • 2.3.3.21, “Reactor Water Cleanup System”

 • 2.3.3.22, “Safety-Related Service Water System”

 • 2.3.3.23, “Spray Pond Pump House Ventilation System”

 • 2.3.3.24, “Standby Liquid Control System”

 • 2.3.3.25, “Traversing In-core Probe System”

 • 2.3.3.26, “Water Treatment and Distribution System”

The staff’s findings on review of LRA Sections 2.3.3.1-2.3.3.26 are in SER Sections 

2.3.3.1-2.3.3.26.

Auxiliary Systems Generic Requests for Additional Information

In RAI 2.3.3-1, dated March 9, 2012, the staff noted 20 instances on drawings in which the 

staff could not determine the basis for the change in scoping criteria from safety-related to 

nonsafety-related (i.e 10 CFR 54.4(a)(1) to 10 CFR 54.4(a)(2)). The applicant was 

requested to clarify the scoping classification changes at these 20 locations.

In its response, by letter dated March 20, 2012, the applicant provided information to clarify

the basis for the change in scoping criteria from 10 CFR 54.4(a)(1) to 10 CFR 54.4(a)(2) for 

all 20 locations. The applicant stated that piping and components that perform or support 

a safety-related function are within the scope of license renewal based on the criteria in 

10 CFR 54.4(a)(1) and that nonsafety-related piping components within the control 

enclosure, reactor enclosure, diesel generator enclosure, and primary containment that 

contain fluid are included within the scope of license renewal based on the criteria in 

10 CFR 54.4(a)(2) caused by potential spacial interaction with safety-related components. 

The response stated that in six instances, the applicant determined there should not have 

been a transition from safety-related to nonsafety-related depicted on the scoping boundary 
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drawings for the locations referenced in the staff’s RAI. Therefore, the applicant stated that in 

these 6 instances the scoping boundary drawings would be revised to show the components 

referenced in the RAI as within the scope of license renewal in accordance with 

10 CFR 54.4(a)(1). For the remaining 14 locations the applicant confirmed that the scoping 

change depicted in the boundary drawing was correct and the components were correctly 

shown on the scoping drawings as within the scope license renewal in accordance with

10 CFR 54.4(a)(2). The staff reviewed the applicant’s response and found it acceptable 

because the applicant revised 6 locations to properly identify safety-related components on 

the scoping boundary drawings, and because the applicant confirmed that the remaining

14 locations depicted nonsafety-related components. 

However, the applicant’s response did not include the revised drawings depicting the correct

scoping classifications. Therefore, by letter dated May 18, 2012, the staff issued 

RAI 2.3.3-2, requesting the applicant to provide the revised scoping boundary drawings. 

Subsequent to the issuance of RAI 2.3.3-2, the staff performed NRC Inspection Procedure 

(IP) 71002 “License Renewal Inspection” review of the LGS site. During the IP 71002 

inspection, the staff confirmed that the drawings referenced in RAI 2.3.3-1 have been 

revised consistent with the applicant’s response. The staff’s concern described in 

RAI 2.3.3-2 is resolved because the staff confirmed that the subject drawings have been 

revised consistent with applicant’s RAI response.

The staff finds the applicant’s responses to RAI 2.3.3-1 and RAI 2.3.3-2 acceptable because the

applicant clarified the 20 scoping classification changes, which included six items revised from 

10 CFR 54.4(a)(2) to 10 CFR 54.4(a)(1), and revised the license renewal boundary drawings. 

The staff confirmed that the scoping classifications were corrected on the revised license renewal 

boundary drawings. No new component types were identified as a result of the applicant’s 

responses to the RAIs. Therefore, the staff’s concern described in RAIs 2.3.3-1 and 2.3.3-2 are

resolved.

2.3.3.1 Auxiliary Steam System

2.3.3.1.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.1 states that the intended function of the auxiliary steam system for license 

renewal is to resist nonsafety-related failure by maintaining leakage boundary integrity to 

preclude system interactions, and by maintaining structural support at physical interfaces with 

safety-related equipment. The LRA also states that the purpose of the auxiliary steam system is 

to provide steam for various startup and plant service functions. The system accomplishes this 

by using auxiliary steam boilers common to both LGS Units 1 and 2.

The auxiliary steam system intended function is to resist nonsafety-related SSC failure that 

could prevent satisfactory accomplishment of a safety-related function.

LRA Table 2.3.3-1 identifies the auxiliary steam system component types within the scope of 

license renewal and subject to an AMR.
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2.3.3.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.1 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.3.1.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the auxiliary steam system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately 

identified the system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).

2.3.3.2 Closed Cooling Water System

2.3.3.2.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.2 states that the closed cooling water system is a normally operating 

closed-loop cooling system designed to provide cooling water to miscellaneous reactor auxiliary 

plant equipment and auxiliary plant equipment associated with nuclear and power conversion 

systems. The LRA also states that the closed cooling water system consists of the reactor 

enclosure cooling water and turbine enclosure cooling water systems.

The intended function of the closed cooling water system is to: provide primary containment 

boundary, resist nonsafety-related SSC failure that could prevent satisfactory accomplishment 

of a safety-related function, and perform a function that demonstrates compliance with the 

NRC’s EQ regulation (10 CFR 50.49) in safety analyses or plant evaluations.

LRA Table 2.3.3-2 identifies the closed cooling water system component types that are within 

the scope of license renewal and subject to an AMR.

2.3.3.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.2 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.3.2.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the closed cooling water system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately 

identified the system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).
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2.3.3.3 Compressed Air System 

2.3.3.3.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.3 states that the compressed air system is a mechanical system designed to 

supply plant equipment with compressed air and gas and supply service air outlets located 

throughout the plant with compressed air. The purpose of the compressed air system is 

to provide a supply of compressed air or gas for operation of pneumatic devices located 

throughout the plant.

The intended function of the compressed air system is to provide primary containment boundary 

and to provide motive power to safety-related components.

LRA Table 2.3.3-3 identifies the compressed air system component types within the scope of 

license renewal and subject to an AMR.

2.3.3.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.3 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.3.3.3 Conclusion

On the basis of the staff review of the LRA and UFSAR, the staff concludes that the applicant 

has appropriately identified the compressed air system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately 

identified the system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).

2.3.3.4 Control Enclosure Ventilation System 

2.3.3.4.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.4 states that the control enclosure ventilation system is a normally operating 

mechanical system common to LGS Units 1 and 2, which provides ventilation, cooling, and 

control of environmental conditions in the control enclosure to maintain operability of 

safety-related equipment. The system also provides control of environmental conditions in the 

main control room for the safety and comfort of operating personnel.

The intended function of the control enclosure ventilation system is to provide a centralized area 

for control and monitoring of nuclear safety-related equipment and to maintain emergency 

temperature limits within areas containing safety-related components. The intended function of 

the control enclosure ventilation system is also to resist nonsafety-related SSC failure that could 

prevent satisfactory accomplishment of a safety-related function. The control enclosure 

ventilation system is also relied upon in safety analyses or plant evaluations to perform a 

function that demonstrates compliance with the NRC’s regulations for fire protection 

(10 CFR 50.48), EQ (10 CFR 50.49), and SBO (10 CFR 50.63).
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LRA Table 2.3.3-4 identifies the control enclosure ventilation system component types within the 

scope of license renewal and subject to an AMR.

2.3.3.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.4 and UFSAR Sections 3.5.1.1.1, 6.4, 6.5.1.2, 7.3.2, 

9.2.10.2, 9.4.1, 9A.2.5, and 9A.3.2.2 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 the applicant has 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).

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. The staff identified that LRA 

Tables 2.3.3-4 and 3.3.2-4 do not contain all the component types of the control enclosure 

ventilation system highlighted on the drawings. Also, the tables do not list any specific 

components and their housing types associated with “ducting and components type“ (e.g., fans 

and fan housing, dampers and damper housings, fire dampers and fire damper housings, filters 

and filter housings, heating and cooling coils) as applicable.

Therefore, in a letter dated February 17, 2012, the staff issued RAI 2.3.3.4-1, requesting

clarification as to whether these component types and all other applicable component types of 

the system are within the scope of license renewal, in accordance with 10 CFR 54.4(a), and 

subject to an AMR in accordance with 10 CFR 54.21(a)(1).

In a letter dated March 5, 2012, the applicant stated that the “Ducting and Components”

component group includes fan housings, damper housings, fire damper housings, and filter 

housings. This practice is consistent with the GALL Report Table IX.B definition of ducting and 

components, which states that ducting and components includes “heating, ventilation, and 

air-conditioning (HVAC) components. Examples include ductwork equipment frames and 

housing, housing supports, including housings for valves, dampers (including louvers, gravity, 

and fire dampers), and ventilation fans.” These components are within the scope of license 

renewal and subject to an AMR. Heating and cooling coils are included in “Heat Exchanger 

Components” component type. These components are reflected in LRA Tables 3.3.2-4 

and 2.3.3-4. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.4-1 acceptable. The 

applicant clarified the discrepancy in the listing of the control enclosure ventilation system 

components. No new systems or components were included in the scope of license renewal as 

a result of this RAI response. Therefore, the staff’s concern described in RAI 2.3.3.4-1 is 

resolved.

2.3.3.4.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the control enclosure ventilation system components within the 
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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 stated in 

10 CFR 54.21(a)(1).

2.3.3.5 Control Rod Drive System

2.3.3.5.1 Summary of Technical Information in the Application 

The CRD system consists of CRD mechanisms, the scram air header, and the hydraulic 

system. The CRD hydraulic system consists of hydraulic control units, a hydraulic power supply 

(pumps), interconnecting piping, and instrumentation. The CRD hydraulic system delivers 

clean, demineralized water for driving, rapid insertion, and cooling functions related to the 

operation of the control rod drives. The hydraulic control units manage water flow to and from 

the control rod.

The scram air header provides pneumatic supply to scram pilot solenoid valves, scram

discharge volume (SDV) vent and drain valve actuators, and the hydraulic system flow control 

valve actuators. During a scram, each hydraulic control unit discharges water from the drive 

mechanisms through the scram outlet valves into the SDV. Energy from the nitrogen 

accumulators and from reactor pressure provides hydraulic power for rapid simultaneous 

insertion of all control rods.

The SDV consists of a header that drains to an instrument volume consisting of a vertical pipe 

with water level instrumentation. During normal plant operation, each SDV is empty and vented 

to the atmosphere through its open vent and drain valves. When a scram occurs, these vent 

and drain valves are closed to conserve reactor water.

LGS Unit 2 has permanent control rod friction test valves that are connected to measure the 

friction of the control rods during rod movement. These valves are manually isolated from the 

CRD system, except when friction testing is being performed.

The intended functions of the CRD system within the scope of license renewal include the 

following:

 • maintains RCPB integrity

 • provides emergency reactor shutdown

 • provides primary containment isolation and integrity

 • senses process conditions and generates RPS or ESF actuation signals

 • provides alternate means of venting the scram air header to cause insertion of control rods

LRA Table 2.3.3-5 identifies the CRD system component types that are within the scope of 

license renewal and subject to an AMR.

2.3.3.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.5 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.
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2.3.3.5.3 Conclusion

On the basis of its review of the LRA and UFSAR,, the staff concludes that the applicant has 

appropriately identified the CRD system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.6 Cranes and Hoists

2.3.3.6.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.6 states that the cranes and hoists are load-handling bridge cranes, jib 

cranes, lifting devices, monorails, and hoists provided throughout the facility to support 

operation and maintenance activities.

The intended function of the cranes and hoists is to provide physical support, shelter and 

protection for safety-related SSCs, and to provide a safe way to handle safety-related 

components and loads above or near safety-related components.

LRA Table 2.3.3-6 identifies the cranes and hoists component types within the scope of license 

renewal and subject to an AMR.

2.3.3.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.6 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff reviewed LRA Section 2.3.3.6 

and the UFSAR as described in SER Section 2.3. The staff’s review did not identify the need 

for any additional information.

2.3.3.6.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the cranes and hoists components within the scope of license renewal, 

as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified 

the system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.7 Emergency Diesel Generator Enclosure Ventilation System 

2.3.3.7.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.7 states that the EDG enclosure ventilation system is a standby 

safety-related mechanical system that provides ventilation and control of environmental 

conditions in the EDG enclosure.

The intended function of the EDG enclosure ventilation system is to maintain emergency 

temperature limits within areas containing safety-related components. The EDG enclosure 

ventilation system is relied upon in safety analyses or plant evaluation to perform a function that 
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demonstrates compliance with the NRC’s regulations for fire protection (10 CFR 50.48) and 

SBO (10 CFR 50.63).

LRA Table 2.3.3-7 identifies the EDG enclosure ventilation system component types within the 

scope of license renewal and subject to an AMR.

2.3.3.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.7 and UFSAR Sections 3.5.1.1.1 and 9.4.6 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 included in the scope of license renewal all components with intended 

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the 

applicant has identified as within the scope of license renewal to verify that the applicant 

included all passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. In a letter dated February 17, 2012, the 

staff issued RAI 2.3.3.7-1, stating that LRA Tables 2.3.3-7 and 3.3.2-7 do not contain all the 

component types for the EDG enclosure ventilation system highlighted on the drawings. The 

tables do not list any specific components and their housing types associated with “ducting and 

components type,” such as fans and fan housing, dampers and damper housings, fire dampers 

and fire damper housings, filters and filter housings, heating and cooling coils etc., as 

applicable.

Therefore, the staff requested clarification as to whether these component types and all other 

applicable component types of the system are within the scope of license renewal in 

accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 

10 CFR 54.21(a)(1).

In a letter dated March 5, 2012, the applicant stated that “Ducting and Components” component 

group includes fan housings, damper housings, fire damper housings, and filter housings. This 

practice is consistent with the GALL Report Table IX.B definition of ducting and components, 

which states that ducting and components includes “heating, ventilation, and air-conditioning 

(HVAC) components. Examples include ductwork . . . equipment frames and housing, housing 

supports, including housings for valves, dampers (including louvers, gravity, and fire dampers), 

and ventilation fans.” The “Ducting and Components” component type listed in LRA 

Table 3.3.2-7 includes ventilation and fire damper housings and fan housings. These 

components are subject to an AMR. Fans, dampers, and fire dampers are active components 

and not subject to an AMR. There are no filters or cooling coils in this system. As indicated on 

drawing LR-M-81, sheets 1 and 3, and LRA Tables 2.3.3-1 and 3.3.2-1, the steam supply to the 

unit heaters is evaluated with the auxiliary steam system.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.7-1 acceptable. The 

applicant clarified the discrepancy in the listing of the EDG enclosure ventilation system 

components. No new systems or components were included in the scope of license renewal as 

a result of this RAI response. Therefore, the staff’s concern described in RAI 2.3.3.7-1 is 

resolved.
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2.3.3.7.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the EDG enclosure ventilation 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 stated in 

10 CFR 54.21(a)(1).

2.3.3.8 Emergency Diesel Generator System 

2.3.3.8.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.8 states that the EDG system is a standby mechanical system designed to 

provide sufficient electrical power to important plant equipment when normal offsite power 

sources are not available.

The intended function of the EDG system is to provide motive power to safety-related 

components and to resist nonsafety-related SSC failure that could prevent satisfactory 

accomplishment of a safety-related function. The EDG system is relied upon in safety analysis 

or plant evaluations to perform a function that demonstrates compliance with the NRC’s 

regulations for SBO (10 CFR 50.63) and fire protection (10 CFR 50.48).

LRA Table 2.3.3-8 identifies the EDG system component types within the scope of license 

renewal and subject to an AMR.

2.3.3.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.8, UFSAR Sections 8.3.1, 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. The staff’s review identified 

areas in which additional information was necessary to complete the review of the 

applicant’s scoping and screening results. The applicant responded to the staff’s requests 

for additional information as discussed below.

In RAI 2.3.3.8-1, dated March 9, 2012, the staff noted that license renewal boundary 

drawings LR-M-20, sheets 8 and 14, location F-5, depict ejector casings within the scope of 

license renewal for 10 CFR 54.4(a)(1). However, the ejector casing is not listed in 

Table 2.3.3-8 as a component type subject to an AMR. The applicant was requested 

to justify the exclusion of the ejector casing component type from LRA Table 2.3.3-8.

In its letter dated March 20, 2012, the applicant stated that the ejector bodies are included in 

LRA Table 2.3.3-8 as a component type, “Piping, piping components, and piping elements.”

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.8-1 acceptable 

because the applicant clarified that the ejector casing bodies are listed in LRA 

Table 2.3.3-8 as a “Piping, piping components, and piping elements” component type. 

Therefore, the staff’s concern described in RAI 2.3.3.8-1 is resolved.
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During its review, the staff noted that license renewal boundary drawings LR-M-20,

sheets 8 and 14, locations B-4 and D-4, depict emergency diesel generator turbocharger 

casings as within the scope of license renewal for 10 CFR 54.4(a)(1). However, the 

emergency diesel generator turbocharger casing is not listed in LRA Table 2.3.3-8 as a 

component type subject to an AMR. Therefore, by letter dated March 9, 2012, the staff 

issued RAI 2.3.3.8-2 requesting the applicant to identify which component type in LRA 

Table 2.3.3-8 included the emergency diesel generator turbocharger casing, or to justify its 

exclusion from LRA Table 2.3.3-8.

In its letter dated March 20, 2012, the applicant stated that the emergency diesel generator 

turbocharger casings, shown on license renewal boundary drawing LR-M-20, sheets 8 and 14, 

are components subject to an AMR that are listed in LRA Table 2.3.3-8 as “Turbocharger 

Casing.”

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.8-2 acceptable 

because the applicant stated that the emergency diesel generator turbocharger casing are 

included in the component type “Turbocharger Casing” listed in LRA Table 2.3.3-8. 

Therefore, the staff’s concern described in RAI 2.3.3.8-2 is resolved.

In RAI 2.3.3.8-3, dated March 9, 2012, the staff noted that license renewal boundary 

drawings LR-M-20, sheets 8 and 14, location F-3, depict exhaust silencer housings within 

the scope of license renewal for 10 CFR 54.4(a)(1). However, the exhaust silencer 

housing is not listed in Table 2.3.3-8 as a component type subject to an AMR. The 

applicant was requested to justify the exclusion of the exhaust silencer component type 

from LRA Table 2.3.3-8.

In its letter dated March 20, 2012, the applicant stated that the exhaust silencer housing and 

internals are subject to an AMR and are included in LRA Table 2.3.3-8 as a component type,

“Piping, piping components, and piping elements.”

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.8-3 acceptable 

because the applicant clarified that the exhaust silencer housing and internals are included in 

LRA Table 2.3.3-8 as a “Piping, piping components, and piping elements” component 

type. Therefore, the staff’s concern described in RAI 2.3.3.8-3 is resolved.

In RAI 2.3.3.8-4, dated March 9, 2012, the staff noted license renewal boundary drawings 

LR-M-20, sheets 3 and 9, locations D-3 and D-7, depict flame arrestor housings within the 

scope of license renewal for 10 CFR 54.4(a)(1). However, the flame arrestor housing is 

not listed in LRA Table 2.3.3-8 as a component type subject to an AMR. The applicant was 

requested to justify the exclusion of the flame arrestor housing component type from LRA 

Table 2.3.3-8.

In its letter dated March 20, 2012, the applicant stated that the flame arrestor housings are 

subject to an AMR and are included in LRA Table 2.3.3-8 as a component type, “Piping, piping 

components, and piping elements.”

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.8-4 acceptable 

because the applicant clarified that the flame arrestor housings are included in LRA 

Table 2.3.3-8 as a “Piping, piping components, and piping elements” component type. 

Therefore, the staff’s concern described in RAI 2.3.3.8-4 is resolved.
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In RAI 2.3.3.8-5, dated March 9, 2012, the staff noted LRA Section 2.1.1 states that the 

in-scope portions of mechanical systems and structures are highlighted in color on the 

license renewal boundary drawings. For the EDG system, the applicant includes the diesel 

engines within the license renewal scoping boundary. License renewal boundary drawings 

LR-M-20, sheets 3 and 9, location F-5, depict diesel engines 1AG501 and 2AG501 as not 

being within the scope of license renewal. Although the applicant states in Note 7 on 

license renewal boundary drawing LR-M-20 that the in-scope diesel fuel oil supply system 

boundary stops at the fuel injectors of the diesel generator because the fuel injectors are

excluded from AMR, the license renewal boundary drawings appear to contradict the 

applicant’s methodology for highlighting the in-scope components (the diesel engines) as 

described in LRA Section 2.1.1. The applicant was requested to justify why the diesel 

engines depicted on license renewal boundary drawings LR-M-20, sheets 3 and 9, are 

indicated as not being within the scope of license renewal.

In its letter dated March 20, 2012, the applicant explained that the diesel engine boxes, as 

shown on license renewal boundary drawings LR-M-20, sheets 3 and 9, were not shown in 

green because those drawings depict the diesel fuel oil storage and transfer system 

components within the scope of license renewal and that the diesel engine box is outside the 

boundary of the diesel fuel oil storage and transfer system. The applicant also stated that the 

first paragraph on LRA page 2.3-84, under the scoping boundary discussion in LRA 

Section 2.3.3.8, states that the license renewal scoping boundary for the diesel fuel oil storage 

and transfer system ends at the connection point to the diesel engines. The applicant further 

stated that LRA Section 2.3.3.8 does include the diesel engines within the scoping boundary for 

license renewal.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.8-5 acceptable 

because the staff confirmed that the applicant has properly identified the components in the 

diesel fuel oil storage and transfer system that are within the scope of license renewal and 

the staff confirmed that LRA Section 2.3.3.8 lists the diesel engines as within the scope of 

license renewal. Therefore, the staff’s concern described in RAI 2.3.3.8-5 is resolved.

2.3.3.8.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI responses, the staff concludes the 

applicant appropriately identified the EDG 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 stated in 

10 CFR 54.21(a)(1).

2.3.3.9 Fire Protection System 

2.3.3.9.1 Summary of Technical Information in the Application 

The fire protection system is a mechanical system common to LGS Units 1 and 2, which is 

designed to provide detection and suppression of a fire at the plant. The fire protection system 

includes water, foam, carbon dioxide, and halon suppression systems. It also includes active 

and passive features such as fire doors, dampers, penetration seals, fire wraps, fire barrier walls 

and slabs, and oil retention dikes. 
2-53

The fire protection system is intended to resist nonsafety-related SSC failure that could prevent 

satisfactory accomplishment of a safety-related function. The fire protection system has 

leakage boundary intended function and the potential for spatial interaction with safety-related 

equipment located in the vicinity of water-filled fire protection system piping. The fire protection 

system also is relied upon in the safety analyses or plant evaluations to perform a function that 

demonstrates compliance with the NRC’s regulations for fire protection in 10 CFR 50.48 for LGS 

Units 1 and 2. The fire protection system also provides the capability to control postulated fires 

in plant areas to maintain safety shutdown ability.

LRA Table 2.3.3-9 identifies the fire protection system component types within the scope of 

license renewal and subject to an AMR.

2.3.3.9.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.9, the UFSAR, and LRA drawings using the evaluation 

methodology described in SER Section 2.3 and 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 included in the scope of license renewal all 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 included all passive 

or long-lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1).

The staff also reviewed the following fire protection document cited in the CLB listed in the LGS 

Units 1 and 2 Operating License Conditions 2.C(3): NRC Safety Evaluation Report, issued 

August 1983, through Supplement 9, issued August 1989, and Safety Evaluation, dated

November 20, 1995.

Based on the documents above, the staff reviewed the LGS Units 1 and 2 commitment to 

10 CFR 50.48, “Fire Protection” (i.e., approved fire protection program). The review consisted 

of a point-by-point comparison with Appendix A to the Branch Technical Position Chemical and 

Mechanical Engineering Branch 9.5-1, “Guidelines for Fire Protection for Nuclear Power Plants,” 

Revision 2, issued July 1981, documented in the UFSAR Section 9.5.1, and Appendix 9A, “Fire 

Protection Evaluation Report.”

During its review of LRA Section 2.3.3.9, the staff identified areas in which additional information 

was necessary to complete its review of the applicant’s scoping and screening results.

By letter dated January 24, 2012, the staff issued RAI 2.3.3.9-1, noting that the LRA boundary 

drawing LR-M-22, sheet 5, at location F3, shows the cable spreading room’s fire walls and 

associated components, including fire doors, fire dampers, and penetration seals as out of 

scope (i.e., not colored in green). The staff requested the applicant to verify whether the cable 

spreading room’s fire walls and associated components are in the scope of license renewal in 

accordance with 10 CFR 54.4(a) and if they are subject to an AMR in accordance with 

10 CFR 54.21(a)(1). The staff requested that if these fire walls and associated components are 

excluded from the scope of license renewal and are not subject to an AMR, the applicant

provide justification for the exclusion.

By letter dated February 16, 2012, the applicant responded to RAI 2.3.3.9-1. The applicant 

stated that the cable spreading room’s fire walls, as shown on boundary drawing LR-M-22,

sheet 5, location F3, are in the scope of license renewal in accordance with 10 CFR 54.4(a) and 
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subject to an AMR in accordance with 10 CFR 54.21(a)(1) as shown on LRA Table 3.3.2-4. The 

boundary drawings were prepared to only show the mechanical systems and equipment that are 

in scope for license renewal, as described in boundary drawing LR-M-00, sheet 2, Note 3. The 

fire walls are structural components and were, therefore, not shown as green on the LR-M-22,

sheet 5, boundary drawing. Further, the applicant stated that the cable spreading room’s fire 

walls associated components, including fire doors and penetration seals, are in the scope of 

license renewal in accordance with 10 CFR 54.4(a) as shown on LRA Table 3.3.2-9. These 

components are subject to an AMR in accordance with 10 CFR 54.21(a)(1). The fire dampers 

are in the scope of license renewal in accordance with 10 CFR 54.4(a). The fire dampers are 

active per NEI 95-10; therefore, the dampers are not subject to an AMR and were not included 

in LRA Table 3.3.2-9. However, the damper housing is passive and is subject to an AMR. The 

damper housings are evaluated with the control enclosure ventilation system AMR included in 

the component type of ducting and components as shown on LRA Table 3.3.2-4.

The staff reviewed the applicant’s response to RAI 2.3.3.9-1, which confirmed that the cable 

spreading room’s fire walls and associated components in question, including fire doors, fire 

dampers, and penetration seals, are in the scope of license renewal and subject to an AMR. 

Therefore, the staff’s concern described in RAI 2.3.3.9-1 is resolved.

By letter dated January 24, 2012, the staff issued RAI 2.3.3.9-2 and asked the applicant to 

determine if LRA Tables 2.3.3-9 and 3.3.2-9 should include the following fire protection 

components:

 • fire hose stations, fire hose connections, and hose racks

 • fire protection water curtain systems in the reactor enclosures and hatchways

 • floor drains for fire water

 • passive components in fire protection water and foam solution storage tanks’ heat 

exchanger

 • fire dampers

 • fire retardant coating (fireproofing material) for structural steel members 

 • passive components in diesel-driven fire pump engine

 • passive components in lightning plant protection system (National Fire Protection 

Association (NFPA) 78, Lightning Protection Code)

If the applicant determined that LRA Tables 2.3.3-9 and 3.3.2-9 should not include these 

components, the staff asked the applicant to justify the exclusion of these components from the 

scope of license renewal.

In its letter dated February 16, 2012, the applicant provided the results of the scoping and 

screening for the fire protection component types addressed in RAI 2.3.3.9-2.

In reviewing its response to RAI 2.3.3.9-2, the staff found that the applicant had addressed and 

resolved each item in the RAI, as discussed below.

Hose stations, hose connections, and hose racks are in the scope of license renewal and 

subject to an AMR. These items include valves, couplings, and fittings, and are included in LRA 
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Table 3.3.2-9 as the “Valve Body,” “Piping,” “Piping Components,” and “Piping Elements,”

component types. The applicant determined that the fire hoses’ associated racks are 

periodically replaced in accordance with NFPA standards and are, therefore, short-lived and not 

subject to an AMR. 

The applicant confirmed that water curtain systems are included in the scope of license renewal, 

and system components (values, spray nozzles, and piping) are evaluated under items 

description “Valve Body,” “Spray Nozzles,” “Piping,” “Piping Components,” and “Piping 

Elements,” in LRA AMR Table 3.3.2-9.

The floor drains for fire water are evaluated under “Plant Drainage System” in LRA 

Section 2.3.3.13; they are in the scope of license renewal and subject to an AMR. The drains 

are included in LRA AMR Table 3.3.2-13 as the piping, piping components, and piping elements 

component type.

The applicant stated that the foam solution tank and backup fire water storage tank are within 

the scope of license renewal. The applicant further stated there is no heat exchanger installed 

in these tanks and no passive subcomponents of these tanks that would be subject to an AMR.

The applicant confirmed that fire damper housings are passive components and subject to an 

AMR. The damper housings are listed in LRA AMR Tables 3.3.2-4, 3.3.2-20, 3.3.2-7, and 

3.3.2-23 in the ducting and components component type. 

Fire retardant coating on structural steel is known as “Cafecote” and is included in the 

component category “Fire Barriers” in LRA Table 3.3.2-9. It is in the scope of license renewal 

and subject to an AMR.

The applicant included passive components in diesel-driven fire pump engines in the scope of 

license renewal. The applicant stated that these components are not subject to an AMR 

because the diesel engines include various components necessary to support engine operation. 

Many of these components are either located internal to the engine or are physically mounted 

on the engine. These components are considered integral subcomponent parts of the active 

diesel engine assembly. Further, the applicant clarified that the fuel oil components that are not 

part of the active diesel engine assembly are subject to an AMR. These components are the 

diesel oil day tank and fuel inlet and return piping and components from the tank up to the diesel 

engine assembly. The applicant also confirmed that these components are included in LRA 

Table 3.3.2-9 as the component type tanks (diesel oil day tank), valve body, and piping, piping 

components, and piping elements.

In regard to passive components in the lightning plant protection system, the applicant stated 

that LGS does not have a plant lightning protection system; however, passive lightning 

protection components at LGS Units 1 and 2 are provided for equipment and personnel 

protection. 

By letter dated April 13, 2012, the staff issued followup RAI 3.3.2.9-2.1, requesting the applicant 

to clarify why the passive lightning protection components are not required for compliance with 

10 CFR 50.48 and within the scope of license renewal. The staff requested the applicant to 

justify excluding these components from the scope of license renewal and an AMR.
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In its letter dated April 27, 2012, the applicant stated that the purpose of the lightning protection 

system is to provide protection of equipment and personnel from hazards from exposure of 

lightning. Further, the applicant stated that lighting protection at LGS Units 1 and 2 is provided 

for the implementation of good design practice and for insurance and property protection 

purposes.

Based on its review, the staff finds the applicant’s response to RAI 3.3.2.9-2.1 acceptable 

because the applicant explained that the lightning protection system at LGS Units 1 and 2 is for 

property protection and loss prevention and, therefore, not safety-related. The staff also 

confirmed that NRC SER, dated August 1983, through Supplement 9, dated August 1989, and 

Safety Evaluation, dated November 20, 1995, do not discuss the lightning protection 

system. Therefore, the staff’s concern described is RAI 2 RAI 3.3.2.9-2.1 is resolved. 

Based on its review, the staff found that the applicant had addressed and resolved each item in

response to the RAI as discussed above. Therefore, the staff found the response to 

RAI 2.3.3.9-2 acceptable for the purpose of determining if the applicant has adequately 

identified the fire protection system components within the scope of license renewal.

By letter dated January 24, 2012, the staff issued RAI 2.3.3.9-3, stating that LRA Section 2.4, 

“Scoping and Screening Results: Structures,” provides the scoping and screening results of 

various structures within the scope of license renewal and subject to an AMR. Further, 

Section 2.4 states that the fire barriers are evaluated separately with the fire protection system, 

LRA Section 2.3.3.9. LRA Table 2.3.3.9 includes fire barriers (doors), fire barriers (fire-rated 

enclosures), fire barriers (for steel components), fire barriers (penetration seals), fire barriers 

(walls and slabs), which are subject to an AMR. The staff requested the applicant to provide a 

summary of the list of buildings or structures where fire barriers are credited and the specific 

types of barriers at these locations in the LGS’s fire protection program.

By letter dated February 16, 2012, the applicant responded to RAI 2.3.3.9-3 and stated that the 

fire barriers within the scope of license renewal and subject to an AMR are described in LRA 

Table 2.3.3-9. These barrier types are located in structures within the scope of license renewal. 

The applicant’s response to RAI 2.3.3.9-3 included a table of the fire barrier types for each 

structure within the scope of license renewal that contain fire barriers.

In reviewing its response to RAI 2.3.3.9-3, the staff found that the applicant had addressed the 

staff concern on fire barriers credited in LGS’s fire protection program, including the specific 

type and location. Therefore, the staff’s concern described in RAI 2.3.3.9-3 is resolved.

2.3.3.9.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the fire protection 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 stated in 

10 CFR 54.21(a)(1).
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2.3.3.10 Fuel Handling and Storage System

2.3.3.10.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.10 describes the fuel handling and storage system as consisting of the spent 

fuel storage racks and special storage racks within the spent fuel storage pools and fuel 

handling equipment. The LRA states that the purpose of the fuel handling and storage system 

is to provide safe and effective storage, transport, and handling of nuclear fuel from the time it 

enters the facility until it leaves the facility.

The fuel handling and storage system’s intended functions are to prevent criticality of fuel 

assemblies stored in the spent fuel pool, provide protection for safe storage of new and spent 

fuel, provide shielding protection for personnel and equipment and components, provide safe 

means for handling safety-related components and loads above or near safety-related 

components, and resist nonsafety-related SSC failure that could prevent satisfactory 

accomplishment of safety-related functions.

LRA Table 2.3.3-10 identifies the fuel handling and storage system component types within the 

scope of license renewal and subject to an AMR.

2.3.3.10.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.10 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.3.10.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the fuel handling and storage system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has 

adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.3.11 Fuel Pool Cooling and Cleanup System 

2.3.3.11.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.11 states that the fuel pool cooling and cleanup system is a normally 

operating system designed to remove decay heat from the spent fuel pool and maintain 

specified fuel pool water temperature, level, purity, and clarity.

The intended function of the fuel pool cooling and cleanup system is to ensure cooling in the 

spent fuel pool to maintain fuel within acceptable temperature limits and to resist 

nonsafety-related SSC failure that could prevent satisfactory accomplishment of a safety-related 

function.

LRA Table 2.3.3-11 identifies the fuel pool cooling and cleanup system component within the 

scope of license renewal and subject to an AMR.
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2.3.3.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.25 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.3.11.3 Conclusion

The staff concludes that the applicant has appropriately identified the fuel pool cooling and 

cleanup system components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the system 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.12 Nonsafety-Related Service Water System 

2.3.3.12.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.12 states that the nonsafety-related SW system designed to supply the 

cooling water required for normal plant operation has no safety-related functions. The 

nonsafety-related SW system takes heat from heat exchangers in the turbine, reactor, control,

and radwaste enclosures and transfers this heat to the cooling towers where it is dissipated.

The intended function of the nonsafety-related SW system is to resist nonsafety-related SSC 

failure that could prevent satisfactory accomplishment of a safety-related function.

LRA Table 2.3.3-12 identifies the nonsafety-related SW system component types within the 

scope of license renewal and subject to an AMR.

2.3.3.12.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.12, UFSAR Section 9.2.1, 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. The staff’s review identified an area in which 

additional information was necessary to complete the review of the applicant’s scoping and 

screening results. The applicant responded to the staff’s RAI as discussed below.

In RAI 2.3.3.12-1, dated March 9, 2012, the staff noted license renewal boundary drawings 

LR-M-10, sheets 5 and 10, locations H-2 and H-4, depict the 6-inch JBD-107/207 and 

6-inch JBD-132/232 lines as being within the scope of license renewal based on the criteria 

of 10 CFR 54.4(a)(2) with continuations to and from license renewal boundary drawings 

LRM-10, sheets 3 and 8. However, the continuations of these lines on license renewal 

boundary drawings, LR-M-10, sheets 3 and 8, are depicted as not being within the scope of 

license renewal. The applicant was requested to clarify the correct scoping classification of 

these pipe lines.

In its response, dated March 20, 2012, the applicant stated that the continuations of the 

6-inch JBD-107/207 and 6-inch JBD-132/232 lines to and from license renewal boundary 

drawings LR-M-10, sheets 3 and 8 should be within the scope of license renewal up to the 
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tees with the 24-inch cooling water headers. During the onsite IP 71002 inspection, the 

staff confirmed that the drawings were revised as described in response to RAI 2.3.3.12-1.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.12-1 acceptable 

because the applicant clarified that the 6-inch JBD-107/207 and 6-inch JBD-132/232 lines, 

to and from license renewal boundary drawings LR-M-10, sheets 3 and 8, are within the 

scope of license renewal for 10 CFR 54.4(a)(2) and revised the license renewal boundary 

drawings. Therefore, the staff’s concern described in RAI 2.3.3.12-1 is resolved.

2.3.3.12.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI responses, the staff concludes the 

applicant appropriately identified the nonsafety-related SW 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 stated in 

10 CFR 54.21(a)(1).

2.3.3.13 Plant Drainage System 

2.3.3.13.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.13 states that the plant drainage system is designed to collect various liquid 

wastes generated in the operation of the plant.

The intended function of the plant drainage system is to provide emergency core cooling, in 

which the equipment provides coolant directly to the core, to resist nonsafety-related SSC 

failure that could prevent satisfactory accomplishment of a safety-related function. The plant 

drainage system is relied upon in safety analyses or plant evaluations to perform a function that 

demonstrates compliance with the NRC’s regulations for fire protection (10 CFR 50.48). LRA 

Table 2.3.3-13 identifies the plant drainage system component types within the scope of license 

renewal and subject to an AMR.

2.3.3.13.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.13, UFSAR Sections 3.4.1.1, 3.6.1, 9.3.3, 9.5.1, 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. The staff’s review identified an 

area in which additional information was necessary to complete the review of the 

applicant’s scoping and screening results. The applicant responded to the staff’s RAI as 

discussed below.

In RAI 2.3.3.13-1, dated March 9, 2012, the staff noted on license renewal boundary 

drawing, LR-M-64, sheet 1, location G-8, that the continuation of pipe lines depicted in the 

scope of license renewal could not be found on any other license renewal boundary 

drawings. The applicant was requested to locate the continuations, and if the continuation 

line cannot be shown on license renewal boundary drawings, to provide additional 

information describing the extent of the scoping boundary and to verify whether or not there 

are additional AMR component types between the continuation and the termination of the 

scoping boundary. The applicant was also requested to provide additional information to 

clarify the change in the scoping classification if a section of the piping changes scoping 

classification over the continuation.
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In its letter dated March 20, 2012, the applicant stated that the piping does not continue to 

any other license renewal boundary drawings. These drain lines originate at floor drains within 

the washdown areas and all component types to the license renewal boundary are currently 

within the license renewal scoping boundary.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.13-1 acceptable 

because the applicant provided additional descriptions of the current license renewal 

boundary for the plant drainage system and indicated that all component types within the 

scoping boundary are currently subject to an AMR. Therefore, the staff’s concern described

in RAI 2.3.3.13-1 is resolved.

2.3.3.13.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the plant drainage 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 stated in 

10 CFR 54.21(a)(1).

2.3.3.14 Primary Containment Instrument Gas System 

2.3.3.14.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.14 states that the primary containment instrument gas system is a 

mechanical system designed to provide a supply of instrument gas of suitable quality and 

pressure for operation of pneumatic devices located inside the primary containment during 

normal operations.

The intended function of the primary containment instrument gas system is to provide primary 

containment boundary, provide motive power to safety-related components, and resist 

nonsafety-related SSC failure that could prevent satisfactory accomplishment of a safety-related 

function. The primary containment instrument gas system is relied upon in safety analyses or 

plant evaluations to perform a function that demonstrates compliance with NRC regulations for 

fire protection (10 CFR 50.48), EQ (10 CFR 50.49), and SBO (10 CFR 50.63).

LRA Table 2.3.3-14 identifies the primary containment instrument gas system component types 

within the scope of license renewal and subject to an AMR.

2.3.3.14.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14, UFSAR Section 9.3.1.3, 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. The staff’s review identified areas in which additional 

information was necessary to complete the review of the applicant’s scoping and screening 

results. The applicant responded to the staff’s requests for additional information as 

discussed below.

In RAI 2.3.3.14-1, dated March 9, 2012, the staff noted license renewal boundary drawing 

LR-M-59, sheet 1, location C-6, depicts Note 5, which states, “This piping is included in 
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scope out to the seismic anchor credited for structural support of the safety-related piping 

located as shown. The nonsafety-related piping beyond this anchor location is not in 

scope.”

However, the 1-inch JCD-109 pipe continues in red, designating the piping as within the 

scope of license renewal for 10 CFR 54.4(a)(2) from Note 5 to the end of the pipe and 

including the drawing continuation marker to drawing LR-M-59, sheet 2, at location F-1. 

The continuation marker on sheet 2 also shows the pipe still in scope for 10 CFR 54.4(a)(2) 

and has another Note 5, the same as sheet 1, where the transition actually is made from 

red to black to indicate that the 1-inch JCD-109 pipe continuation changed to not being in 

scope for license renewal. For the LGS Unit 2 license renewal boundary drawing LR-M-59, 

sheet 3, location C-6, the 1-inch JCD-209 pipe has the same Note 5. There is also an 

immediate transition from red to black, which indicates that the remainder of the pipe up to 

and including the continuation marker is no longer within the scope of license renewal, as 

Note 5 indicates. There is also no duplicate Note 5 on sheet 4. The applicant was 

requested to clarify why the 1-inch JCD-109 pipe scope does not agree with Note 5 on 

license renewal boundary drawing LR-M-59, sheet 1. The applicant also was requested to 

clarify why there are differences in scoping between the 1-inch JCD-109 pipeline on 

sheets 1 and 2 and the 1-inch JCD-209 pipeline on sheets 3 and 4.

In its letter dated March 20, 2012, the applicant stated that Note 5 on license renewal boundary 

drawing LR-M-59, sheet 1, location C-6, will be deleted because it is a misleading reference. 

During the onsite IP 71002 inspection, the staff confirmed that the drawing was revised as 

described in response to RAI 2.3.3.14-1. The comparable scoping boundary for the LGS Unit 2

license renewal boundary drawing LR-M-59, sheet 3 will not need revision because the scoping 

boundary for the LGS Unit 2 1-inch JCD-209 piping does not extend onto license renewal 

boundary drawing LR-M-59, sheet 4. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.14-1 acceptable 

because the applicant revised license renewal boundary drawing LR-M-59, sheet 1, to 

delete Note 5. The staff also found the applicant’s justification of the scoping classification 

difference between LGS Unit 1 and LGS Unit 2 comparable pipelines was acceptable and 

that no additional components were required to be brought within scope of license renewal. 

Therefore, the staff’s concern described in RAI 2.3.3.14-1 is resolved.

In RAI 2.3.3.14-2, dated March 9, 2012, the staff noted on license renewal boundary 

drawing LR-M-59, sheet 3, location H-6, a line not highlighted within the scope of license 

renewal. However, this line is connected to a continuation marker from drawing LR-M-42, 

sheet 3, location A-3, which depicts the continuation marker to be highlighted in green and 

in scope for 10 CFR 54.4(a)(1). The applicant was requested to clarify the scoping 

classification of this pipe line.

In its letter dated March 20, 2012, the applicant stated that the continuation line to 

PDS-059-206B on license renewal boundary drawing LR-M-59, sheet 3, from LR-M-42, sheet 3,

should have been shown as within the scope of license renewal for 10 CFR 54.4(a)(1). During 

the onsite IP 71002 inspection, the staff confirmed that the drawings were revised as described 

in response to RAI 2.3.3.14-2.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.14-2 acceptable 

because the applicant clarified the pipe section scoping classification and revised license 
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renewal boundary drawing LR-M-59, sheet 3. Therefore, the staff’s concern described in

RAI 2.3.3.14-2 is resolved.

2.3.3.14.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI responses, the staff concludes the 

applicant appropriately identified the primary containment instrument gas 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 stated in 10 CFR 54.21(a)(1).

2.3.3.15 Primary Containment Leak Testing System 

2.3.3.15.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.15 states that the primary containment leak testing system provides the 

ability to test the leakage of the primary containment structure, including containment 

penetrations, hatches, airlocks, and containment isolation valves to verify that the leakage is 

within specified limits as required by 10 CFR 50 Appendix J.

The intended functions of the primary containment leak testing system are to provide primary 

containment boundary and to resist nonsafety-related SSC failure that could prevent satisfactory 

accomplishment of a safety-related function.

LRA Table 2.3.3-15 identifies the primary containment leak testing system component types 

within the scope of license renewal and subject to an AMR.

2.3.3.15.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.25 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.3.15.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the primary containment leak testing system components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant 

has adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.3.16 Primary Containment Ventilation System 

2.3.3.16.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.16 states that the primary containment ventilation system removes heat from 

and maintains air circulation in the primary containment and provides cooling to other areas of 

the plant.
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The intended functions of the primary containment ventilation system is to provide primary 

containment boundary, control combustible gas mixtures in the primary containment 

atmosphere, and resist nonsafety-related SSC failure that could prevent satisfactory 

accomplishment of a safety-related function. The primary containment ventilation system is 

relied upon in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the NRC’s regulations for environmental qualification (10 CFR 50.49).

LRA Table 2.3.3-16 identifies the primary containment ventilation system component types that 

are within the scope of license renewal and subject to an AMR.

2.3.3.16.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.16 and UFSAR Sections 3.5.1.1.1, 6.2, 9.2.10, and 

9.4.5.2 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 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).

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. In a letter dated February 17, 2012, the 

staff issued RAI 2.3.3.16-1, noting that LRA Tables 2.3.3-16 and 3.3.2-16 do not contain all the 

component types for the primary containment ventilation system highlighted on the drawings. 

The tables do not list any specific components and their housing types associated with “ducting 

and components type” (e.g., fans and fan housing, dampers and damper housings, fire dampers 

and fire damper housings, filters and filter housings, heating and cooling coils), as applicable.

Therefore, the staff requested clarification on whether these component types and all other 

applicable component types of the system are within the scope of license renewal in 

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

10 CFR 54.21(a)(1).

In the letter dated March 5, 2012, the applicant stated that the LGS “Ducting and Components”

includes fan housings (damper housings, fire damper housings, and filter housings). This 

practice is consistent with the GALL Report Table IX.B definition of ducting and components, 

which states that ducting and components include “heating, ventilation, and air-conditioning 

(HVAC) components. Examples include ductwork . . . equipment frames and housing, housing 

supports, including housings for valves, dampers (including louvers, gravity, and fire dampers), 

and ventilation fans.” The “Ducting and Components” component type listed in LRA 

Table 3.3.2-7 includes ventilation and fire damper housings and fan housings. These 

components are subject to an AMR. Fans, dampers, and fire dampers are active components 

and not subject to an AMR. Cooling coils are included in the “Heat Exchanger Components”

component type. LRA Table 2.3.3-16 and Table 3.3.2-16 list the heat exchangers within the 

scope of license renewal and subject to an AMR. Fans and dampers are active components 

and are not subject to an AMR. There are no fire dampers, filters, or heaters in this system.
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Based on its review, the staff finds the applicant’s response to RAI 2.3.3.16-1 acceptable. The 

applicant clarified the discrepancy in the listing of the primary containment ventilation system 

components. No new systems or components were included in the scope of license renewal as 

a result of this RAI response. Therefore, the staff’s concern described in RAI 2.3.3.16-1 is 

resolved.

2.3.3.16.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the primary containment ventilation 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 stated in 10 CFR 54.21(a)(1).

2.3.3.17 Process Radiation Monitoring System 

2.3.3.17.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.17 states that the process radiation monitoring system monitors the level of

radioactivity of various process liquid and gas lines that can serve as discharge routes for

radioactive materials. For certain systems, the process radiation monitoring system supports 

the prevention of an uncontrolled release of radioactive liquids, gases, and particulates by 

providing isolation signals to the monitored systems.

The intended functions of the process radiation monitoring system is to sense process 

conditions and generate signals for reactor trip or ESF actuation, provide primary containment 

boundary, and resist nonsafety-related SSC failure that could prevent satisfactory 

accomplishment of a safety-related function. The process radiation monitoring system is relied 

upon in safety analyses or plant evaluations to perform a function that demonstrates compliance 

with the NRC’s regulations for EQ (10 CFR 50.49).

LRA Table 2.3.3-17 identifies the process radiation monitoring system component types that are 

within the scope of license renewal and subject to an AMR.

2.3.3.17.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.17, UFSAR Sections 7.6.1.1, 7.7.1.9, 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. The staff’s review identified areas in 

which additional information was necessary to complete the review of the applicant’s 

scoping and screening results. The applicant responded to the staff’s requests for 

additional information as discussed below.

In RAI 2.3.3.17-1, dated March 9, 2012, the staff noted on license renewal boundary 

drawings LR-M-26, sheets 1 and 7, location C-2, and LR-M-26, sheet 4, location B-7, 

sample chambers in Detail K that are within the scope of license renewal for 

10 CFR 54.4(a)(2), but are not listed in LRA Table 2.3.3-17 as a component type subject to 

an AMR. The applicant was requested to justify the exclusion of the sample chamber 

component type from LRA Table 2.3.3-17.
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In its letter dated March 20, 2012, the applicant stated that the sample chambers are included 

in LRA Table 2.3.3-17 as a component type of “Piping, piping components, and piping

elements.” Additionally, as part of its RAI response, the applicant made revisions to LRA 

Section 3.3.2.1.17, Table 3.3.2-17, Table 3.3.1, and Table 2.3.3-17 to include the correct 

environments for the nonsafety-related liquid process monitor components and remove 

component types not applicable for the process radiation monitoring system.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-1 acceptable 

because the applicant clarified that the sample chambers are included in LRA Table 2.3.3-17 

as a “Piping, piping components, and piping elements” component type. Therefore, the

staff’s concern described in RAI 2.3.3.17-1 is resolved.

In RAI 2.3.3.17-2, dated March 9, 2012, the staff noted on license renewal boundary 

drawing LR-M-26, sheet 5, location E-3, that the filter and detector housings in Detail G are 

within the scope of license renewal for 10 CFR 54.4(a)(1), but are not listed in 

Table 2.3.3-17 as a component type subject to an AMR. The applicant was requested to 

justify the exclusion of the filter and detector housing component types from LRA 

Table 2.3.3-17.

In its letter dated March 20, 2012, the applicant stated that the filters and detector housings 

are included in LRA Table 2.3.3-17 as a component type of “Piping, piping components, and 

piping elements.”

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-2 acceptable 

because the applicant clarified that the sample chambers are located in LRA Table 2.3.3-17 

as a “Piping, piping components, and piping elements” component type. Therefore, the

staff’s concern described in RAI 2.3.3.17-2 is resolved.

2.3.3.17.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI responses, the staff concludes the 

applicant appropriately identified the process radiation monitoring 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 stated in 

10 CFR 54.21(a)(1).

2.3.3.18 Process and Post-Accident Sampling System

2.3.3.18.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.3.18 states that the process and post-accident sampling systems consists of 

the plant process sampling system and plant post-accident sampling system. The process and 

post-accident sampling system is designed to obtain representative samples from process 

streams to minimize leakage, spillage, and potential radiation exposure to operational staff.

The intended functions of the process and post-accident sampling system is to provide primary 

resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function.
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LRA Table 2.3.3-18 identifies the process and post-accident sampling system component types 

within the scope of license renewal and subject to an AMR.

2.3.3.18.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.18, UFSAR Sections 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. The staff’s review identified an area 

in which additional information was necessary to complete the review of the applicant’s 

scoping and screening results. The applicant responded to the staff’s RAI as discussed 

below.

In RAI 2.3.3.18-1, dated March 9, 2012, the staff noted on license renewal boundary 

drawings LR-M-23, sheets 4 and 7, location H-4, a continuation line from the feedwater to 

reactor 10 CFR 54.4(a)(2) pipelines, respectively, to license renewal boundary drawings 

LR-M-06, sheets 3 and 6, location G-8, where the pipeline continuations are shown as not 

in scope of license renewal. The applicant was requested to clarify the scoping 

classification of these pipe lines.

In its letter dated March 20, 2012, the applicant stated that the feedwater sample lines shown 

on license renewal boundary drawing LR-M-06, sheets 3 and 6, are located within the turbine 

enclosure in an area where spatial interaction is not a concern and are correctly shown as 

excluded from the scope of license renewal. The sample line continuations shown on license 

renewal boundary drawings LR-M-23, sheets 4 and 7, terminate within the reactor enclosure in 

an area where spatial interaction is a concern and are correctly shown as within the scope of 

license renewal.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.18-1 acceptable 

because the applicant clarified the scoping classification of the above pipe lines.

Therefore, the staff’s concern described in RAI 2.3.3.18-1 is resolved.

2.3.3.18.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the process and post-accident sampling 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 stated in 10 CFR 54.21(a)(1).

2.3.3.19 Radwaste System 

2.3.3.19.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.19 states that the radwaste system is a liquid, solid, and gaseous radioactive

waste management system designed to process all of the radioactive, or potentially radioactive, 

liquid, solid, and gaseous waste generated in the operation of the plant.

The intended function of the radwaste system is to provide primary containment boundary, 

provide emergency heat removal from the primary containment, provide containment pressure 

control, and resist nonsafety-related SSC failure that could prevent satisfactory accomplishment 
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of a safety-related function. The radwaste system is relied upon in safety analyses or plant 

evaluations to perform a function that demonstrates compliance with the NRC’s regulations for 

EQ (10 CFR 40.49).

LRA Table 2.3.3-19 identifies the radwaste system component types within the scope of license 

renewal and subject to an AMR.

2.3.3.19.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.19 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.3.19.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the radwaste system components within the scope of license renewal, 

as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified 

the system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.20 Reactor Enclosure Ventilation System 

2.3.3.20.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.20 states that the reactor enclosure ventilation system provides ventilation 

and maintains environmental conditions to areas inside the reactor enclosure during normal 

plant operation. The system also maintains the reactor enclosure at a negative pressure to 

prevent exfiltration of potentially contaminated air, filters air exhausted from areas of potential 

contamination, and isolates supply and exhaust ducts of affected rooms following a high-energy 

line break.

The intended functions of the reactor enclosure ventilation system are to provide secondary 

containment boundary, maintain emergency temperature limits within areas containing 

safety-related components, and resist nonsafety-related SSC failure that could prevent 

satisfactory accomplishment of a safety-related function. The reactor enclosure ventilation 

system is relied upon in safety analyses or plant evaluations to perform a function that 

demonstrates compliance with the NRC’s regulations for fire protection (10 CFR 50.48), 

EQ (10 CFR 50.49), and SBO (10 CFR 50.63).

LRA Table 2.3.3-20 identifies the reactor enclosure ventilation system component types within 

the scope of license renewal and subject to an AMR.

2.3.3.20.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.20 and UFSAR Sections 3.5.1.1.1, 9.4.2, and 9A.2.5 

using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR 

Section 2.3.
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During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant included in the scope of license renewal all components with intended 

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the 

applicant has identified as within the scope of license renewal to verify that the applicant has 

included all passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. In a letter dated February 17, 2012, the 

staff issued RAI 2.3.3.20-1, noting that LRA Tables 2.3.3-20 and 3.3.2-20 do not contain all the 

component types for the reactor enclosure ventilation system highlighted on the drawings. The 

tables do not list any specific components and their housing types associated with “ducting and 

components type” (e.g., fans and fan housing, dampers and damper housings, fire dampers and 

fire damper housings, filters and filter housings, heating and cooling coils, as applicable).

Therefore, the staff requested clarification as to whether these component types and all other 

applicable component types of the system are within the scope of license renewal in 

accordance with 10 CFR 54.4(a) and subject to an AMR, in accordance with 

10 CFR 54.21(a)(1).

In its letter dated March 5, 2012, the applicant stated that the LGS “Ducting and Components”

includes fan housings (damper housings, fire damper housings, and filter housings). This 

practice is consistent with the GALL Report Table IX.B definition of ducting and components, 

which states that ducting and components include “heating, ventilation, and air-conditioning 

(HVAC) components. Examples include ductwork, equipment frames and housing, housing 

supports, including housings for valves, dampers (including louvers, gravity, and fire dampers), 

and ventilation fans.”

As described in LRA Sections 2.3.2.6 and 2.3.3.20, the SGTS recirculates air flow through the 

same path that the reactor enclosure ventilation system uses. For the purposes of license 

renewal evaluation, the shared ductwork and components are evaluated with SGTS.

The “Ducting and Components” listed in LRA Table 3.3.2-6 for SGTS include ventilation damper 

housings, fan housings, filter housings, and electric duct heater frames. The “Ducting and 

Components” listed in LRA Table 3.3.2-20 for the reactor enclosure ventilation system include 

ventilation and fire damper housings and unit cooler fan housings. These components are 

subject to an AMR. Cooling coils are included in LRA Table 3.3.2-20 in the “Heat Exchanger 

Components” component type. Fans, dampers, fire dampers, and electric duct heating coils are 

active components and are not subject to an AMR. Filter media are short-lived and are not 

subject to an AMR, as explained in the notes on drawing LR-M-76. As indicated on drawing 

LR-M-76 sheets 1, 2, 7, and 8, and LRA Tables 2.3.3-1 and 3.3.2-1, the steam supply to the unit 

heaters is evaluated with the auxiliary steam system.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.20-1 acceptable. The 

applicant clarified the discrepancy in the listing of the reactor enclosure ventilation system 

components. No new systems or components were included in the scope of license renewal as 

a result of this RAI response. Therefore, the staff’s concern described in RAI 2.3.3.20-1 is 

resolved.
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2.3.3.20.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the reactor enclosure ventilation 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 stated in 

10 CFR 54.21(a)(1).

2.3.3.21 Reactor Water Cleanup System 

2.3.3.21.1 Summary of Technical Information in the Application 

The reactor water cleanup system is a high-pressure filtration and demineralization system 

designed to maintain reactor coolant purity. The reactor water cleanup system removes solid 

and dissolved impurities from reactor coolant, blowdown excess reactor coolant during startup, 

shutdown, and hot standby conditions to the main condenser, CST, or equipment drain 

collection tank. The system minimizes temperature gradients in the main recirculation piping 

and RPV during periods when the main recirculation pumps are unavailable.

The intended functions of the reactor water cleanup system are to provide primary containment 

boundary, sense process conditions and generate signals for reactor trip or ESF actuation, and 

resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function. The reactor water cleanup system is also relied upon in safety analyses 

or plant evaluations to perform a function that demonstrates compliance with the NRC’s 

regulations for fire protection (10 CFR 50.48) and EQ (10 CFR 50.49).

LRA Table 2.3.3-21 identifies the reactor water cleanup system component types within the 

scope of license renewal and subject to an AMR.

2.3.3.21.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.21 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.3.21.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the reactor water cleanup system component types within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has 

adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.3.22 Safety-Related Service Water System 

2.3.3.22.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.22 states that the safety-related SW system is designed to remove heat from 

the primary containment, from areas containing ECCS equipment in the reactor enclosure, and 

from safety-related plant equipment. The safety-related SW system consists of the residual 
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heat removal service water (RHRSW) system, the emergency service water (ESW) system, and 

the RHR heat exchanger tube corrosion monitoring subsystem.

The intended functions of the safety-related SW system are to remove residual heat from the 

RCS, provide heat removal from safety-related heat exchangers, provide emergency heat 

removal from primary containment, provide containment pressure control, maintain emergency 

temperature limits within areas containing safety-related components, and resist 

nonsafety-related SSC failure that could prevent satisfactory accomplishment of a safety-related 

function. The safety-related SW system is also relied upon in safety analyses or plant 

evaluations to perform a function that demonstrates compliance with the NRC’s regulations for 

fire protection (10 CFR 50.48), EQ (10 CFR 50.49), and SBO (10 CFR 50.63).

LRA Table 2.3.3-22 identifies the safety-related SW system component types within the scope 

of license renewal and subject to an AMR.

2.3.3.22.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.22, UFSAR Sections 3.1, 3.2, 7.1.2, 7.3.1, 7.3.2, 7.4, 

7.6, 9.2.2, 9.2.3, 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. The 

staff’s review identified areas in which additional information was necessary to complete 

the review of the applicant’s scoping and screening results. The applicant responded to 

the staff’s RAIs as discussed below.

In RAI 2.3.3.22-1, dated March 9, 2012, the staff noted on license renewal boundary 

drawing LR-M-13, sheet 2, locations D-2 and E-7, 11⁄2-inch JBD-419 lines as within the 

scope of license renewal based on the criteria in 10 CFR 54.4(a)(2), with continuations to 

license renewal boundary drawing LR-M-23, sheet 7. However, the continuations of these 

lines on license renewal boundary drawing LR-M-23, sheet 7, are shown as not within the 

scope of license renewal. The applicant was requested to clarify the scoping classification 

of these pipe lines.

In its letter dated March 20, 2012, the applicant stated that the continuation of the 11⁄2-inch

JBD-419 lines to license renewal boundary drawing LR-M-23, sheet 7, should be within the 

scope of license renewal. During the onsite IP 71002 inspection, the staff confirmed that 

the drawings were revised as described in response to RAI 2.3.3.22-1.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.22-1 acceptable 

because the applicant clarified that the 11⁄2-inch JBD-419 continuation lines to license 

renewal boundary drawing LR-M-23, sheet 7, are within the scope of license renewal for 

10 CFR 54.4(a)(2) and revised the license renewal boundary drawing. Therefore, the

staff’s concern described in RAI 2.3.3.22-1 is resolved.

In RAI 2.3.3.22-2, dated March 9, 2012, the staff noted on license renewal boundary 

drawing LR-M-13, sheet 1, locations D-2 and D-4, that the 11⁄2-inch JBD-319 lines are

within the scope of license renewal for 10 CFR 54.4(a)(2), with continuations to and from 

license renewal boundary drawing LR-M-23, sheet 4. However, the continuations of these 

lines on drawing LR-M-23, sheet 4, are shown as not within the scope of license renewal. 

The applicant was requested to clarify the scoping classification of these pipe lines.
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In its letter dated March 20, 2012, the applicant stated that the continuation of 11⁄2-inch 

JBD-319 lines to and from the license renewal boundary drawing LR-M-23, sheet 4, should 

be within the scope of license renewal. During the onsite IP 71002 inspection, the staff 

confirmed that the drawings were revised as described in response to RAI 2.3.3.22-2.

Based on its review, the staff finds that the applicant’s response to RAI 2.3.3.22-2

acceptable because the applicant clarified that the 11⁄2-inch JBD-319 continuation lines to 

and from the license renewal boundary drawing LR-M-23, sheet 4, are within the scope of 

license renewal for 10 CFR 54.4(a)(2) and revised the license renewal boundary drawings. 

Therefore, the staff’s concern described in RAI 2.3.3.22-2 is resolved.

2.3.3.22.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the safety-related SW 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 stated in 

10 CFR 54.21(a)(1).

2.3.3.23 Spray Pond Pump House Ventilation System 

2.3.3.23.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.23 states that the spray pond pump house ventilation system provides 

ventilation, heating, cooling, and control of environmental conditions in the spray pond pump 

house. The spray pond pump house ventilation system provides ventilation and cooling in the 

spray pond pump house under normal plant operating conditions and following DBEs, provides 

heating under normal plant operating conditions, and provides suitable environmental conditions 

for the ESW and RHRSW pumps and their accessories.

The intended function of the spray pond pump house ventilation system is to maintain 

emergency temperature limits within areas containing safety-related components. The spray 

pond pump house ventilation system also is relied upon in safety analyses or plant evaluations 

to perform a function that demonstrates compliance with the NRC’s regulations for fire 

protection (10 CFR 50.48) and SBO (10 CFR 50.63).

LRA Table 2.3.3-23 identifies the spray pond pump house ventilation system component types 

that are within the scope of license renewal and subject to an AMR.

2.3.3.23.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.23 and UFSAR Sections 3.5.1.1.1 and 9.4.7 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 included in the scope of license renewal all 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 included all 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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The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. In a letter, dated February 17, 2012, 

the staff issued RAI 2.3.3.23-1, stating that LRA Tables 2.3.3-23 and 3.3.2-23 do not contain all 

the component types for the spray pond pump house ventilation system highlighted on the 

drawing. The tables do not list any specific components and their housing types associated with 

“ducting and components type” (e.g., fans and fan housing, dampers and damper housings, fire 

dampers and fire damper housings, filters and filter housings, heating and cooling coils, as 

applicable).

Therefore, the staff requested clarification on whether these component types and all other 

applicable component types of the system are within the scope of license renewal in 

accordance with 10 CFR 54.4(a) and are subject to an AMR in accordance with 

10 CFR 54.21(a)(1).

In the letter dated March 5, 2012, the applicant stated that the LGS “Ducting and Components”

includes fan housings (damper housings, fire damper housings, and filter housings). This 

practice is consistent with the GALL Report Table IX.B definition of ducting and components, 

which states that ducting and components includes “heating, ventilation, and air-conditioning 

(HVAC) components. Examples include ductwork . . . equipment frames and housing, housing 

supports, including housings for valves, dampers (including louvers, gravity, and fire dampers), 

and ventilation fans.”

The “Ducting and Components” listed in LRA Tables 2.3.3-23 and 3.3.2-23 include ventilation 

and fire damper housings and fan housings. These components are subject to an AMR. There 

are no filters or cooling coils in the spray pond pump house ventilation system. Fans, dampers, 

fire dampers, and electric duct heating coils are active components and are not subject to 

an AMR.

During evaluation of RAI 2.3.3.23-1, the applicant determined that electric duct heater housings 

and a portion of the fan housings are stainless-steel and aluminum, respectively, and not carbon 

steel as reflected in the LRA AMR table for the spray pond pump house ventilation system. As 

a result of this determination, the applicant revised LRA Section 3.3.2.1.23 and LRA 

Tables 3.3.1 and 3.3.2-23 to include these materials. An extent of condition review of these 

components in the other ventilation systems confirmed that no additional changes are required 

to the LRA.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.23-1 acceptable. The 

applicant clarified the discrepancy in the listing of the spray pond pump house ventilation 

system components. No new systems or components were included in the scope of license 

renewal as a result of this RAI response. Therefore, the staff’s concern described in 

RAI 2.3.3.23-1 is resolved.

2.3.3.23.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the spray pond pump house ventilation 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 stated in 10 CFR 54.21(a)(1).
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2.3.3.24 Standby Liquid Control System 

2.3.3.24.1 Summary of Technical Information in the Application 

The SLC system consists of a boron solution tank, a test water tank, three 

positive-displacement pumps, three explosive valves, three pump discharge relief valves, three 

pulsation dampeners/accumulators, a motor operated stop-check shutoff valve, and associated 

valves, piping, and controls. The SLC system is automatically initiated by signals from the 

redundant reactivity control system or manually initiated from the control room to pump a boron 

neutron absorber solution into the reactor if the reactor cannot be shut down with the control 

rods, or if suppression pool potential of hydrogen (pH) control is required to mitigate the dose 

consequences of a LOCA. The liquid is piped into the reactor vessel and discharged into the 

core by the CS line and sparger used by the HPCI system so that it mixes with the cooling water 

rising through the core. 

The intended functions of the SLC system within the scope of license renewal include the 

following:

 • provides emergency negative reactivity to the RCS to bring the reactor to a shutdown 

condition at any time in the reactor core life

 • provides primary containment isolation and integrity

 • maintains RCPB integrity

 • provides post-LOCA pH control in the suppression pool that will minimize the potential for 

re-evolution of elemental iodine dissolved in the suppression pool

LRA Table 2.3.3-24 identifies the SLC system component types within the scope of license 

renewal and subject to an AMR.

2.3.3.24.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.24 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.3.24.2 Conclusion

On the basis of its review of the LRA and UFSAR the staff concludes that the applicant has 

appropriately identified the SLC system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).
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2.3.3.25 Traversing In-core Probe System 

2.3.3.25.1 Summary of Technical Information in the Application 

The traversing in-core probe (TIP) machines are comprised of a TIP detector, a drive 

mechanism, an indexing mechanism, and guide tubes. There are five TIP machines, each with 

its own group of guide tubes that correspond to a low-power range monitor (LPRM) group.

A valve system is provided with a valve on each guide tube entering the drywell. A ball valve 

and a cable shearing valve are mounted in the guide tubing just outside the drywell. The shear 

valves are actuated by explosive squibs and can cut the cable and close off the guide tube.

The intended functions of the TIP system within the scope of license renewal are to provide 

primary containment isolation and integrity

LRA Table 2.3.3-25 identifies the traversing in-core probe system component types within the 

scope of license renewal and subject to an AMR.

2.3.3.25.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.25 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.3.25.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the TIP system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.26 Water Treatment and Distribution System 

2.3.3.26.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.26 states that the water treatment and distribution (WTD) system consists of 

the clarified water subsystem and the demineralized water makeup subsystem. The system is 

designed to provide treated makeup water to support normal plant operation. The WTD also 

includes the domestic water subsystem.

The intended function of the WTD system is to resist nonsafety-related SSC failure that could 

prevent satisfactory accomplishment of a safety-related function.

LRA Table 2.3.3-26 identifies the water treatment and distribution system component types 

within the scope of license renewal and subject to an AMR.
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2.3.3.25.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.26 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.3.26.2 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the WTD system component types within the scope of license renewal, 

as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified 

the system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.4 Steam and Power Conversion Systems

LRA Section 2.3.4 identifies the steam and power conversion systems SCs subject to an AMR 

for license renewal. The applicant described the supporting SCs of the steam and power 

conversion systems in the following LRA sections:

 • 2.3.4.1, “Circulating Water System”

 • 2.3.4.2, “Condensate System”

 • 2.3.4.3, “Condenser and Air Removal System”

 • 2.3.4.4, “Extraction Steam System”

 • 2.3.4.5, “Feedwater System”

 • 2.3.4.6, “Main Steam System”

 • 2.4.3.7, “Main Turbine System”

The staff’s findings on review of LRA Sections 2.3.4.1 – 2.3.4.7 are in SER 

Sections 2.3.4.1–2.3.4.7.

Steam and Power Conversion Generic Request for Additional Information

In RAI 2.3.4-1, dated March 9, 2012, the staff noted 15 instances on drawings in which the 

staff could not determine the basis for the change in scoping criteria from 

10 CFR 54.4(a)(1) to 10 CFR 54.4(a)(2). The applicant was requested to clarify the 

scoping classification of the 15 10 CFR 54.4(a)(2) pipe lines.

In its response, by letter dated March 20, 2012, the applicant provided information to clarify the 

basis for the change in scoping criteria from 10 CFR 54.4(a)(1) to 10 CFR 54.4(a)(2) for all 

15 locations. The applicant stated that piping and components that perform or support a 

safety-related function are within the scope of license renewal based on the criteria in 

10 CFR 54.4(a)(1) and that nonsafety-related piping components within the reactor enclosure 

and primary containment that contain fluid are included within the scope of license renewal 

based on the criteria in 10 CFR 54.4(a)(2) caused by potential spacial interaction with 

safety-related components. The applicant stated that in five instances it determined there 

should not have been a transition from safety-related to nonsafety-related depicted on the scoping 
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boundary drawings for the systems referenced in the staff’s RAI. Therefore, the applicant stated 

that in these five instances the scoping boundary drawings would be revised to show the 

components referenced in the RAI as within the scope of license renewal in accordance with 

10 CFR 54.4(a)(1). For the remaining 10 locations, the applicant confirmed that the scoping 

change depicted in the boundary drawing was correct and the components were correctly 

shown on the scoping drawings as within the scope license renewal in accordance with 

10 CFR 54.4(a)(2). 

The staff reviewed the applicant’s response and found it acceptable because the applicant 

revised five locations on the scoping boundary drawings to properly identify safety-related 

components, and because the applicant confirmed that the remaining 10 locations were for 

nonsafety-related components and, therefore, were properly depicted as within the scope of 

license renewal based on the criteria in 10 CFR 54.4(a)(2). Also, during the onsite IP 71002 

inspection, the staff confirmed that the drawings were revised as described in response to 

RAI 2.3.4-1.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4-1 acceptable because

the applicant clarified the 15 scoping classification changes, which included five items that were 

revised and corrected on their respective license renewal boundary drawings. No new 

component types were identified as a result of the applicant’s response to the RAI. Therefore, 

the staff’s concern described in RAI 2.3.4-1 is resolved.

2.3.4.1 Circulating Water System 

2.3.4.1.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.1 states that the circulating water system is a closed-loop system consisting 

of hyperbolic natural draft cooling towers, four 25 percent capacity circulating water pumps per 

unit, and associated piping, valves, controls, and instrumentation designed to remove the 

design plant heat loads. The license renewal circulating water system includes the plant 

chlorination system and the Schuylkill River and Perkiomen Creek makeup systems.

The intended function of the circulating water system is to resist nonsafety-related SSC failure 

that could prevent satisfactory accomplishment of a safety-related function. Also, the circulating 

water system is relied upon in safety analyses or plant evaluations to perform a function that 

demonstrates compliance with the NRC’s regulations for fire protection (10 CFR 50.48).

LRA Table 2.3.4-1 identifies the circulating water system component types within the scope of 

license renewal and subject to an AMR.

2.3.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.1 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.4.1.3 Conclusion 

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the circulating water system components within the scope of license 
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renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately 

identified the system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).

2.3.4.2 Condensate System 

2.3.4.2.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.2 states that the condensate system is designed to provide filtered and 

demineralized condensate from the condenser hotwell to the feedwater system. The 

condensate system also provides for the storage of condensate water for use in normal plant 

operations and refueling operations. The condensate system consists of the condensate (up to 

the filter demineralizers), condensate filter demineralizers, and condensate and refueling water 

storage and transfer systems.

The intended function of the condensate system is to sense process conditions and generate 

signals for reactor trip or engineered safety features actuation and to resist nonsafety-related 

SSC failure that could prevent satisfactory accomplishment of a safety-related function. The 

condensate system also is relied upon in safety analyses or plant evaluations to perform a 

function that demonstrates compliance with the NRC’s regulations for fire protection 

(10 CFR 50.48).

LRA Table 2.3.4-2 identifies the condensate system component types within the scope of 

license renewal and subject to an AMR.

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.2 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.4.2.3 Conclusion 

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the condensate system components within the scope of license renewal, 

as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified 

the system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.4.3 Condenser and Air Removal System 

2.3.4.3.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.3 states that the condenser and air removal system is designed to condense 

and deaerate the exhaust steam from the main turbine during normal operation. The system 

has a function to provide passive holdup for leakage from the MSIVs following an accident and 

to isolate mechanical vacuum pump discharge upon detection of high radiation in the main 

steam lines.
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The intended function of the condenser and air removal system is to resist nonsafety-related 

SSC failure that could prevent satisfactory accomplishment of a safety-related function and for 

post-accident containment holdup and plateout of MSIV bypass leakage.

LRA Table 2.3.4-3 identifies the condenser and air removal system component types within the 

scope of license renewal and subject to an AMR.

2.3.4.3.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.4.3, UFSAR Sections 6.7, 10.4, 7.6, 15.4, 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. The staff’s review identified an 

area in which additional information was necessary to complete the review of the 

applicant’s scoping and screening results. The applicant responded to the staff’s RAI as 

discussed below.

In RAI 2.3.4.3-1, dated March 9, 2012, the staff noted on license renewal boundary 

drawings LR-M-07, sheets 1 and 3, location H-2, air inlets with screens that are within the 

scope of license renewal for 10 CFR 54.4(a)(2), but that are not listed in LRA Table 2.3.4-3 

as a component type subject to an AMR. The applicant was requested to justify the 

exclusion of the air inlet with screen component type from LRA Table 2.3.4-3.

In its response, dated March 20, 2012, the applicant stated that the screens prevent 

foreign material from entering open pipelines and do not perform a license renewal 

function. The applicant stated that it will revise license renewal boundary drawings 

LR-M-07, sheets 1 and 3, to include a note clarifying that the screens are not within the 

scope of license renewal. During onsite IP 71002 inspection the staff confirmed that the 

drawings were revised as described in response to RAI 2.3.4.3-1.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.3-1 acceptable 

because the applicant clarified the purpose of the screens and revised license renewal 

boundary drawings LR-M-07, sheets 1 and 3, to indicate that the screens are excluded 

from scope of license renewal. Therefore, the staff’s concern described in RAI 2.3.4.3-1 is

resolved.

2.3.4.3.3 Conclusion 

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes 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), and that the applicant has adequately 

identified all the components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.4.4 Extraction Steam System 

2.3.4.4.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.4 states that the extraction steam system supplies steam from the 

high-pressure turbine, cross-around piping, moisture separator drains, and low-pressure turbine 

stages to the six stages of feedwater heaters.
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The intended function of the extraction steam system is to resist nonsafety-related SSC failure 

that could prevent satisfactory accomplishment of a safety-related function.

LRA Table 2.3.4-4 identifies the extraction steam system component types within the scope of 

license renewal and subject to an AMR.

2.3.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.4 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.4.4.3 Conclusion 

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the extraction steam system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately 

identified the system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).

2.3.4.5 Feedwater System 

2.3.4.5.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.5 states that the feedwater system is designed to provide preheated 

feedwater to the RPV. The feedwater system consists of the following plant systems: heater 

vents and drains, feedwater, and hydrogen water chemistry.

The intended functions of the feedwater system are to provide primary containment boundary, 

to remove residual heat from the RCS and to resist nonsafety-related SSC failure that could 

prevent satisfactory accomplishment of a safety-related function. The feedwater system is 

relied upon in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with the NRC’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).

LRA Table 2.3.4-5 identifies the feedwater system component types within the scope of license 

renewal and subject to an AMR.

2.3.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.5 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review did not identify the 

need for any additional information.

2.3.4.5.3 Conclusion 

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the feedwater system components within the scope of license renewal, 

as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified 
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the system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.4.6 Main Steam System 

2.3.4.6.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.6 states that the main steam system is designed to convey steam produced 

in the reactor to the main turbine and direct steam from the main steam relief valve (MSRV) 

discharge to the suppression pool. The main steam system includes the MSIV alternate drain 

pathway and the MSIV leakage control system.

The intended functions of the main steam system are to provide emergency heat removal from 

primary containment, provide containment pressure control for post-accident containment 

holdup and plateout of MSIV bypass leakage, and to resist nonsafety-related SSC failure that 

could prevent satisfactory accomplishment of a safety-related function. The main steam system 

is also relied upon in safety analyses or plant evaluations to perform a function that 

demonstrates compliance with the NRC’s regulations for fire protection (10 CFR 50.48), EQ 

(10 CFR 50.49), and SBO (10 CFR 50.63).

LRA Table 2.3.4-6 identifies the main steam system component types within the scope of 

license renewal and subject to an AMR.

2.3.4.6.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.4.6, UFSAR Sections 3.2, 3.6, 5.2, 6.7, 10.1, 10.2, 

10.4, 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. The staff’s review 

identified an area in which additional information was necessary to complete the review of 

the applicant’s scoping and screening results. The applicant responded to the staff’s RAI

as discussed below.

In RAI 2.3.4.6-1, dated March 9, 2012, the staff noted on license renewal boundary 

drawing, LR-M-05, sheet 1, locations G-3, G-4, and G-6, that the continuation of the 

11⁄2-inch “Bearing Drain to Oily Waste” pipe from the condenser could not be found on the 

license renewal boundary drawings. The applicant was requested to provide the license 

renewal boundary for the 11⁄2-inch “Bearing Drain to Oily Waste” pipe, and if the 

continuation line cannot be shown on these license renewal boundary drawings, to provide 

additional information describing the extent of the scoping boundary and to verify if there 

are additional AMR component types between the continuation and the termination of the 

scoping boundary. The applicant also was requested to provide additional information to 

clarify the change in the scoping classification, if a section of the piping changes scoping 

classification over the continuation.

In its letter dated March 20, 2012, the applicant described the correct license renewal 

scoping boundaries for the 11⁄2-inch “Bearing Drain to Oily Waste” piping and stated that it 

will revise license renewal boundary drawings LR-M-05, sheets 3 and 6, and add a 

note describing the basis for the change. During the onsite IP 71002 inspection, the staff 

confirmed that the drawings were revised as described in response to RAI 2.3.4.6-1.
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Based on its review the staff finds the applicant’s response to RAI 2.3.4.6-1 acceptable 

because the applicant clarified the license renewal scoping boundary for the 11⁄2-inch

“Bearing Drain to Oily Waste” piping and provided the revised license renewal boundary 

drawings. Therefore, the staff’s concern described in RAI 2.3.4.6-1 is resolved.

2.3.4.6.3 Conclusion 

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the main steam 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 stated in 

10 CFR 54.21(a)(1).

2.3.4.7 Main Turbine 

2.3.4.7.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.7 states main turbine is designed to convert the thermal energy in the steam 

supplied from the reactor into rotational mechanical energy. The main turbine consists of the 

following subsystems: main turbine, seal steam system, turbine lube oil system, 

electrohydraulic control system, and turbine supervisory instrumentation system.

The intended function of the main turbine is to resist nonsafety-related SSC failure that could 

prevent satisfactory accomplishment of a safety-related function and for post-accident 

containment holdup and plateout of MSIV bypass leakage.

LRA Table 2.3.4-7 identifies the main turbine component types within the scope of license 

renewal and subject to an AMR.

2.3.4.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.7, UFSAR Sections 3.2, 6.7, 10.1, 10.2, 10.3, 

10.4, 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. The staff’s review 

identified areas in which additional information was necessary to complete the review of 

the applicant’s scoping and screening results. The applicant responded to the staff’s RAIs 

as discussed below.

In RAI 2.3.4.7-1, dated March 9, 2012, the staff noted on license renewal boundary 

drawing LR-M-07, sheet 2, location F-6, 1-inch HBD-359 piping within the scope of license 

renewal; however, the continuation on this same drawing at location B-4 shows this piping 

as not within the scope of license renewal. The applicant was requested to clarify the 

scoping classification for this pipe section.

In its letter dated March 20, 2012, the applicant clarified that the 1-inch HBD-359 piping and 

valve on the continuation should be within the scope of license renewal. During the onsite 

IP 71002 inspection, the staff confirmed that the drawings were revised as described in 

response to RAI 2.3.4.7-1.
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Based on its review, the staff finds the applicant’s response to RAI 2.3.4.7-1 acceptable 

because the applicant clarified the license renewal scoping boundaries of the 1-inch

HBD-359 piping and revised the license renewal boundary drawings. Therefore, the staff’s

concern described in RAI 2.3.4.7-1 is resolved.

In RAI 2.3.4.7-2, dated March 9, 2012, the staff noted on license renewal boundary 

drawings LR-M-07, sheets 2 and 4, location E-7, that drain piping 1-inch HBD-359, and 

1-inch HBD-459 are depicted as within the scope of license renewal for 10 CFR 54.4(a)(2). 

However, license renewal boundary drawings LR-M-06, sheets 2 and 5, location D-8, 

depict the continuation piping as not being within the scope of license renewal. The 

applicant was requested to clarify the scoping boundaries for the continuation piping.

In its letter dated March 20, 2012, the applicant clarified that the continuation piping and duct 

are within the scope of license renewal. During the onsite IP 71002 inspection, the staff 

confirmed that the drawings were revised as described in response to RAI 2.3.4.7-2.

Based on its review the staff finds the applicant’s response to RAI 2.3.4.7-2 acceptable 

because the applicant clarified the license renewal boundaries of the 1-inch HBD-359 and 

1-inch HBD-459 continuation piping and revised the license renewal boundary drawings.

Therefore, the staff’s concern described in RAI 2.3.4.7-2 is resolved.

2.3.4.7.3 Conclusion 

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the main turbine 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 stated in 

10 CFR 54.21(a)(1).

2.4 Scoping and Screening Results: Structures

This section documents the staff’s review of the applicant’s scoping and screening results for 

structures. Specifically, this section discusses:

 • 220 and 500 kV substations

 • admin building shop and warehouse

 • auxiliary boiler and lube oil storage enclosure

 • circulating water pump house

 • component supports commodities group

 • control enclosure

 • cooling towers

 • diesel oil storage tank structures

 • emergency diesel generator enclosure

 • piping and component insulation commodity group

 • primary containment
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 • radwaste enclosure

 • reactor enclosure

 • service water pipe tunnel

 • spray pond and pump house

 • turbine enclosure

 • yard facilities

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 all structures and 

components meeting the scoping criteria and subject to an AMR are included.

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, 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 in 

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 the functions are 

performed with moving parts or a change in configuration or properties or 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.

2.4.1 220 and 500 kV Substations

2.4.1.1 Summary of Technical Information in the Application 

In LRA Section 2.4.1, the applicant described the 220 kV and 500 kV substations as being 

composed of two separate substations physically located northwest and southeast of the power 

block, respectively. The purpose of the 220 kV and 500 kV substations is to provide offsite 

power for both LGS Units 1 and 2. 
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The 220 kV substation foundations consist of reinforced concrete slabs, footings, and 

equipment foundations on soil. The purpose of the 220 kV substation is to provide physical 

support, shelter, and protection to the substation equipment and the13 kV system and provide a 

tie-in point for the two offsite transmission lines. The offsite 220 kV system consists of two 

220 kV transmission lines connected to a breaker-and-a-half design with one 220 kV-13 kV 

transformer. The 220 kV substation is a nonsafety-related, nonseismic structure.

The 500 kV substation foundations consist of reinforced concrete slabs, beams, grade beams, 

walls, piers, and footings founded on soil. The purpose of the 500 kV substation is to provide 

physical support, shelter, and protection to the substation equipment and 13 kV system. In 

addition, the 500 kV also provides a tie-in point for the three transmission lines. The offsite 

500 kV system consists of three 500 kV transmission lines connected to a breaker-and-a-half 

design with one 500 kV-13 kV transformer. The 500 kV substation also contains the No. 4 bus 

tie auto transformer, which links the 220 kV substation to the 500 kV substation.

The 500 kV substation is a nonseismic structure; however, it is relied upon to provide offsite 

power during SBO and safe shutdown during a fire. 

LRA Table 2.4-1 identifies the 220 kV and 500 kV substations component types within the 

scope of license renewal and subject to an AMR.

2.4.1.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.1 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff’s review did not identify the 

need for any additional information.

2.4.1.3 Conclusion 

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the 220 kV and 500 kV substations components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has 

adequately identified the system components subject to an AMR, in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.4.2 Admin Building Shop and Warehouse 

2.4.2.1 Summary of Technical Information in the Application 

In LRA Section 2.4.2, the applicant described the admin building shop and warehouse as an 

irregularly shaped multistory enclosure approximately 284 ft by 270 ft in plan area and

comprised of reinforced concrete, structural steel frame and floor beams, precast concrete 

panels, masonry walls, commercial grade finished office interior elements, including drywall, 

glass, and a built up roof on metal decking. It is physically located east of and immediately 

adjacent to the LGS Unit 2 reactor enclosure and the LGS Unit 2 turbine enclosure. 

The purpose of the admin building shop and warehouse is to provide support, shelter, and 

protection for site personnel and their office space, shop area, and storage in support of LGS 

Units 1 and 2. In addition, the structure is classified as a nonsafety-related seismic Category II

structure.
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LRA Table 2.4-2 identifies the admin building shop and warehouse component types within the 

scope of license renewal and subject to an AMR.

2.4.2.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.4 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff’s review did not identify the 

need for any additional information.

2.4.2.3 Conclusion 

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the admin building shop and warehouse components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has 

adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.4.3 Auxiliary Boiler and Lube Oil Storage Enclosure 

2.4.3.1 Summary of Technical Information in the Application 

In LRA Section 2.4.3, the applicant described the auxiliary boiler and lube oil storage enclosure 

as comprised of the fuel oil pump house enclosure and the auxiliary boiler pipe tunnel (also 

known as the machine shop pipe tunnel).

The auxiliary boiler enclosure is described as a multistory structure composed of structural 

steel, concrete block, and precast concrete panel. The structure is approximately 21 ft by 72 ft 

in plan area and is classified as a nonsafety-related seismic Category II structure. 

The purpose of the auxiliary boiler enclosure is to provide physical support, shelter, and 

protection for the nonsafety-related auxiliary steam system components and its supporting 

systems.

The auxiliary boiler pipe tunnel is described as a reinforced concrete rectangular box enclosure

approximately 174 inches in length and 21 feet in width and between 8 feet and 12 feet high. It 

is physically adjacent to the LGS Unit 2 reactor enclosure. The purpose of the auxiliary boiler 

pipe tunnel is to provide structural support for LGS Units 1 and 2 piping and the structures 

founded on the tunnel. In addition, the pipe tunnel houses safety-related and nonsafety-related 

piping into the power block.

The lube oil storage enclosure is described as a precast concrete panel enclosure and the 

exterior walls are comprised of precast concrete panels secured to a steel frame. In addition, 

the structure uses the southern side of the auxiliary boiler enclosure exterior masonry block wall 

as part of the enclosure. The single story structure is approximately 21 feet by 32 feet in plan 

area. The structure is classified as a nonsafety-related structure designed to commercial grade 

standards. The purpose of the lube oil storage enclosure is to provide physical support, shelter, 

and protection for the nonsafety-related equipment located inside the enclosure.
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The fuel oil pump house enclosure is described as a single story, structural steel and concrete 

structure with precast concrete exterior panels. It is classified as a seismic Category II structure 

and is physically located south of the power block. The enclosure is approximately 25 feet by 

40 feet in plan area. The purpose of the fuel oil pump house enclosure is to provide physical 

support, shelter, and protection for the nonsafety-related fuel oil transfer and fuel oil supply 

pumps that provide fuel to the fuel oil storage tank and feed oil to the nonsafety-related auxiliary 

boilers and supporting equipment.

LRA Table 2.4-3 identifies the auxiliary boiler and lube oil storage enclosure component types 

within the scope of license renewal and subject to an AMR.

2.4.3.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.3 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff’s review did not identify the 

need for any additional information.

2.4.3.3 Conclusion 

On the basis of it review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the auxiliary boiler and lube oil storage enclosure component types

within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also finds that the 

applicant has adequately identified the system components subject to an AMR in accordance 

with the requirements stated in 10 CFR 54.21(a)(1).

2.4.4 Circulating Water Pump House

2.4.4.1 Summary of Technical Information in the Application 

In LRA Section 2.4.4, the applicant described the circulating water (CW) pump house as a

reinforced concrete structure comprised of concrete and steel grating floors, steel roof beams, 

and miscellaneous steel. The CW pump house is supported by concrete fill placed on rock. 

The structure is approximately 42 feet by 274 feet in plan and is classified as a seismic 

Category II structure. The CW pump house is physically located north of the power block and 

south of the cooling towers.

The purpose of the CW pump house is to provide structural support; shelter and protection; 

access to the fire protection system fire pumps and associated piping, valves, and related 

equipment; and access to the circulating water system and nonsafety-related SW system 

pumps, piping, valves and associated equipment.

LRA Table 2.4-4 identifies the CW pump house component types within the scope of license 

renewal and subject to an AMR.

2.4.4.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.4 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff’s review did not identify the 

need for any additional information.
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2.4.4.3 Conclusion 

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the CW pump house components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.4.5 Component Supports Commodities Group

2.4.5.1 Summary of Technical Information in the Application 

In LRA Section 2.4.5, the applicant described the component supports commodities group as 

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. 

The commodity group is comprised of the following supports:

 • supports for ASME Class 1, 2, and 3, piping and component supports, reactor vessel skirt 

support anchorage, CRD support and restraints, pump supports, and the reactor vessel 

support ring girder and anchorage

 • supports for cable trays, conduit, HVAC ducts, tube track, instrument tubing and 

non-ASME piping and components

 • supports for HVAC system components and other miscellaneous mechanical equipment

 • supports for platforms, jet impingement shields, and other miscellaneous structures

 • supports for racks, panels, cabinets and enclosures for electrical equipment and 

instrumentation

The purpose of a support is to transfer gravity, thermal, seismic, and other lateral loads imposed 

on, or by the system, structure, or component to the supporting building structural element or 

foundation. Specialty supports such as snubbers only resist seismic forces. Vibration isolators 

are installed in some vibrating equipment to minimize the impact of vibration. Other support 

types such as guides and position stops allow displacement in a specified direction or preclude 

unacceptable movements and interactions.

LRA Table 2.4-5 identifies the component supports commodities group component types within 

the scope of license renewal and subject to an AMR.

2.4.5.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.5 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff’s review did not identify the 

need for any additional information.

2.4.5.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the component supports commodities group components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant 
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has adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.4.6 Control Enclosure

2.4.6.1 Summary of Technical Information in the Application 

In LRA Section 2.4.6, the applicant described the control enclosure as comprised of reinforced 

concrete bearing walls, slabs, foundation mat, roof, masonry walls, and structural steel. The 

reinforced concrete foundation is supported on bedrock. In addition, the floors and roof are 

constructed of reinforced concrete supported by steel beams. The roof is covered by an 

elastomer roofing membrane. The structure is approximately 132 feet by 62 feet in plan area 

and is physically located north of the seismic Class I safety-related reactor enclosures and 

south of the seismic Class II nonsafety-related turbine enclosure. The control enclosure is 

classified as a seismic Category I safety-related structure.

The purpose of the control enclosure is to provide structural support, shelter and protection to 

SSCs and personnel housed within the building during normal plant operations, and during and 

following postulated DBAs and extreme environmental conditions. In addition, the building 

contains the control room that provides a centralized area for control and monitoring of 

safety-related and nonsafety-related equipment throughout the station. The control enclosure 

also supports and protects both safety and nonsafety-related equipment.

LRA Table 2.4-6 identifies the control enclosure component types within the scope of license 

renewal and subject to an AMR. 

2.4.6.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.6 and the UFSAR using the evaluation methodology 

described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. During its review, the 

staff evaluated the structural 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 included as within the scope of license renewal to verify that the applicant 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).

During its review of LRA Section 2.6, the staff noted areas in which additional information was 

necessary to complete its review of the applicant’s scoping and screening results. By letter 

dated February 16, 2012, the staff issued RAI 2.4.6-1, requesting the applicant to confirm the 

inclusion of the “rubberized flat dumbbell-type waterstops” located at all construction joints 

below the maximum expected groundwater level for all safety-related enclosures, as stated in 

UFSAR Section 3.4.1.2 in the scope of license renewal, as applicable, and subject to an AMR 

per 10 CFR 54.21(a)(1)(i). In addition, in the event that the waterstops were omitted, the staff 

asked the applicant to justify the exclusion from the scope of license renewal.
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By letter dated March 5, 2012, the applicant responded to RAI 2.4.6-1 and stated, in part, the 

following:

The waterstops are included and addressed as part of the component, “Concrete:

Below-Grade Exterior (Inaccessible)” that is subject to the Structures Monitoring 

(B.2.1.35) program or the RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants (B.2.1.36) program.

In reviewing its response to RAI 2.4.6-1, the staff found that the applicant confirmed the 

inclusion of the waterstops within the scope of license renewal. In addition, the response also 

clarified the location within the LRA where the components were covered. Based on its review, 

the staff finds the applicant’s response to RAI 2.4.6-1 acceptable because the waterstops at 

LGS have been included in the scope of license renewal and included in the scope of an aging 

management program (AMP). The staff’s concern described in RAI 2.4.6-1 is resolved.

2.4.6.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the control enclosure 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 stated in 

10 CFR 54.21(a)(1).

2.4.7 Cooling Towers

2.4.7.1 Summary of Technical Information in the Application 

In LRA Section 2.4.7, the applicant described the cooling towers as reinforced concrete 

hyperbolic natural draft cooling towers that are founded on a reinforced concrete foundation 

supported on rock. In addition, the reinforced concrete cooling tower basin is supported on soil 

fill. The cooling towers are physically located north of the reactor enclosures and are classified 

as seismic Category II structures. The cooling tower structures are nonsafety-related and 

separated from safety-related SSCs such that their failure would not affect a safety-related 

function.

The purpose of the reinforced concrete cooling tower basins is to provide a source of cooling 

water for the CWS, the nonsafety-related SW system, and the fire protection system.

LRA Table 2.4-7 identifies the cooling towers component types within the scope of license 

renewal and subject to an AMR. 

2.4.7.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.7 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff’s review did not identify the 

need for any additional information.
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2.4.7.3 Conclusion 

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the cooling towers components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.4.8 Diesel Oil Storage Tank Structures

2.4.8.1 Summary of Technical Information in the Application 

In LRA Section 2.4.8, the applicant described the diesel oil storage tank structures as 

below- grade structures comprised of a below-grade base slab, below-grade excavated slope, 

structural backfill around the fuel oil tanks, and a valve pit or manhole allowing access to each 

tank. In addition, the tank enclosures also contain the oil unloading area concrete slab and the 

metal enclosure located over the valve pits. The tank enclosure is classified as a seismic 

Category I structure and is physically located south of the LGS Unit 1 reactor enclosure and 

approximately 150 feet from the emergency diesel generators. Each tank is located 

approximately 9 feet below grade.

The purpose of the diesel oil storage tank structures is to provide access, support, shelter, and

protection to the below-grade EDG system fuel oil tanks to ensure that they remain operable 

during and after the design basis wind, tornadoes, floods, earthquake, and missiles.

LRA Table 2.4-8 identifies the diesel oil storage tank enclosures component types within the 

scope of license renewal and subject to an AMR. 

2.4.8.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.8 and the UFSAR using the evaluation methodology 

described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural 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 included as within the scope of license renewal to verify that the applicant 

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).

During its review of LRA Section 2.8, the staff noted areas in which additional information was 

necessary to complete its review of the applicant’s scoping and screening results. By letter 

dated February 16, 2012, the staff issued RAI 2.4.8-1, requesting the applicant to provide 

additional details about the metal enclosure (butler building) located over the diesel oil storage 

tank structures. Specifically, the information requested should justify the exclusion of the metal 

enclosure from the scope of license renewal and provide a detailed description on how its failure 

would not prevent satisfactory accomplishment of a safety-related function. 
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By letter dated March 5, 2012, the applicant responded to RAI 2.4.8-1 and stated, in part, the 

following:

The loading on the manholes caused by a complete collapse of the metal 

enclosure was evaluated and determined to be bounded by the tornado missile 

design of the tank manholes and buried diesel oil fuel tanks. In addition, the 

common metal enclosure is located above the eight access manholes, with the 

sides and ends supported by the reinforced concrete Seismic Category I

manhole walls and not by the concrete top slabs.

Finally, the evaluation also considered the impact of a complete collapse on the 

fill lines and vent paths located above the Diesel Oil Storage Tank Structures and 

concluded that there would be no loss of any safety-related function.

In reviewing its response to RAI 2.4.8-1, the staff found that the applicant demonstrated and 

confirmed the adequate exclusion of the metal enclosure (butler building) from the scope of 

license renewal. In addition, the response also clarified that failure of this structure would not 

prevent satisfactory accomplishment of any safety-related function. Based on its review, the 

staff finds the applicant’s response to RAI 2.4.8-1 acceptable because the metal enclosure 

(butler building) located at the diesel oil storage tank enclosures has been adequately excluded 

from the scope of LR and subsequent AMP. The staff’s concern described in RAI 2.4.8-1 is 

resolved.

2.4.8.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the diesel oil storage tank structures 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 stated in 

10 CFR 54.21(a)(1).

2.4.9 Emergency Diesel Generator Enclosure

2.4.9.1 Summary of Technical Information in the Application 

In LRA Section 2.4.9, the applicant described the EDG enclosure as a single story multilevel 

structure divided into four compartments or bays, in which each bay houses an emergency 

diesel generator unit. Units 1 and 2, have separate EDG enclosures. Each diesel compartment 

or bay consists of an upper mezzanine level that contains support equipment for the diesel 

generator. Each enclosure is approximately 273 feet by 86 feet in plan area and is comprised of 

reinforced concrete walls, slabs, foundation mat, roof, masonry walls, and structural steel. The 

roof is reinforced concrete supported by structural steel that is protected by an elastomer roof 

membrane. In addition, the walls of each EDG enclosure are founded on bedrock and the base 

slab is supported by concrete fill placed on bedrock. The EDG enclosures are classified as 

seismic Category I and are physically located south of the seismic Category I reactor enclosure.

The purpose of the emergency diesel generator enclosure is to provide structural support, 

shelter, access control, and protection to safety-related systems, components, and structures 

housed within it during operation and postulated DBAs.
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LRA Table 2.4-9 identifies the EDG enclosure component types within the scope of license 

renewal and subject to an AMR.

2.4.9.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.9 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff’s review did not identify the 

need for any additional information.

2.4.9.3 Conclusion 

Based on its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the EDG enclosure components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.4.10 Piping and Component Insulation Commodity Group

2.4.10.1 Summary of Technical Information in the Application 

In LRA Section 2.4.10, the applicant described the piping and component insulation commodity 

group as comprised of prefabricated blankets, modules, panels, and sheet or bulk materials 

engineered to fit the piping and component surfaces to be insulated. In addition, the insulation 

group includes metallic and nonmetallic materials.

The purpose of piping and component insulation is to improve thermal efficiency, minimize heat 

loads on the HVAC systems, provide for personnel protection, prevent freezing of heat traced 

piping, and protect against sweating of cold piping and components. In addition, insulation 

located in areas with safety-related equipment is designed to protect nearby safety-related 

equipment from overheating and maintain its structural integrity during postulated design basis

seismic events.

LRA Table 2.4-10 identifies the piping and component insulation commodity group component 

types within the scope of license renewal and subject to an AMR. 

2.4.10.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.10 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff’s review did not identify the 

need for any additional information.

2.4.10.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the piping and component insulation commodity group components

within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also finds that the 

applicant has adequately identified the system components subject to an AMR in accordance 

with the requirements stated in 10 CFR 54.21(a)(1).
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2.4.11 Primary Containment

2.4.11.1 Summary of Technical Information in the Application 

In LRA Section 2.4.11, the applicant described the primary containment as a GE BWR;

specifically, a reinforced concrete Mark II type. Both LGS Units 1 and 2 have their primary 

containment structure completely enclosed and contained within a reactor enclosure. The 

reactor enclosure provides the secondary containment pressure boundary, shielding, and 

shelter and protection for the primary containment and the components housed within. The 

entire primary containment is structurally separated from the surrounding reactor enclosure,

except at the base foundation slab (a reinforced concrete mat, top-lined with a carbon steel liner 

plate) in which a seismic gap filled with foam is provided between the two adjoining foundation 

slabs. Included in the boundary of the primary containment are the reinforced concrete and 

steel components that make up the primary containment.

The primary containments located within the reactor enclosures are classified as seismic 

Category I safety-related structures and are physically located south of the control enclosure 

and north of the emergency diesel generator enclosure.

The purpose of the primary containment is to provide a high-integrity barrier against leakage of 

any fission products associated with postulated accidents involving loss of coolant and to limit 

the release of radioactive fission products to values that ensure offsite dose rates well below 

10 CFR 50.67 guideline limits. The primary containment also provides a source of water for the 

ECCS and for pressure suppression in the event of a LOCA. In addition, the primary 

containment and internal structures provide structural support to the RPV, RCSs, and other 

safety- and nonsafety-related SSCs housed within the primary containment.

LRA Table 2.4-11 identifies the primary containment component types within the scope of 

license renewal and subject to an AMR. 

2.4.11.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.11 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff’s review did not identify the 

need for any additional information.

2.4.11.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the primary containment components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately 

identified the system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).

2.4.12 Radwaste Enclosure

2.4.12.1 Summary of Technical Information in the Application 

In LRA Section 2.4.12, the applicant described the radwaste enclosure as a multistory structure 

approximately 150 feet by 199 feet in plan area with above- and below-grade areas. The 
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reinforced concrete foundation slab is supported by a layer of concrete placed on top of 

bedrock. The exterior and bearing walls are reinforced concrete; additionally, the exterior walls 

below-grade are waterproofed as necessary.

The radwaste enclosure is classified as a seismic Category IIA and designed in accordance with 

seismic Category I criteria, even though it is not required to protect the integrity of the RCPB, or 

to ensure the capability to safely shut down the reactor. Its failure would not result in potential 

offsite exposures comparable to the guideline exposures of 10 CFR 50.67. The structure is 

physically adjacent to the seismic Category I reactor enclosure. 

The purpose of the radwaste enclosure and offgas enclosure is to provide structural support, 

shelter and protection of the recovery, processing, and temporary storage of radioactive waste 

during the operation of the plant. In addition, the radwaste enclosure serves to contain any 

effluent accidentally spilled inside the enclosure.

LRA Table 2.4-12 identifies the radwaste enclosure component types within the scope of license 

renewal and subject to an AMR. 

2.4.12.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.12 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff’s review did not identify the 

need for any additional information.

2.4.12.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the radwaste enclosure components within the scope of license renewal, 

as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified 

the system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.4.13 Reactor Enclosure

2.4.13.1 Summary of Technical Information in the Application 

In LRA Section 2.4.13, the applicant described the reactor enclosure as an integral structure 

divided into separate LGS Unit 1 and Unit 2 reactor enclosures that share a common 

foundation, a common wall dividing the LGS Units 1 and 2 portions, a common refueling floor 

area, a common railroad airlock, a common refueling hoistway, and a common roof. The 

foundation for the reactor enclosure is a single integral unit consisting of continuous wall 

footings and spread column footings joined together by a continuous reinforced concrete mat 

founded on rock or on concrete fill placed on rock. The reactor enclosure is approximately 

326 feet by 137 feet in plan dimension at the ground level.

The reactor enclosures are safety-related seismic Category I reinforced concrete structures and 

are physically located south of the control enclosure and north of the emergency diesel 

generator enclosure.
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The purpose of the reactor enclosure and the refueling floor area are 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. In 

addition, the reactor enclosure is designed to minimize release of airborne radioactive fission 

products to values that ensure offsite dose rates are well below 10 CFR 50.67 guideline limits, 

and to provide for controlled filtered elevated release of the reactor enclosure atmosphere under 

accident conditions.

LRA Table 2.4-13 identifies the reactor enclosure components subject to an AMR for the SCs 

within license renewal by component type and intended function.

2.4.13.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.13 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff’s review did not identify the 

need for any additional information.

2.4.13.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the reactor enclosure components within the scope of license renewal, 

as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified 

the system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.4.14 Service Water Pipe Tunnel

2.4.14.1 Summary of Technical Information in the Application 

In LRA Section 2.4.14, the applicant described the SW pipe tunnel as a below-grade reinforced 

concrete rectangular box section approximately 326 feet long, 18 feet 6 inches wide and 17 feet 

6 inches high. In addition, the bottom slab is founded on concrete supported on bedrock and 

the roof slab extends to the grade level. Watertight doors provide below-grade access into the 

SW pipe tunnel from the adjacent reactor enclosure. The structure is classified as a 

safety-related seismic Category I structure and is physically located south of the reactor 

enclosure, adjacent to the west wall of the radwaste enclosure and the east wall of the auxiliary 

boiler and lube oil storage enclosure.

The purpose of the SW pipe tunnel is to provide structural support, shelter, and protection for 

LGS Units 1 and 2 for the ESW and RHR SW piping, piping components, and supporting 

components.

LRA Table 2.4-14 identifies the SW pipe tunnel component types within the scope of license 

renewal and subject to an AMR.

2.4.14.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.14 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff’s review did not identify the 

need for any additional information.
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2.4.14.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the SW pipe tunnel component types within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately 

identified the system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).

2.4.15 Spray Pond and Pump House

2.4.15.1 Summary of Technical Information in the Application 

In LRA Section 2.4.15, the applicant described the spray pond and pump house. The spray 

pond is an excavated below-grade pond, sized for a water volume adequate for cooling under 

design basis conditions. The spray pond is comprised of the excavated spray pond, spray 

network piping and reinforced concrete supports, reinforced concrete overflow weir structure, 

reinforced concrete intake area slab, and an earthen emergency spillway. A soil-bentonite liner 

and a protective soil cover are placed over the entire bottom of the pond and on the soil slopes. 

The soil cover on the slopes, in turn, is protected by riprap and riprap bedding. The rock slopes 

are treated by shotcrete for protection against weathering. Rock bolts also were installed at 

some locations in the rock slopes as an added stability measure.

The spray pond is classified as a safety-related seismic Category I structure and is physically 

located about 500 feet north of the cooling towers. The purpose of the spray pond is to provide 

the ultimate heat sink for both units that ensures an adequate source of cooling water is 

available at all times for reactor shutdown, cooldown, and accident mitigation.

The spray pond pump house is a two-story reinforced concrete structure approximately 46 feet

by 151 feet in plan area. It is comprised of reinforced concrete foundation slab and walls, steel 

floor and roof beams, and other miscellaneous structural and platform steel. A mezzanine floor 

composed of grating over steel beams supports the heating and ventilating equipment.

The spray pond pump house is classified as a safety-related and seismic Category I structure 

and is physically located on the south edge of the spray pond. The purpose of the spray pond 

pump house is to provide structural support, shelter and protection, and access to spray pond 

water for the RHRSW and ESW pumps, and associated piping, valves, and related equipment 

included with the safety-related SW system under postulated environmental and DBA loading 

conditions.

LRA Table 2.4-15 identifies the spray pond and pump house component types within the scope 

of license renewal and subject to an AMR.

2.4.15.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.15 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff’s review did not identify the 

need for any additional information.
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2.4.15.3 Conclusion

Based on its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the spray pond and pump house components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately 

identified the system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).

2.4.16 Turbine Enclosure

2.4.16.1 Summary of Technical Information in the Application 

In LRA Section 2.4.16, the applicant described the turbine enclosure as a steel-framed, 

reinforced concrete structure enclosed with precast concrete panels above grade. It is a 

multistory structure approximately 170 feet by 630 feet in plan area and has reinforced concrete 

footings and a foundation mat supported on bedrock. In addition, seismic separation gaps are 

provided at the interface of the turbine enclosure with the reactor, control, and radwaste 

enclosures.

The turbine enclosure is physically located north of the other powerblock enclosures (radwaste 

enclosure, reactor enclosure, and control enclosure) and is classified as a seismic Category II

nonsafety-related structure.

LRA Table 2.4-16 identifies the turbine enclosure component types within the scope of license 

renewal and subject to an AMR.

2.4.16.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.16 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff’s review did not identify the 

need for any additional information.

2.4.16.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the turbine enclosure components within the scope of license renewal, 

as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified 

the system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.4.17 Yard Facilities

2.4.17.1 Summary of Technical Information in the Application 

In LRA Section 2.4.17, the applicant described the yard facilities as comprised of the tank 

foundations and dikes, trenches, light poles, transmission towers, fire hose cart and storage cart 

foundations, manholes, valve pits and duct banks, railroad bridge, transformer foundations and 

dikes, yard drainage system, miscellaneous yard structures, and meteorological towers.
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The purpose of the yard facilities is to provide structural support, shelter, and protection for 

safety-related and nonsafety-related components and commodities, including components 

credited for fire protection and SBO. Dikes surrounding condensate storage and refueling water 

storage tanks are designed to contain and prevent radioactive effluent from reaching the surface 

waters.

LRA Table 2.4-17 identifies the yard facilities’ component types within the scope of license 

renewal and subject to an AMR.

2.4.17.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.17 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff’s review did not identify the 

need for any additional information.

2.4.17.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the yard facilities’ component types within the scope of license renewal, 

as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified 

the system components subject to an AMR in accordance with the requirements stated 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 and instrumentation and control systems. Specifically, this section discusses electrical 

and I&C component commodity groups

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived SSCs 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 are subject to an AMR.

The staff’s evaluation of the LRA information 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, components and supporting structures for electrical and I&C 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 the applicant’s RAI 

response, 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 application 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 SSCs with intended functions, the staff sought to determine whether the functions are 
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performed with moving parts or a change in configuration or properties or the SSCs 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 SSCs were 

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.5.1 Electrical and Instrumentation and Controls Commodity Groups

2.5.1.1 Summary of Technical Information in the Application 

LRA Section 2.5 describes the electrical and I&C systems. The scoping method considers all 

electrical and I&C systems, including components in the recovery path for loss of offsite power 

in the event of an SBO. The scoping method includes identifying the electrical I&C systems and 

their design functions and reviewing them against criteria contained in 10 CFR 54.4. The 

electrical and I&C components identified to be within the scope of license renewal have been 

grouped by the applicant into component commodity groups. The applicant has applied the 

screening criteria in 10 CFR 54.21 (a)(1)(i) and 10 CFR 54.21 (a)(1)(ii) to this list of component 

commodity groups to identify those that perform their intended functions without moving parts or 

without a change in configuration or properties and to remove the component commodity groups 

subject to replacement based on a qualified life or specified time period. The following list 

identifies the component commodity groups subject to an AMR and their intended functions:

 • cable connections (metallic parts) – electrical continuity

 • fuse holders: metallic clamps – electrical continuity

 • high-voltage insulators – insulate (electrical)

 • insulation material for electrical cables and connections – insulate (electrical)

 • MEB – electrical continuity, insulate (electrical), shelter, protection

 • switchyard bus and connections – electrical continuity

 • transmission conductors and connectors – electrical continuity

2.5.1.2 Staff Evaluation 

The staff reviewed LRA Section 2.5 and UFSAR Chapters 7 and 8 using the evaluation 

methodology described in SER Section 2.5 and the guidance in SRP-LR Section 2.5, “Scoping 

and Screening Results: Electrical and Instrumentation and Controls 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 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).

General Design Criteria 17 of Appendix A to 10 CFR Part 50 requires electric power from the 

transmission network to the onsite electric distribution system to be supplied by two physically 

independent circuits to minimize the likelihood of their simultaneous failure. In addition, the staff 

noted that the guidance provided by letter dated April 1, 2002, “Staff Guidance on Scoping of 

Equipment Relied on To Meet the Requirements of the Station Blackout Rule (10 CFR 50.63) 
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for License Renewal (10 CFR 54.4(a)(3)),” was later incorporated in SRP-LR Section 2.5.2.1.1, 

which stated the following:

Both the offsite and onsite power systems are relied upon to meet the 

requirements of the SBO Rule. This includes the following:

 • The onsite power system meeting the requirements under 10 CFR 54.4(a)(1) (safety-related

systems)

 • Equipment that is required to cope with an SBO (e.g., alternate ac power sources) meeting 

the requirements under 10 CFR 54.4(a)(3)

 • The plant system portion of the offsite power system that is used to connect the plant to the 

offsite power source meeting the requirements under 10 CFR 54.4(a)(3). The electrical 

distribution equipment out to the first circuit breaker with the offsite distribution system (i.e., 

equipment in the switchyard). This path typically includes the circuit breakers that connect 

to the offsite system power transformers (startup transformers), the transformers 

themselves, the intervening overhead or underground circuits between circuit breaker and 

transformer and transformer and onsite electrical distribution system, and the associated 

control circuits and structures. However, the staff's review is based on the plant-specific 

current licensing basis, regulatory requirements, and offsite power design configurations.

For purposes of the license renewal rule, the staff has determined that the plant 

system portion of the offsite power system that is used to connect the plant to the 

offsite power source should be included within the scope of the rule. This path 

typically includes switchyard circuit breakers that connect to the offsite system 

power transformers (startup transformers), the transformers themselves, the 

intervening overhead or underground circuits between circuit breaker and 

transformer and transformer and onsite electrical system, and the associated 

control circuits and structures. Ensuring that the appropriate offsite power 

system long-lived passive SSCs that are part of this circuit path are subject to an 

AMR will assure that the bases underlying the station blackout (SBO) 

requirements are maintained over the period of extended license.

In RAI 2.5-1, dated February 16, 2012, the staff requested the applicant to confirm if the control 

circuits and structures associated with the switchyard circuit breakers used to supply the SBO 

recovery paths are within the scope of license renewal. The applicant responded to RAI 2.5-1 

by letter dated March 5, 2012, stating that the circuit breaker control circuits are included in the 

scoping of electrical systems and components for SBO and also are part of the electrical 

commodities for the recovery path. Also, the applicant stated that the switchyard circuit breaker 

structures are included in the scope of license renewal. The staff reviewed the applicant’s 

March 5, 2012, letter and the LRA, and confirmed that the applicant included the control circuits 

and structures, associated with the switchyard circuit breakers, within the scope of license 

renewal.

The applicant included the circuits between the plant electrical distribution system and the 

electrical transmission network up to and including the circuit breakers between the switchyard 

bus and the offsite transmission lines. The switchyard bus and connections, transmission 

conductors and connectors, high-voltage insulators, substation structures and supports, 

inaccessible power cables, MEB, insulation material for electrical cables and connections, and 

cable connections (metallic parts) are within the scope of license renewal. Consequently, the 
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staff concludes that the scoping is consistent with the guidance issued April 1, 2002, and later

incorporated into SRP-LR Section 2.5.2.1.1.

The applicant did not include cable tie wraps and uninsulated grounding conductors in the 

component groups subject to an AMR because it determined that the cable tie wraps and the 

uninsulated grounding conductors do not perform any license renewal functions. The staff 

reviewed the UFSAR and found that cable tie wraps and uninsulated grounding conductors do 

not meet any of the criteria in 10 CFR 54.4(a) and, therefore, are not within the scope of license 

renewal. Therefore, the staff concludes that the exclusion of cable tie wraps and uninsulated 

grounding conductors from the component groups subject to an AMR is acceptable.

2.5.1.3 Conclusion 

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the electrical and instrumentation and controls commodity 

groups 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 stated in 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 the applicant’s scoping and screening 

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 on 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).

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 any 

changes to the CLB in order to comply with 10 CFR 54.21(a)(1), in accordance with the Atomic 

Energy Act of 1954, as amended, and NRC regulations.

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SECTION 3

AGING MANAGEMENT REVIEW RESULTS

This safety evaluation report (SER) section evaluates aging management programs (AMPs) and 

aging management reviews (AMRs) for Limerick Generating Station (LGS) Units 1 and 2, by the 

staff of the United States (US) Nuclear Regulatory Commission (NRC) (the staff). In 

Appendix B of its license renewal application (LRA), Exelon Generation Company, LLC (Exelon 

or the applicant) described the 45 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, or 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 (10 CFR)

Part 54, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants,” and the 

guidance of NUREG-1800, Revision 2, “Standard Review Plan for Review of License Renewal 

Applications for Nuclear Power Plants” (SRP-LR), issued December 2010 and the GALL Report.

In addition to its review of the LRA, the staff conducted an onsite audit of selected AMPs, during 

the weeks of October 3 and October 11, 2011. The onsite audits are designed for maximum 
3-2

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 follows the standard LRA format agreed to by the 

staff and the Nuclear Energy Institute (NEI) by letter dated April 7, 2003.

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 1s: 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 2s: 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.

The content of the previous LRAs and of the LGS Units 1 and 2 application is essentially the 

same. The intent of the revised format of the LRA was to modify the tables in LRA Section 3 to 

provide additional information that would assist in the staff’s review. In its Table 1s, the 

applicant summarized the portions of the application that it considered to be consistent with the 

GALL Report. In its Table 2s, 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 1s 

Each Table 1 compares in summary how the facility aligns with the corresponding tables in the 

SRP-LR. The tables are essentially the same as Tables 1 through 6 in the SRP-LR, except that 

the “Type” column has been replaced by an “Item” column and the “Item in GALL” column has 

been replaced by a “Discussion” column. The “Item” column is a means for the staff reviewer to 

cross-reference Table 2s with Table 1s. 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 GALL Report assumptions

 • discussion of how the line 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 the 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 the consistency can be checked easily.
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3.0.1.2 Overview of Table 2s 

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., engineered safety features (ESF), auxiliary systems). 

For example, the ESF group has tables specific to the core spray (CS) system, reactor core 

isolation cooling system, and residual heat removal system. Each Table 2 consists of nine 

columns:

 • Component Type – The first column lists LRA Section 2 component types subject to an AMR 

in alphabetical order.

 • 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.

 • Material – The third column lists the particular construction material(s) for the component 

type.

 • 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 Tables 3.0-1, 3.0-2, and 3.0-3. LRA Table 3.0-2 states that the indoor

air, uncontrolled environment encompasses the GALL Report defined environments of 

“air-indoor, uncontrolled,” “air-indoor, uncontrolled (greater than 95 °F),” “air with steam or 

water leakage,” “air with leaking secondary-side water and/or steam,” and “condensation.” 

LRA Table 3.0-2 also states that, for the uncontrolled indoor air environment, humidity levels 

of up to 100 percent are assumed, surfaces of components may be wet, and the 

environment may contain aggressive chemical species. The GALL Report indicates that the 

aging susceptibility of many materials in air depends on whether moisture is present.

Because the applicant used the term “air-indoor, uncontrolled” to encompass several 

GALL Report environments, the staff could not determine whether the proper aging 

effects and AMPs had been identified for those AMR items exposed to the environment 

of “air-indoor, uncontrolled.” By letter dated January 17, 2012, the staff issued 

RAI 3.0.2-1 requesting the applicant to (a) identify which AMR items in the LRA are 

exposed to an uncontrolled indoor air environment for which humidity, condensation, 

moisture, or other contaminants are present; and (b) if in identifying these items it is 

determined that the AMR items have additional aging effects requiring management, 

propose an AMP to manage the aging effect or state the basis for why no AMP is 

required.

In its response, by letter dated February 15, 2012, the applicant stated that the 

information in LRA Table 3.0-2 represented potentially acceptable LGS/GALL Report 

environment combinations that could be used if justified; however, the table did not 

reflect the actual environment combinations used. The applicant also stated that that 

there are no AMR items in the LRA for which the environment of uncontrolled indoor air 

contains humidity, condensation, moisture, or contaminants; and, therefore, there are no 

additional aging effects requiring management. The applicant further stated that air 

environments that have the potential for humidity, condensation, moisture, or 

contaminants have been identified as “air/gas-wetted” or “air-outdoor.”
3-4

The applicant revised LRA Tables 3.0-1 and 3.0-2 to reflect the actual LGS/GALL Report 

environment combinations used, including aligning the LGS environment of “air-indoor, 

uncontrolled” with the GALL Report environments of “air-indoor, uncontrolled” and 

“system temperature up to 288° C (550 °F)” (for closure bolting). The applicant also 

revised five AMR items for aluminum components and one AMR item for a galvanized 

steel component to correct discrepancies in the LRA in which the AMR correctly 

identified the environment as “air-indoor, uncontrolled”, but referred to the GALL Report 

item that corresponded to an “air-indoor, controlled” environment. The applicant revised 

LRA Tables 3.2.2-6, 3.3.2-4, and 3.3.2-16 to correct the references; however, no change 

in aging management approach was needed.

The staff finds the applicant’s response acceptable because the applicant has clarified 

its definition of the “air-indoor, uncontrolled” environment, such that the staff can 

determine whether the proper aging effects and AMPs have been identified for AMR 

items exposed to this environment. The staff’s individual AMR item evaluations for 

components exposed to “air-indoor, uncontrolled” are documented in the appropriate 

SER sections for their associated Table 1 references. The staff’s concern described in 

RAI 3.0.2-1 is resolved.

 • Aging Effect Requiring Management (AERM) – The fifth column lists AERMs. As part of 

the AMR process, the applicant determined any AERMs for each combination of material 

and environment.

 • Aging Management Programs – The sixth column lists the AMPs that the applicant uses 

to manage the identified aging effects.

 • 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 to identify the AMR results in the LRA tables corresponding to 

the items in the GALL Report tables.

 • Table 1 Item – The eighth column lists the corresponding summary item from LRA 

Table 1. 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 8 is left blank. In this 

manner, the information from the two tables can be correlated.

 • 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 work 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.

Staff 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.

3.0.2.1 Review of AMPs 

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 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 the 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 or 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.
3-6

 (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 Section 3.0.3 and 3.0.5.

3.0.2.2 Review of AMR Results 

Each LRA Table 2 contains information concerning whether or not 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. Items in Column 7 of the LRA, “NUREG-1801 Volume 2 Item,”

correlate to an AMR combination as identified in the GALL Report. A blank in Column 7 

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.
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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 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 GALL Report 

AMP. The staff audited these items to verify consistency with the GALL Report and confirmed

that the identified exceptions to GALL Report AMPs have been reviewed and accepted. The 

staff also determined whether the applicant’s AMP was consistent with 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 the GALL 

Report, is consistent with 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, is consistent 

with 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 confirmed whether the AMR item of the different component 

was applicable to the component under review and whether the identified exceptions to 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, the 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 
3-8

staff also conducted detailed discussions and interviews with the applicant’s license renewal 

project personnel and others with technical expertise relevant to aging management.

3.0.3 Aging Management Programs 

SER Table 3.0.3-1 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, if the program is a new or existing AMP and the section of this SER in which the 

staff’s evaluation of the program is documented.

Table 3.0.3-1 Aging Management Programs

AMP

(LRA Section)

New or 

Existing 

AMP

GALL Report 

Comparison

GALL Report AMPs Staff’s

SER 

Section

ASME Code Section XI 

Inservice Inspection, 

Subsections IWB, IWC, and 

IWD (B.2.1.1)

Existing Consistent XI.M1, “ASME Code 

Section XI Inservice 

Inspection, Subsections 

IWB, IWC, and IWD”

3.0.3.1.1

Water Chemistry (B.2.1.2) Existing Consistent XI.M2, “Water Chemistry” 3.0.3.1.2

Reactor Head Closure Stud 

Bolting (B.2.1.3)

Existing Consistent with 

exception

XI.M3, “Reactor Head 

Closure Stud Bolting.”

3.0.3.1.3

BWR Vessel ID Attachment 

Welds (B.2.1.4)

Existing Consistent XI.M4, “BWR Vessel ID 

Attachment Welds”

3.0.3.1.4

BWR Feedwater Nozzle

(B.2.1.5)

Existing Consistent XI.M5, “BWR Feedwater 

Nozzle”

3.0.3.1.5

BWR Control Rod Drive 

Return Line Nozzle

(B.2.1.6)

Existing Consistent with 

enhancement

XI.M6, “BWR Control Rod 

Drive Return Line Nozzle”

3.0.3.2.1

BWR Stress Corrosion 

Cracking (B.2.1.7)

Existing Consistent XI.M7, “BWR Stress

Corrosion Cracking”

3.0.3.1.6

BWR Penetrations (B.2.1.8) Existing Consistent XI.M8, “BWR Penetrations” 3.0.3.1.7

BWR Vessel Internals

(B.2.1.9)

Existing Consistent with 

enhancements

XI.M9, “BWR Vessel 

Internals”

3.0.3.2.2

Flow-Accelerated Corrosion

(B.2.1.10)

Existing Consistent XI.M17, “Flow-Accelerated 

Corrosion.”

3.0.3.1.8

Bolting Integrity (B.2.1.11) Existing Consistent with 

enhancements

XI.M18, “Bolting Integrity” 3.0.3.2.3

Open-Cycle Cooling Water 

System (B.2.1.12)

Existing Consistent with 

enhancements

XI.M21, “Open-Cycle 

Cooling Water System”

3.0.3.2.4

Closed Treated Water 

Systems (B.2.1.13)

Existing Consistent with 

enhancements

XI.M21A, “Closed Treated 

Water Systems”

3.0.3.2.5
3-9

AMP

(LRA Section)

New or 

Existing 

AMP

GALL Report 

Comparison

GALL Report AMPs Staff’s

SER 

Section

Inspection of Overhead 

Heavy Load and Light Load 

(Related to Refueling) 

Handling Systems

(B.2.1.14)

Existing Consistent with 

enhancements

XI.M23, “Inspection of 

Overhead Heavy Load and 

Light Load (Related to 

Refueling) Handling 

Systems”

3.0.3.2.6

Compressed Air Monitoring

(B.2.1.15)

Existing Consistent with 

enhancement

XI.M24, “Compressed Air 

Monitoring”

3.0.3.1.9

BWR Reactor Water 

Cleanup System (B.2.1.16)

Existing Consistent XI.M25, “BWR Reactor 

Water Cleanup System”

3.0.3.1.10

Fire Protection (B.2.1.17) Existing Consistent with 

enhancements

XI.M26, “Fire Protection” 3.0.3.2.7

Fire Water System (B.2.1.18) Existing Consistent with 

enhancements

XI.M27, “Fire Water System” 3.0.3.2.8

Aboveground Metallic Tanks

(B.2.1.19)

Existing Consistent with 

enhancements

XI.M29, “Aboveground

Metallic Tanks”

3.0.3.2.9

Fuel Oil Chemistry (B.2.1.20) Existing Consistent with 

enhancements

XI.M30, “Fuel Oil Chemistry” 3.0.3.2.10

Reactor Vessel Surveillance 

(B.2.1.21)

Existing Consistent XI.M31, “Reactor Vessel 

Surveillance”

3.0.3.1.11

One-Time Inspection 

(B.2.1.22)

New Consistent XI.M32, “One-Time 

Inspection”

3.0.3.1.12

Selective Leaching 

(B.2.1.23)

New Consistent XI.M33, “Selective Leaching 

of Materials”

3.0.3.1.13

One-Time Inspection of 

ASME Code Class 1

Small-Bore Piping (B.2.1.24)

New Consistent XI.M35, “One-Time 

Inspection of ASME 

Code Class 1 Small-Bore 

Piping”

3.0.3.1.14

External Surfaces Monitoring 

of Mechanical Components 

(B.2.1.25)

New Consistent XI.M36, “External Surfaces 

Monitoring of Mechanical 

Components”

3.0.3.1.15

Inspection of Internal 

Surfaces in Miscellaneous 

Piping and Ducting 

Components (B.2.1.26)

New Consistent XI.M38, “Inspection of 

Internal Surfaces in 

Miscellaneous Piping and 

Ducting Components”

3.0.3.1.16

Lubricating Oil Analysis

(B.2.1.27)

Existing Consistent XI.M39, “Lubricating Oil 

Analysis”

3.0.3.1.17

Monitoring of 

Neutron-Absorbing Materials 

Other than Boraflex

(B.2.1.28)

Existing Consistent with 

enhancements

XI.M40, “Monitoring of 

Neutron-Absorbing Materials 

Other than Boraflex”

3.0.3.2.11

Buried and Underground 

Piping and Tanks

(B.2.1.29)

Existing Consistent with 

enhancements

XI.M41, “Buried and 

Underground Piping and 

Tanks”

3.0.3.2.12
3-10

AMP

(LRA Section)

New or 

Existing 

AMP

GALL Report 

Comparison

GALL Report AMPs Staff’s

SER 

Section

ASME Code Section XI, 

Subsection IWE (B.2.1.30)

Existing Consistent with 

enhancements

XI.S1, “ASME Code 

Section XI, Subsection IWE”

3.0.3.2.13

ASME Code Section XI, 

Subsection IWL (B.2.1.31)

Existing Consistent with 

enhancement

XI.S2, “ASME Code 

Section XI, Subsection IWL”

3.0.3.2.14

ASME Code Section XI, 

Subsection IWF (B.2.1.32)

Existing Consistent with 

enhancement

XI.S3, “ASME Code 

Section XI, Subsection IWF”

3.0.3.2.15

10 CFR Part 50, Appendix J 

(B.2.1.33)

Existing Consistent XI.S4, “10 CFR Part 50, 

Appendix J”

3.0.3.1.18

Masonry Walls (B.2.1.34) Existing Consistent with 

enhancements

XI.S5, “Masonry Walls” 3.0.3.2.16

Structures Monitoring 

(B.2.1.35)

Existing Consistent with 

enhancements

XI.S6, “Structures 

Monitoring”

3.0.3.2.17

RG 1.127, “Inspection of 

Water-Control Structures 

Associated with Nuclear 

Power Plants” (B.2.1.36)

Existing Consistent with 

enhancements

XI.S7, “RG 1.127, Inspection 

of Water-Control Structures 

Associated with Nuclear 

Power Plants”

3.0.3.2.18

Protective Coating 

Monitoring and Maintenance 

(B.2.1.37)

Existing Consistent with 

enhancements

XI.S8, “Protective Coating 

Monitoring and Maintenance 

Program”

3.0.3.2.19

Insulation Material for 

Electrical Cables and 

Connections Not Subject to 

10 CFR 50.49 Environmental 

Qualification Requirements 

(B.2.1.38)

New Consistent XI.E1, “Insulation Material for 

Electrical Cables and 

Connections Not Subject to 

10 CFR 50.49 Environmental 

Qualification Requirements”

3.0.3.1.19

Insulation Material for 

Electrical Cables and 

Connections Not Subject to 

10 CFR 50.49 Environmental 

Qualification Requirements 

Used in Instrumentation 

Circuits (B.2.1.39)

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”

3.0.3.1.20

Inaccessible Power Cables 

Not Subject to 10 CFR 50.49 

Environmental Qualification 

Requirements (B.2.1.40)

New Consistent XI.E3, “Inaccessible Power 

Cables Not Subject to 

10 CFR 50.49 Environmental 

Qualification Requirements.”

3.0.3.1.21

Metal Enclosed Bus 

(B.2.1.41)

New Consistent XI.E4, “Metal Enclosed Bus” 3.0.3.1.22

Fuse Holders (B.2.1.42) New Consistent XI.E5, “Fuse Holders” 3.0.3.1.23

Electrical Cable Connections 

Not Subject to 10 CFR 50.49 

Environmental Qualification 

Requirements (B.2.1.43)

New Consistent XI.E6, “Electrical Cable 

Connections Not Subject to 

10 CFR 50.49 Environmental 

Qualification Requirements”

3.0.3.1.24
3-11

AMP

(LRA Section)

New or 

Existing 

AMP

GALL Report 

Comparison

GALL Report AMPs Staff’s

SER 

Section

Fatigue Monitoring (B.3.1.1) Existing Consistent with 

enhancements

X.M1, “Fatigue Monitoring” 3.0.3.2.20

Environmental Qualification 

(EQ) of Electric Components 

(B.3.1.2)

Existing Consistent X.E1, “Environmental 

Qualification (EQ) of Electric 

Components”

3.0.3.1.25

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 Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.2.1.1) 

 • Water Chemistry (B.2.1.2)

 • Reactor Head Closure Stud Bolting (B.2.1.3)

 • BWR (Boiling-Water Reactor) Vessel ID Attachment Welds (B.2.1.4)

 • BWR Feedwater Nozzle(B.2.1.5)

 • BWR Stress Corrosion Cracking (B.2.1.7)

 • BWR Penetrations (B.2.1.8)

 • Flow-Accelerated Corrosion (B.2.1.10)

 • Compressed Air Monitoring (B.2.1.15)

 • BWR Reactor Water Cleanup System (B.2.1.16)

 • Reactor Vessel Surveillance (B.2.1.21)

 • One-Time Inspection (B.2.1.22)

 • Selective Leaching (B.2.1.23)

 • One-Time Inspection of ASME Code Class 1 Small-Bore Piping (B.2.1.24)

 • External Surfaces Monitoring of Mechanical Components (B.2.1.25)

 • Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.26)

 • Lubricating Oil Analysis (B.2.1.27)

 • 10 CFR Part 50, Appendix J (B.2.1.33)

 • Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements (B.2.1.38)

 • Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Used in Instrumentation Circuits (B.2.1.39)

 • Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements (B.2.1.40)

 • Metal Enclosed Bus (B.2.1.41)
3-12

 • Fuse Holders (B.2.1.42)

 • Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements (B.2.1.43)

 • Environmental Qualification (EQ) of Electric Components (B.3.1.2)

3.0.3.1.1 ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

Summary of Technical Information in the Application. LRA Section B.2.1.1 describes the 

existing ASME [American Society of Mechanical Engineers] Section XI Inservice 

Inspection (ISI), Subsections IWB, IWC, and IWD program as consistent with GALL Report 

AMP XI.M1, “ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD.” 

It states that this program manages cracking, loss of fracture toughness, and loss of material in 

ASME Code Class 1, 2, and 3 piping and components within the scope of license renewal. The 

LRA also states that this program includes periodic visual, surface, volumetric examinations, 

and leakage tests of ASME Code, Class 1, 2, and 3 pressure-retaining components, including 

welds, pump casings, valve bodies, integral attachments, and pressure-retaining bolting. 

In addition, the LRA states that indications and relevant conditions detected during 

examinations are evaluated in accordance with ASME Code, Section XI, Articles IWB-3000, 

IWC-3000, and IWD-3000. The LRA states that the program directs that repair and 

replacement activities be performed in accordance with ASME Code, Section XI, IWA-4000. 

The LRA further states that this program is updated during each successive 120-month 

(10-year) inspection interval to comply with the requirements of the ASME Code, Section XI, 

Subsections IWB, IWC, and IWD, edition and addenda in accordance with 10 CFR 50.55a, 

subject to prior approval of the edition and addenda by the NRC. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by 

the conditions for which the GALL Report was evaluated.

The staff compared elements 1-6 of the applicant’s program to the corresponding elements of 

GALL Report AMP XI.M1. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant’s program is consistent with the corresponding element of GALL Report 

AMP XI.M1. 

The “detection of aging effects” program element in GALL Report AMP XI.M1 states that ASME

Code, Section XI, Table IWB-2500-1, is used to determine the examination of Categories B-F 

and B-J welds. The staff noted that the applicant implemented risk-informed inservice 

inspection (RI-ISI) with Examination Category R-A instead of Categories B-F and B-J for the 

current 10-year ISI interval as approved by the NRC. The RI-ISI provides alternate inspection 

requirements for a subset of ASME Code Class 1 piping welds. The staff noted that the use of 

RI-ISI is only approved for the current 10-year ISI interval. Future implementation of RI-ISI is 

subject to the NRC approval in accordance to 10 CFR 50.55a for each subsequent 10-year ISI 

interval, including the period of extended operation. The staff confirmed during the onsite audit 

that the applicant’s ISI program plan calls for a review of the RI-ISI implementation for future 

inspection intervals. The staff finds this acceptable because the applicant will have to seek 

NRC approval for use of this RI-ISI relief request for future inspection intervals.
3-13

The staff noted that the applicant updates its program every 10 years (120 months) to the latest 

ASME Code, Section XI, as approved by the NRC before the start of the inspection interval. 

Both LGS Unit 1 and LGS Unit 2 are in their third 10-year ISI interval, which began on 

February 1, 2007. The current ASME Code of record for both LGS Unit 1 and LGS Unit 2 is the 

2001 Edition through the 2003 Addenda.

Based on its audit, the staff finds that elements 1-6 of the ASME Code Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD program are consistent with the corresponding 

program elements of GALL Report AMP XI.M1 and, therefore, acceptable.

Operating Experience. LRA Section B.2.1.1 summarizes operating experience related to the 

ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program. The 

applicant indicated that this program is based on the ASME Code, Section XI, Subsections IWB, 

IWC, and IWD, which is based on industrywide operating experience, research data, and 

technical evaluations. The applicant stated that plant-specific examples are documented in its 

ISI summary reports and in the corrective action program (CAP) records. The staff sampled 

inspection results from the current 10-year interval ISI summary reports. For example, the ISI 

program examinations identified multiple pinhole leaks and pipe wall thinning in its emergency 

service water (ESW) piping and residual heat removal service water (RHRSW) system piping in 

both LGS Unit 1 and LGS Unit 2. The applicant performed numerous analyses and attributed 

the pinhole leaks and wall thinning to initial operation with untreated water, which established 

significant corrosion cells. As part of the corrective actions, the applicant has improved its water 

treatment to eliminate the root cause. In addition, as part of the ISI repair and replacement, the 

applicant has replaced some of the degraded piping with more corrosion-resistant stainless 

steel piping. The evaluation of the operating experience related to the applicant’s ESW and 

RHRSW system piping is further discussed in the staff’s review of LRA Section B.2.1.12, “Open 

Cycle Cooling Water System,” as documented in Section 3.0.3.2.4 of this SER. 

The staff reviewed the applicant’s ISI summary reports submitted for the current and previous 

10-year ISI intervals for both LGS units to verify that the applicant’s implementation of the 

program was effective in detecting, trending, and correcting those aging effects for which the 

program was credited. The staff’s review of these ISI summary reports did not reveal any 

evidence that would demonstrate that the program was ineffective in detecting the aging effects 

this program manages.

The applicant stated that its operating experience is consistent with industry operating 

experience. It cited multiple examples in which examinations performed per the ISI program 

have been effective in detecting flaws, evaluating flaws, and directing repair and replacement 

activities. The applicant further indicated that it will use its site-specific corrective action 

program and an ongoing review of industry operating experience to ensure that the ASME Code 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program remains effective in 

managing the identified aging effects. The staff reviewed the operating experience information 

in the application and information obtained during the audit to determine whether the applicant 

reviewed the applicable aging effects, industry, and plant-specific operating experience. 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. During its review, the staff did 

not find operating experience to indicate that the applicant’s program would not be effective in 

adequately managing aging effects during the period of extended operation.
3-14

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.1 provides the UFSAR supplement for the ASME 

Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program. The staff 

reviewed this UFSAR supplement description of the program and notes that it conforms to the 

recommended description for this type of program as described in SRP-LR Table 3.0-1. The 

staff determines that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the ASME Code Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD program, the staff finds all program elements 

consistent with the GALL Report. 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).

3.0.3.1.2 Water Chemistry

Summary of Technical Information in the Application. LRA Section B.2.1.2 describes the 

existing Water Chemistry program as consistent with GALL Report AMP XI.M2, “Water 

Chemistry.” The LRA states that this program uses the guidance of the Boiling Water Reactor 

Vessel and Internals Project (BWRVIP)-190, “BWR Water Chemistry Guidelines – 2008 

Revision,” and addresses the reactor vessel, reactor internals, piping components, heat 

exchangers, and tanks exposed to treated water environments. The LRA also states that this 

program manages loss of material, cracking, and reduction of heat transfer through monitoring, 

trending, and controlling of the chemical environments for detrimental contaminants in 

associated systems. The LRA further states that this program does not detect aging effects, but 

components located in stagnant or low flow areas, where water chemistry programs may not be 

effective, will be inspected as part of the One-Time Inspection program to verify proper 

chemistry control and aging management. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP Xl.M2. Based on its audit of the Water 

Chemistry program, the staff finds that program elements 1-6 for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.M2. 

Operating Experience. LRA Section B.2.1.2 summarizes operating experience related to the 

Water Chemistry program. The LRA described an occurrence in 2003 in which the stability of 

insoluble iron for LGS Unit 2 was less than the values for LGS Unit 1. The LRA stated that a 

common-cause analysis determined that the differences between the units’ sample line 

diameters and lengths had caused the discrepancy because of the effects of velocity and flow 

rates on particulate suspension. The LRA described changes made to the sampling practices 
3-15

and stated this illustrated the effectiveness of the program to identify and resolve issues through 

monitoring and implementing corrective actions. 

The LRA also described an occurrence in 2006 related to increasing trends in reactor water 

conductivity and chlorides following a refueling outage, which exceeded chemistry action levels 

for a short period of time (i.e., less than the limiting condition for operation). The LRA stated 

that a root cause investigation determined that the excursion may have been because of the 

use of a chlorinated solvent. After evaluating various aspects, the LRA recommended that 

noble metals be reapplied because of the potential for crack flanking of the noble metal coating. 

The LRA concluded that this illustrated the effectiveness of the program to analyze the extent of 

chemistry excursions and to evaluate the effects of these deviations.

The staff reviewed operating experience information in the application and during the audit to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the audit report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately evaluated and incorporated operating experience related to this program. During its 

review, the staff found no operating experience to indicate that the applicant’s program would

not be effective in adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

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 

against the recommended description for this type of program as described in SRP-LR 

Table 3.0-1 and noted that, although the supplement stated that the program is based on 

BWRVIP Water Chemistry Guidelines, it did not state that the program is based on 

BWRVIP-190, which is the 2008 revision. The licensing basis for this program for the period of 

extended operation may not be adequate if the applicant does not incorporate this information 

into its UFSAR supplement. By letter dated January 17, 2012, the staff issued RAI B.2.1.2-1,

requesting the applicant to include BWRVIP-190 in its UFSAR supplement for this program.

In its response, provided by letter dated February 15, 2012, the applicant revised LRA 

Section A.2.1.2 to state that the program is based on the guidelines of BWRVIP-190. The staff 

also noted that similar information was included in the new LRA Appendix C, “Response to 

BWRVIP License Renewal Applicant Action Items,” item BWRVIP-74-A(6). The staff finds the 

applicant’s response acceptable because the description of the Water Chemistry program in the 

UFSAR supplement includes BWRVIP-190, which will ensure the licensing basis will be 

adequately maintained during the period of extended operation. Therefore, the UFSAR 

supplement for the Water Chemistry program is consistent with the corresponding program 

description in SRP-LR Table 3.0-1. The staff’s concern described in RAI B.2.1.2-1 is resolved.

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

February 15, 2012, is an adequate summary description of the program.
3-16

Conclusion. On the basis of its audit and review of the Water Chemistry program, the staff 

concludes that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. The staff also 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 reviewed the UFSAR supplement for this AMP and further 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

3.0.3.1.3 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 GALL Report 

AMP XI.M3, “Reactor Head Closure Stud Bolting.”

The LRA states that the Reactor Head Closure Stud Bolting program is an existing condition 

monitoring and preventive program that provides for ASME Code, Section XI, inspections of 

reactor head closure studs, associated nuts, bushings, flange threads, and washers for cracking 

and loss of material. The LRA also states that the program manages these aging effects in air 

with reactor coolant leakage environment. The LRA further states that the program is based on 

the examination and inspection requirements specified in the ASME Code, Section XI, 

Subsection IWB, Table IWB-2500-1, and preventive measures described in NRC Regulatory 

Guide (RG) 1.65, “Materials and Inspections for Reactor Vessel Closure Studs.” The LRA 

states that the inspections monitor for cracking, loss of material, and coolant leakage. The LRA 

also states that the flange threads and studs receive a volumetric examination and the surfaces 

of nuts and washers are inspected using visual VT-1 examination. The LRA further states that 

all pressure-retaining boundary components in Examination Category B-P receive visual VT-2 

examination during the system leakage and the system hydrostatic tests. 

In addition, the LRA states that the program includes the preventive measures to mitigate 

cracking described in RG 1.65, which includes the use of approved corrosion inhibitors and 

lubricants. The LRA also stated that the reactor head closure studs, nuts, bushings, flange 

threads, and washers are fabricated with approved materials and surface-treated with an 

acceptable phosphate coating to inhibit corrosion and reduce stress corrosion cracking (SCC) 

and intergranular stress corrosion cracking (IGSCC). The applicant further stated that the 

reactor head closure studs are constructed of ASME Code SA540 Grade B24, Class 3 material, 

which has a maximum tensile strength level less than 170 ksi.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M3. For the applicant’s “preventive 

actions” program element, the staff noted a potential exception to GALL Report AMP. 

Therefore, the staff issued an RAI, as discussed below.

The “preventive actions” program element in GALL Report AMP XI.M3 lists preventive 

measures that can reduce the potential for SCC and IGSCC. These measures, among others, 

include using bolting material for closure studs that has actual measured yield strength less than 

150 ksi, and using manganese phosphate or other acceptable surface treatments. During its 

audit, the staff noted that the applicant’s onsite documentation for its reactor head closure stud 

bolting program indicated that some of the closure studs and nuts were manufactured from 
3-17

material with actual measured yield strength greater than 150 ksi. The staff also noted that the 

LRA AMP states that the reactor head closure stud, nut, bushing, flange thread, and washer 

surfaces are treated with an acceptable phosphate coating to inhibit corrosion and reduce SCC 

and IGSCC. However, Section 5.3.1.11 of the applicant’s UFSAR indicates that a phosphate 

coating is only applied to threaded areas of studs and nuts and bearing areas of nuts and 

washers. It was not clear to the staff if closure bolting with measured yield strength greater than 

150 ksi will be used during the period of extended operations and if a phosphate coating was 

actually applied to the applicant’s flange threads as stated in the LRA. 

By letter dated January 17, 2011, the staff issued RAI B.2.1.3-1, requesting the applicant to

clarify if closure studs and nuts manufactured from material with actual measured yield strength 

greater than 150 ksi will be used during the period of extended operation. If so, the applicant 

was asked to justify the adequacy of the program to manage cracking because of SCC, to 

provide clarification if a phosphate coating was applied on the flange threads, whether the 

phosphate coating applied to the closure bolting components is intact, and to justify adequacy of 

the program if that was not the case.

Exception. By letter dated February 15, 2012, the applicant amended LRA Section B.2.1.3 and 

identified the use of closure studs with actual measured yield strength greater than or equal to 

150 ksi as an exception to the “preventive actions” program element of GALL Report 

AMP XI.M3.

As part of its response, the applicant provided a table summarizing the actual measured yield 

and tensile strength values for LGS, Units 1 and 2 reactor head closure bolting. The applicant 

stated that it has revised its purchasing requirements for reactor head closure studs to ensure 

that any replacement studs installed in the future will have measured yield strength less than 

150 ksi. Also, as part of its response on aging management for SCC, the applicant stated that 

its program is consistent with other aspects of preventive measures listed in GALL Report 

AMP XI.M3; e.g., that metal-plated stud bolting is not used and an approved stable lubricant is 

applied to the studs and associated hardware whenever the reactor head is installed, which 

does not contain molybdenum disulfide (MoS2). The applicant stated that the volumetric 

ultrasonic examination (UT) method is used for the stud inspections to identify cracking. 

Furthermore, following each refueling outage, a system pressure test is performed to identify 

and correct any potential reactor coolant leaks, thus avoiding exposure of the studs to an 

environment conducive to SCC. The applicant stated that there have been no recordable 

indications identified by past examinations of reactor head closure stud bolting components over 

the past 10 years, indicating that the current program has been effective in managing cracking. 

The staff reviewed the applicant’s exception on the use of bolting material with actual measured 

yield strength greater than 150 ksi. As part of its review, the staff reviewed the applicant’s 

justification for the adequacy of the AMP to manage SCC in the high-strength material. 

Specifically, the staff reviewed the maximum measured yield strength and tensile strength data 

the applicant extracted from the certified material test report for the applicant’s reactor head 
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closure studs. The staff noted that the maximum measured tensile strength of the studs ranged 

from 164 ksi to 169 ksi as shown below:

Heat Average Yield 

Strength

Maximum Yield Strength Maximum Tensile 

Strength

Where Used

89616 146.0 ksi 150.5 ksi 164 ksi Unit 1 - All Studs, 

Unit 2 - 1 Stud

19626 144.0 ksi 150.5 ksi 165 ksi Unit 2 - 69 Studs

83222 152.1 ksi 157.0 ksi 169 ksi Unit 2 - 4 Studs

61923 148.9 ksi 152.7 ksi 167.34 ksi Unit 2 - 2 Studs

In addition, the staff noted that with the exception of four studs for LGS Unit 2, all of the average 

measured yield strength values for the studs are below 150 ksi. The staff also noted that a 

limited number of studs have average yield strength slightly exceeding 150 ksi. The staff further 

noted that the applicant uses stable lubricants for its reactor head closure bolting, which is an 

appropriate measure to mitigate or prevent SCC in the closure bolting components, consistent 

with the GALL Report. Moreover, the staff reviewed the most recent ISI summary reports for 

LGS Units 1 and 2 and confirmed that the ultrasonic examinations did not find any recordable 

indications for the applicant’s closure studs and flange threads. Furthermore, the staff noted 

that VT-1 examinations also confirmed that there were no recordable indications reported for the 

applicant’s reactor head closure nuts and washers. 

Based on its review, the staff finds the exception acceptable because the program includes 

ultrasonic examination of each closure stud during each inspection interval, which provides 

reasonable assurance that SCC in closure studs can be detected and adequately managed

before loss of intended function, the volumetric examinations of the closure studs have not 

indicated any evidence of SCC, and all of the applicant’s closure studs have measured tensile 

strength values less than 170 ksi. In addition, the majority of the applicant’s closure studs have 

average measured yield strength values less than 150 ksi; therefore, these components do not 

have significantly high susceptibility to SCC and the applicant’s use of stable lubricants is an 

appropriate preventive measure to ensure that closure studs are protected from contaminants 

that could lead to SCC. Therefore, the staff’s concerns regarding SCC described in 

RAI B 2.1.3-1 are resolved.

By the same letter dated February 15, 2012, the applicant also revised the LRA to remove the 

bushings and flange threads from the list of components fabricated with phosphate coating and 

removed bushings from the list of components the program managed. In its response to the 

application of a protective coating, the applicant stated that its review of the staff’s RAI resulted 

in identifying that its design for reactor head closure stud bolting does not include bushings as 

stated in LRA Section B.2.1.3 and Section A.2.1.3. The applicant stated that a manganese 

phosphate coating was applied to the threaded areas of the studs and nuts, and bearing areas 

of the nuts and washers as described in the UFSAR, while a phosphate coating was not applied 

to the flange threads. The applicant also stated that based on recent observations by personnel 

performing inspections of the closure bolting components, there was no visual evidence that the 

manganese phosphate coating is intact. The applicant further stated that corrosion is managed 

effectively by the application of an approved, stable lubricant whenever the stud bolting is 

assembled and by periodic examinations in accordance with ASME Code requirements. The 

applicant also stated that there have been no recordable indications identified by the ASME 

Code-required examinations. The staff finds this response acceptable because the applicant 

has appropriately revised the LRA to be consistent with its UFSAR. The staff’s concerns 
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expressed in RAI B 2.1.3-1 about the inconsistencies the staff noted in the applicant’s LRA and 

UFSAR are resolved. 

In addition, the staff reviewed the applicant’s justification of the adequacy of its program to 

manage the aging effects caused by corrosion in the absence of the phosphate coating on the 

applicant’s reactor closure bolting. During its review, the staff noted that the applicant uses 

stable lubricants for its closure bolting, which can mitigate corrosion by precluding contact with 

contaminants that can cause corrosion. The staff also noted that as part of the ASME 

Code-required periodic examinations, the applicant performs VT-2 examination of

pressure-retaining components during system leakage testing. The staff further noted that VT-1 

examinations of the applicant’s nuts and washers confirmed that there were no recordable 

indications on the applicant’s closure bolting, providing confirmation that the applicant’s program 

is effective in mitigating the aging effects of corrosion. Therefore, the staff’s concerns about the 

integrity of the phosphate coating expressed in RAI B 2.1.3-1 are resolved. 

Based on its audit, and review of the Reactor Head Closure Stud Bolting program, the staff finds 

that the program elements 1, 3, 4, 5, and 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 exception associated with the “preventive actions”

program element and the applicant’s response to RAI 2.1.3-1. Based on its review, the staff 

finds the applicant’s proposed AMP, with exception, is adequate to manage the applicable aging 

effects. 

Operating Experience. LRA Section B.2.1.3 summarizes operating experience related to the 

Reactor Head Closure Stud Bolting program. The applicant stated that ultrasonic examinations 

performed on all of the closure studs and flange threads for LGS Units 1 and 2 from 2002 

to 2010 confirmed that there were no recordable indications. The applicant also stated that 

during the same period, VT-1 examinations performed on all of the closure washers and nuts 

also confirmed that there were no recordable indications. The applicant further stated that 

historically, inspections have found the reactor closure studs, flange threads, nuts, and washers 

to be in satisfactory condition. The applicant also stated that the review of the operating 

experience for the Reactor Head Closure Stud Bolting program did not identify an adverse trend 

in performance or signs of age-related degradation. Based on its operating experience review 

results, the applicant stated that there is confidence that continued implementation of the 

Reactor Head Closure Stud Bolting program will effectively identify degradation before failure 

during the period of extended operation.

The staff reviewed operating experience information in the application and during the audit to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the Audit Report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant adequately 

evaluated and incorporated operating experience related to this program.

During its review, the staff found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 
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aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.3, as revised by letter dated February 15, 2012,

provides the UFSAR supplement for the Reactor Head Closure Stud Bolting program. The staff 

reviewed the revised UFSAR supplement description of the program and notes that it conforms 

to the recommended description for this type of program as described 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 Reactor Head Closure Stud Bolting 

program, the staff determines that the 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 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).

3.0.3.1.4 BWR Vessel Inside Diameter (ID) Attachment Welds

Summary of Technical Information in the Application. LRA Section B.2.1.4 describes the 

existing BWR Vessel ID Attachment Welds program as consistent with GALL Report 

AMP XI.M4, “BWR Vessel ID Attachment Welds.” 

The LRA states that the program manages the effects of cracking in the reactor vessel inside 

diameter (ID) attachment welds by the inspection and evaluation recommendations of 

BWRVIP-48-A. The program provides for mitigation of cracking through management of reactor 

water chemistry and monitoring for cracking through in-vessel examinations of the reactor 

vessel internal attachment welds. The program also manages the effects of loss of material 

caused by wear of the steam dryer support brackets. These inspections are implemented as 

part of augmented ISI requirements.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M4. 

During its audit, the staff noted that the applicant manages the effects of loss of material caused 

by wear of the LGS Unit 1 steam dryer support brackets by using a visual VT-3 examination as 

part of the BWR Vessel ID Attachment Welds program. The staff noted that loss of material is 

not addressed in GALL Report AMP XI.M4 or BWRVIP-48-A; therefore, it is not clear to the staff 

whether the VT-3 examination is an appropriate and effective inspection method to identify loss 

of material of the steam dryer support brackets. The staff noted that since BWRVIP-48-A does 

not manage wear or loss of material, the applicant has not identified the acceptance criteria for 

the inspections of steam dryer support brackets and associated corrective actions if the 

acceptance criteria are not met. By letter dated November 18, 2011, the staff issued 

RAI B.2.1.4-1 requesting the applicant to justify the use of a visual VT-3 examination for the 
3-21

steam dryer support brackets and to identify the acceptance criteria and associated corrective 

actions.

In its response, provided by letter dated December 7, 2011, the applicant stated that the 

inspection of the bracket for loss of material because of wear by visual VT-3 examination is 

appropriate to identify this aging effect because ASME Code Section XI, Article IWA-2213(a) 

indicates that visual VT-3 can be conducted to determine loose or missing parts, debris, 

corrosion, wear, or erosion. The staff noted that it is consistent with the “detection of aging” 

program element of GALL Report AMP XI.M4 that VT-3 examinations can be used to determine 

the general mechanical and structural condition of the components. Thus, the staff finds it is 

reasonable that wear or loss of material for the steam dryer support brackets can be detected 

with the use of VT-3 examinations. 

The applicant explained that BWRVIP48-A refers to ASME Code Section XI, Subsection 

IWB-3520 for acceptance criteria. The staff noted that ASME Code Section XI, Subsection 

IWB-3520.2 provides acceptance criteria and relevant conditions that require corrective actions 

before continued service for VT-3, which is consistent with the “acceptance criteria” program 

element of the GALL Report AMP XI.M4.

The applicant also stated that corrective actions for wear conditions are performed in 

accordance with ASME Code Section XI, Subsection IWB-3140. The staff noted that corrective 

actions in ASME Code, Section XI, Subsection IWB-3143, include repair and replacement 

activities that are equivalent to those in ASME Code, Section XI, Subsection IWA-4000, and are 

also consistent with the “corrective actions” program element of GALL Report AMP XI M4. The 

applicant explained that other activities that have been performed for the wear conditions 

identified on the steam dryer support brackets included performing engineering evaluation and 

followup inspections during subsequent LGS Unit 1 outages to monitor and trend the wear 

condition in accordance with its CAP and performing extent of condition examinations for wear 

on LGS Unit 2 components. 

The applicant stated that a CAP issue report has been initiated to revise the implementing 

procedure. The revision will document programmatic elements, including the use of visual VT-3 

examination, acceptance criteria, and corrective actions related to the inspection of steam dryer 

support brackets to manage loss of material because of wear. The staff noted that the UFSAR 

supplement in LRA Section A.2.1.4 is also revised to include a description of how the program 

manages the effects of loss of material caused by wear of the steam dryer support brackets.

The staff finds the applicant’s response acceptable because its inspection methodology, 

acceptance criteria, and corrective actions are consistent with the provision in ASME 

Code Section XI, which have been proven capable of detecting and managing loss of material 

caused by wear and the BWR Vessel ID Attachment Welds program ensures that these 

inspections will be conducted as part of its augmented ISI requirements. The staff’s concern 

described in B.2.1.4-1 is resolved.

Based on its audit of the BWR Vessel ID Attachment Welds program, the staff finds that 

program elements 1-6 for which the applicant claimed consistency with the GALL Report are 

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

Operating Experience. LRA Section B.2.1.4 summarizes operating experience related to the 

BWR Vessel ID Attachment Welds program. 
3-22

The applicant indicated that the examinations of LGS Units 1 and 2 vessel internal attachment 

welds were performed using enhanced visual techniques (EVT)-1 between the 2000 and 2009 

refueling outages. The applicant stated that the examinations included all of the jet pump riser 

brace support pads, the feedwater sparger attachment welds, the steam dryer support bracket 

attachment welds, and the CS bracket attachment welds. The applicant further stated that 

examination of the guide rod bracket attachment welds was performed using VT-3 visual 

techniques and no indications were identified. Examination of the surveillance sample holder 

attachment welds was performed using VT-1 visual techniques and no indications were 

identified.

The applicant indicated re-inspection of all four LGS Unit 1 steam dryer support bracket 

attachment welds was performed using visual techniques in 2010 and that wear was identified 

on all four brackets and a condition report was generated to evaluate the wear. The indications 

on three of the four brackets were considered normal wear and the wear on one of the brackets 

was considered notable. In accordance with the program requirements, scope expansion was 

defined, which included additional examinations of the steam dryer hold down brackets (on the 

underside of the RPV head) and the steam dryer seismic blocks (on the steam dryer support 

ring) during the 2010 outage. The applicant further stated that no indications were identified on 

the steam dryer hold down brackets.

The staff reviewed operating experience information in the application and during the audit, to 

determine if the applicant reviewed applicable aging effects and industry and plant-specific 

operating experience. As discussed in the audit report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately evaluated and incorporated operating experience related to this program. During its 

review, the staff found no operating experience to indicate that the applicant’s program would 

not be effective in adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.4, as amended by letter dated December 7, 2011, 

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 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 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 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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3.0.3.1.5 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 program is designed to ensure that aging degradation caused by

cracking is adequately managed for the nozzle components, so that its intended function is 

maintained through the end of the period of extended operation. 

The LRA states that its BWR Feedwater Nozzle program consists of augmented ISI in 

accordance with the requirements of the ASME Code, Section XI, Subsection IWB, 

Table IWB 2500-1, and the recommendations of General Electric (GE) NE-523-A71-0594-A, 

Revision 1. The program specifies periodic ultrasonic inspection of critical regions of the 

feedwater nozzles. In response to NUREG-0619, “BWR Feedwater Nozzle and Control Rod 

Drive Return Line Nozzle Cracking,” design changes were made to the feedwater nozzles 

before initial reactor operation to mitigate or prevent thermally induced fatigue cracking. The 

current design does not include cladding on the nozzle inner surface and uses a triple thermal 

sleeve feedwater sparger design with two ring seals.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M5. 

In particular, the staff confirmed that the AMP addresses the detection and sizing of cracks by 

ISI in accordance with ASME Code, Section XI, Subsection IWB. The staff also confirmed that 

the inspection schedule is in accordance with Table 6-1 of the GE-NE-523-A71-0594-A, 

Revision 1, consistent with the recommendation of GALL Report AMP XI.M5. In addition, it was 

confirmed that the AMP requires that any repair or replacement activities be implemented in 

accordance with the guidelines of the ASME Code, Section XI, IWB-4000.

The staff also reviewed UFSAR Section 5.2.4.8 and confirmed that the feedwater nozzle has 

been modified and the current configuration is the triple-sleeve with two sister ring seals and an 

unclad nozzle. The staff noted that this design ensures the longest ISI intervals in accordance 

with NUREG-0619.

Based on its audit of the BWR Feedwater Nozzle program, the staff finds that program elements 

1-6 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 applicant stated that it started operation in 1986 with 

important design features recommended by NUREG-0619 incorporated into the plant design, 

including eliminating the cladding on the nozzle inner diameter and the use of low leakage triple 

thermal sleeve feedwater spargers. The applicant also stated that the feedwater nozzles have 

been inspected for cracking as part of the existing augmented ISI program, in accordance with 

the guidance in GE-NE- 523-A71-0594-A, Revision 1. Recordable indications were noted and a 

fracture mechanics analysis was performed in 2000 to validate the inspection interval based on 

the requirements of GE-NE-523-A71-0594-A, Revision 1. 

The staff reviewed operating experience information in the application and during the audit to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 
3-24

operating experience. As discussed in the audit report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately evaluated and incorporated operating experience related to this program. During its 

review, the staff found no operating experience to indicate that the applicant’s program would 

not be effective in adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

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 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 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).

3.0.3.1.6 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 BWR Stress Corrosion Cracking program is an existing 

condition monitoring and mitigation program that manages IGSCC in the piping and piping 

components made of stainless steel and nickel-based alloy in a reactor coolant environment as 

delineated in NUREG-0313, Revision 2, and NRC Generic Letter (GL) 88-01, “NRC Position on 

IGSCC in BWR Austenitic Stainless Steel Piping,” dated January 25, 1988, and its 

Supplement 1, dated February 4, 1992. The program includes preventive measures to mitigate 

IGSCC, and inspection and flaw evaluation to monitor IGSCC and its effects. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M7. For the “scope of program,” and 

“detection of aging effect” program elements, the staff determined the need for additional 

information, which resulted in the issuance of RAIs as discussed below.

GALL Report AMP XI.M7 states that NUREG-0313, Revision 2, and GL 88-01 delineate the 

guidance for selection of resistant materials and processes that provide resistance to IGSCC,

such as solution heat treatment and stress improvement processes. LRA Section B.2.1.7 states 

that this program implements the program delineated in NUREG-0313, Revision 2, and in 

GL 88-01 and its Supplement 1. 
3-25

During the audit, the staff noted that the applicant’s ISI program plan indicates that the following 

welds of LGS Units 1 and 2 are made of Alloy 182 with Alloy 182 weld butter: (1) recirculation 

outlet nozzle to safe-end welds for Loops A and B, (2) jet pump instrumentation nozzle to 

safe-end welds for Loops A and B, and (3) control rod drive (CRD) return nozzle-to-cap welds. 

Based on the guidance in GL 88-01, Attachment A, “Staff Position on Materials,” the Alloy 182 

welds of LGS Units 1 and 2 are not resistant to IGSCC. In addition, the applicant’s ISI program 

plan indicates that ultrasonic examinations of Alloy 182 reactor pressure vessel (RPV) nozzle to

safe-end welds (i.e., welds incorporating Alloy 182 welds and/or weld butters) at several BWR 

facilities have resulted in the detection of cracking, which appears to have initiated as IGSCC in 

the Alloy 182 weld butter.

During the audit of the onsite documentation, the staff also noted that the Alloy 182 welds of 

LGS Unit 1 are categorized to IGSCC Category C, consistent with the GL 88-01 guidance that 

Alloy 182 is not a resistant material. By contrast, the absence of Alloy 182 welds in the 

applicant’s list for the IGSCC Category-B-through-G welds for LGS Unit 2 suggests that these 

welds are categorized to IGSCC Category A (resistant material), inconsistent with GL 88-01. 

The IGSCC categories of the welds in the BWR Stress Corrosion Cracking program are used to 

determine the inspection extent and frequency in accordance with GL 88-01 and BWRVIP-75-A. 

Therefore, the staff needed clarification for the following items about the Alloy 182 welds of LGS 

Unit 2: the proper IGSCC categories of these welds; the basis of the applicant’s categorization 

of these welds; and consistency of the applicant’s categorization with the guidance in GL 88-01 

and the IGSCC categorization of the LGS Unit 1, Alloy 182 welds. 

By letter dated November 18, 2011, the staff issued RAI B.2.1.7-1 requesting the applicant to 

describe the IGSCC categories of the LGS Unit 2 Alloy 182 welds listed in the applicant’s ISI

plan. The staff also requested the applicant to provide the basis for the applicant’s IGSCC 

categorization of these Unit 2, Alloy 182 welds. The staff further requested that as part of the 

response, if any of these LGS Unit 2 Alloy 182 welds are categorized as IGSCC Category A, the 

applicant clarify why the weld is categorized as a resistant weld, inconsistent with the guidance 

in GL 88-01 and the weld categorization of the LGS Unit 1 Alloy 182 welds to IGSCC 

Category C.

In its response, provided by letter dated December 7, 2011, the applicant stated that the LGS 

Units 1 and 2 Alloy 182 welds were listed within the procedure for augmented ISI of Alloy 182

nozzle weldments. The applicant also indicated that during the AMP audit, the weld 

descriptions provided in this procedure were incorrect for five LGS Unit 2 welds and a CAP 

issue report has been initiated to correct this error on the weld description in this procedure. 

The applicant further clarified that the following five welds of LGS Unit 2 had an Alloy 82 inlay 

installed over the Alloy 182 weld/weld-butter before initial power operations, such that the 

Alloy 182 material has not been in contact with reactor coolant: Welds VRR-2RS-2A N1A, 

VRR-2RS-2B N1B, RPV-2IN N8A, RPV-2IN N8B, and RPV-2IN N9. In addition, the applicant 

clarified that these welds were correctly classified as IGSCC Category A in accordance with 

NUREG-0313, Revision 2. The applicant confirmed that IGSCC Category A, assigned to these 

welds, is appropriate since the Alloy 82 inlay material is considered resistant to IGSCC and was 

applied on these welds to prevent reactor coolant from contacting the Alloy 182 material. The 

applicant also stated that all LGS Units 1 and 2 Alloy 182 welds are categorized consistent with 

GL 88-01 and NUREG-0313, Revision 2, as described in its response. The staff finds the 

applicant’s response acceptable because the applicant clarified and confirmed that the five 

welds made of Alloy 182 material have Alloy 82 inlay, which is classified as IGSCC Category A 
3-26

(resistant material), consistent with the guidance in GL 88-01, and the inlays were applied on 

these welds before the start of the initial power operation. The staff’s concern described in 

RAI B.2.1.7-1 is resolved. 

The “scope of program” program element of GALL Report AMP XI.M7 states that the program is 

applicable to all BWR piping and piping welds made of austenitic stainless steel and nickel alloy 

that are 4 inches or larger in nominal diameter containing reactor coolant at a temperature 

above 93° C (200 °F) during power operation, regardless of Code classification. In comparison, 

LRA Section B.2.1.7 states that the BWR Stress Corrosion Cracking program manages IGSCC 

in reactor coolant pressure boundary (RCPB) piping and piping components made of stainless 

steel and nickel-based alloy in a reactor coolant environment. In addition, LRA Table 3.2.1, 

item 3.2.1-54 indicates that the GALL Report recommends the BWR Stress Corrosion Cracking 

program to manage cracking caused by SCC and IGSCC of stainless steel piping, piping 

components, and piping elements exposed to treated water greater than 60° C (140 °F). The 

staff also noted that LRA Table 3.2.1, item 3.2.1-54 is for the ESF. However, LRA Table 3.1.2-1 

and related information in the LRA indicate that the applicant credited LRA Table 3.2.1, 

item 3.2.1-54 to manage the aging effect of RCPB components only. 

During the audit, the staff further noted that the applicant’s weld selection table for ISI indicates 

that the applicant’s program includes two ASME Code Class 2 welds associated with valves in 

the reactor water cleanup (RWCU) system of LGS Unit 1. One of the welds is IGSCC 

Category B and the other weld is IGSCC Category C.

In comparison, the LRA does not clearly address whether the scope of the applicant’s program 

includes piping and piping welds regardless of ASME Code classification, consistent with the 

GALL Report recommendations. The staff noted that the LRA includes the RCPB in the 

program scope; however, the LRA does not clearly address whether the scope of the program 

includes non-Class-1 piping and its associated welds. In addition, the staff noted that RWCU 

system piping and piping welds outboard of the second containment isolation valves are 

included in the scope of GALL Report AMP XI.M25, “BWR Reactor Water Cleanup System,”

while RWCU system piping and piping welds inboard of the second containment isolation valves 

are included in the BWR Stress Corrosion program. Therefore, the staff needed to further 

clarify if the LGS Unit 1 ASME Code Class 2 welds, categorized as IGSCC Category B and C, 

are located inboard of the second containment isolation valves.

By letter dated January 17, 2012, the staff issued RAI B.2.1.7-2 requesting the applicant to 

describe if the scope of applicant’s program includes BWR piping and piping welds made of 

austenitic stainless steel and nickel alloy regardless of ASME Code classification, consistent 

with the GALL Report recommendations. The staff also requested that if the scope of the 

applicant’s program does not include non-Class-1 piping and piping welds, the applicant justify 

why non-Class-1 piping and piping welds can be excluded from the program scope. In addition, 

the staff requested that the applicant revise LRA Section A.2.1.7 (UFSAR supplement) to clarify 

that the scope of the program includes the relevant piping and piping welds regardless of 

Code classification. The staff further requested that the applicant clarify if the ASME 

Code Class 2 welds associated with the valves in the LGS Unit 1 RWCU system are located 

inboard of the second containment isolation valves (i.e., “inboard” valves). The staff requested 

that if these ASME Code Class 2 welds are associated with inboard valves, the applicant clarify 

why its statement that the program manages the aging effect of the RCPB components is 

consistent with the inclusion of these ASME Code Class 2 welds in the program.
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In its response, provided by letter dated February 15, 2012, the applicant indicated that the two 

ASME Code Class 2 welds in the RWCU system are located outboard of the second 

containment isolation valve, for which no augmented inspection is required. The applicant 

further indicated that since these two welds had been incorrectly identified as the welds that 

should be included in the inspection in accordance with GL 88-01, a CAP issue report was 

issued in August 2010, to correctly identify that these welds are not within the augmented

inspections specified in GL 88-01. The staff found this portion of the applicant’s response 

adequate because it clarified the outboard locations of the welds in the RWCU system, and the 

GALL Report recommends GALL Report AMP XI.M25, “BWR Reactor Water Cleanup System,”

to manage the aging effect of these outboard welds rather than the BWR Stress Corrosion 

Cracking program.

In its response regarding program scope, the applicant confirmed that the BWR Stress 

Corrosion Cracking program includes BWR piping and piping welds made of austenitic stainless 

steel and nickel alloy regardless of ASME Code classification. The applicant also stated that 

the determination of program scope included screening of all BWR piping and piping welds 

made of austenitic stainless steel that are 4 inches or greater in nominal diameter containing 

reactor coolant at a temperature greater than 93° C (200 °F) during power operation, regardless 

of Code classification. The applicant further stated that this screening identified only ASME 

Code Class 1 piping as within the scope of the BWR Stress Corrosion Cracking program. The 

staff found that this portion of the applicant’s response is acceptable because the applicant 

confirmed that the scope of the program includes all relevant piping and piping welds regardless 

of ASME Code classification, consistent with the GALL Report, and the applicant’s screening of 

the welds in accordance with the GALL Report identified only RCPB welds as the welds to be 

inspected in the program.

However, the staff noted that the revised UFSAR supplement in the applicant’s response states 

that the BWR Stress Corrosion Cracking program is an existing augmented ISI program that 

manages IGSCC in reactor coolant pressure boundary piping and piping components made of 

stainless steel and nickel-based alloy, regardless of Code classification, as delineated in 

NUREG-0313, Revision 2, and GL 88-01 and its Supplement 1. In its review, the staff finds that 

the applicant’s revision to the UFSAR supplement, which includes the reference to “reactor 

coolant pressure boundary piping,” is in conflict with the applicant’s response indicating that the 

program includes all relevant piping regardless of ASME Code classification. Therefore, this 

part specifically related to the UFSAR supplement is further evaluated in the evaluation section 

for the UFSAR supplement as described below. Based on this review, the staff’s concern 

described in RAI B.2.1.7-2 is resolved, except for aspects related to the applicant’s revision to 

the UFSAR supplement. 

The “detection of aging effect” program element of GALL Report AMP XI.M7 states that the 

extent, method, and schedule of the inspection and test techniques delineated in GL 88-01 or 

BWRVIP-75-A are designed to maintain structural integrity and ensure that aging effects are 

discovered and repaired before the loss of intended function of the component. The GALL 

Report also states that modifications to the extent and schedule of inspection in GL 88-01 are 

allowed in accordance with the inspection guidance in approved BWRVIP-75-A. The LRA 

further states that welds classified as Category A have been subsumed into the RI-ISI program 

in accordance with staff-approved EPRI Topical Report TR-112657, Revision B-A, Final Report, 

“Revised Risk-Informed Inservice Inspection Evaluation Procedure,” issued December 1999.
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Although the applicant indicated that the program uses a staff-approved methodology described 

in EPRI TR-112657, Revision B-A, to subsume IGSCC Category A welds in RI-ISI, the staff 

noted that the relief request was approved for the applicant’s third 10-year inservice inspection 

interval, which is scheduled to end on January 31, 2017. The staff noted that the applicant 

would need to get NRC approval for using this risk-informed method, for the period of extended 

operation, as an alternative to the ASME Code Section XI inservice inspection requirements for 

piping and the inspection requirements of GL 88-01. Therefore, the staff needed to further 

clarify what extent, method, and schedule the applicant would use to inspect the piping and 

piping components in the scope of the BWR Stress Corrosion Cracking program in the case the 

applicant could not continue to get NRC approval for using the risk-informed method described 

in EPRI TR-112657, Revision B-A. The staff also found that the UFSAR supplement for this 

program should be further evaluated in terms of its consistency with the program on the use of 

the risk-informed method. 

By letter dated January 17, 2012, the staff issued RAI B.2.1.7-3 requesting the applicant to

describe the extent, method, and schedule that the applicant would use to inspect the piping 

and piping components in the scope of the BWR Stress Corrosion Cracking program in the case 

the applicant could not continue to get NRC approval for using the risk-informed method 

described in EPRI TR-112657, Revision B-A. The staff also requested that the applicant revise 

LRA Section A.2.1.7 (UFSAR supplement), consistent with the applicant’s response on the need 

to remove the applicant’s reference to the risk-informed ISI from the UFSAR supplement. 

In its response, provided by letter dated February 15, 2012, the applicant clarified that in the 

event that NRC approval is not provided to use the risk-informed methodology described in 

EPRI TR-112657, Revision B-A, for scheduling inspections for IGSCC Category A welds, the 

extent and schedule of the inspection and test techniques would be in accordance with the 

inspection guidance in approved BWRVIP-75-A. The applicant also stated that the inspection 

method is not affected by use of the risk-informed methodology and is in accordance with 

GL 88-01 and NUREG-0313, Revision 2. In addition, the applicant provided the revision to the 

UFSAR supplement, consistent with the applicant’s response. The staff finds the applicant’s 

response acceptable because the applicant confirmed that in the case the applicant cannot get 

NRC approval for using the risk-informed inspection methodology, the extent, method, and 

schedule of the inspections would be consistent with staff-approved guidance, and the 

applicant’s revisions to the UFSAR supplement, which removed a reference to the risk-informed 

methodology, is consistent with the acceptable response. The staff’s concern described in 

RAI B.2.1.7-3 is resolved.

Based on its audit, and review of the applicant’s responses to RAIs B.2.1.7-1, B.2.1.7-2,

and B.2.1.7-3 of the BWR Stress Corrosion Cracking program, the staff finds that program 

elements 1-6 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 operating experience related to the 

BWR Stress Corrosion Cracking program. The LRA states that during the LGS Unit 1 1989 

refueling outage, a volumetric UT identified a cracking indication in a reactor recirculation nozzle

to safe-end weld that resulted in this weld being classified as IGSCC Category F in accordance 

with GL 88-01 and NUREG-0313, Revision 2 guidelines. The applicant also indicated that 

mechanical stress improvement process (MSIP) was performed on this weld in 1992 and the 

weld was re-examined during each of the following four refueling outages in accordance with 

GL 88-01 guidance. The applicant further indicated that since none of these re-examinations 
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indicated crack growth, the weld was upgraded to Category E and examination of this weld has 

continued during every other refueling outage in accordance with BWRVIP-75-A guidance.

The applicant stated that this example illustrates how implementation of industry operating 

experience from GL 88-01 and volumetric ultrasonic testing was applied to identify a cracking 

indication in a susceptible RCPB weld. Furthermore, this example demonstrates effective use 

of industry recommendations to apply MSIP on a weld with a crack indication as a mitigating 

action to reduce the stresses in the weld and probability for continued SCC. The applicant also 

stated that this example demonstrates how the guidelines in GL 88-01, NUREG-0313, and 

BWRVIP-75-A are applied effectively to classify a weld with cracking indication and to 

appropriately schedule and perform examinations to confirm that the condition of the weld is 

acceptable for continued service. 

LRA Section B.2.1.7 states that NUREG-0313, Revision 2, and GL 88-01 provide 

recommendations to perform MSIP on welds that were susceptible to SCC to reduce the tensile 

stresses and the susceptibility to SCC. The applicant also indicated that MSIP was performed 

on LGS Unit 1 in 1992 and 1994 on 23 welds within the scope of the GL 88-01 that had no

evidence of prior cracking and on one weld that had indications of prior cracking. The applicant 

further indicated that MSIP was performed on LGS Unit 2 before reactor operations on 18 welds 

and the augmented ISIs to examine SCC has been in place since 1988, in accordance with 

GL 88-01 and BWRVIP-75-A. In addition, the applicant indicated that the inspections have not 

identified any indications of cracking in susceptible welds following the application of MSIP to 

those welds determined to be most susceptible.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicant reviewed applicable aging effects and industry and 

plant-specific operating experience. 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.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.7, as amended by letter dated February 15, 2012, 

provides the UFSAR supplement for the BWR Stress Corrosion Cracking program. The staff 

reviewed this UFSAR supplement and needed further clarification on the scope of the program 

described in the UFSAR supplement. The staff noted that the licensing basis for this program 

for the period of extended operation may not be adequate if the applicant does not provide 

sufficient information and clarification on its UFSAR supplement.

As described above in the staff safety evaluation regarding RAI B.2.1.7-3, the applicant, in its 

letter dated February 15, 2012, removed reference to the risk-informed inspection methodology 

from the UFSAR supplement. The staff finds this revision acceptable because the use of the 

risk-informed methodology is granted only for a specific inspection interval and needs additional 

reviews and NRC approval for continued use.
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As addressed above in the staff’s safety evaluation regarding RAI B.2.1.7-2, the staff requested 

the applicant to describe whether the scope of the applicant’s program includes BWR piping and 

piping welds made of austenitic stainless steel and nickel alloy regardless of ASME 

Code classification, consistent with the GALL Report. In the same RAI, the staff also requested 

that the applicant revise LRA Section A.2.1.7 (UFSAR supplement) appropriately to clarify that 

the scope of the program includes the relevant piping and piping welds regardless of ASME 

Code classification. 

In its letter dated February 15, 2012, the applicant clarified that the BWR Stress Corrosion 

Cracking program includes BWR piping and piping welds made of austenitic stainless steel and 

nickel alloy regardless of ASME Code classification. The applicant also stated that 

determination of program scope included screening of all BWR piping and piping welds made of 

austenitic stainless steel that are 4 inches or greater in nominal diameter containing reactor 

coolant at a temperature greater than 93° C (200 °F) during power operation, regardless of 

Code classification. However, in its review, the staff found that the applicant’s revision to the 

UFSAR supplement, which includes reference to “reactor coolant pressure boundary piping,”

conflicts with the applicant’s response, indicating that the program includes all relevant piping 

regardless of Code classification. By letter dated April 5, 2012, the staff issued RAI B.2.1.7-2.1 

requesting the applicant to justify why its revised UFSAR supplement includes “reactor coolant 

pressure boundary piping,” which is inconsistent with other text in the RAI response indicating 

that the program includes relevant piping and piping welds regardless of Code classification. 

In its response, provided by letter dated April 13, 2012, the applicant revised the UFSAR 

supplement (LRA Section A.2.1.7) to include “relevant piping and piping welds” without a 

reference to “reactor coolant pressure boundary piping and piping components,” consistent with 

the program description provided in its response to RAI B.2.1.7-2. The staff reviewed the 

applicant’s revision to the UFSAR supplement and found the response acceptable because the 

revised UFSAR is consistent with the program scope of GALL Report AMP XI.M7.

The staff finds that the information in the UFSAR supplement, as amended by letters dated 

February 15, 2012, and April 13, 2012, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the BWR Stress Corrosion Cracking 

program, the staff concludes that the program elements, for which the applicant claimed 

consistency with the GALL Report, are consistent with the corresponding program elements of 

GALL Report AMP XI.M7. 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).

3.0.3.1.7 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.” This program is a condition monitoring and mitigation program that manages the 

effects of cracking of the reactor vessel instrumentation penetrations, and CRD housing and 

in-core-monitoring housing penetrations exposed to reactor coolant through water chemistry 

and ISIs. It also incorporates the inspection and evaluation recommendations of BWRVIP-49-A, 
3-31

“Instrument Penetration Inspection and Flaw Evaluation Guidelines,” BWRVIP-47-A, “BWR 

Lower Plenum Inspection and Flaw Evaluation Guidelines,” and the water chemistry 

recommendations as described in the Water Chemistry program. Each refueling outage, a 

visual inspection (VT-2) is performed on these components during the system leakage test in 

accordance with the controlling edition of ASME Code, Section XI. BWRVIP-27-A states that it 

does not apply to plants such as LGS, in which standby liquid control (SLC) injects by CS

system piping.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M8. For the “parameters monitored 

or inspected” program element, the staff determined the need for additional information, which 

resulted in the issuance of RAIs as discussed below.

The “parameters monitored or inspected” program element of GALL Report AMP XI.M8 states 

that it manages the effects of cracking caused by SCC and IGSCC on the intended function of 

the BWR instrumentation nozzles, CRD housing and in-core monitoring housing (ICMH) 

penetrations, and BWR SLC nozzles/core ΔP nozzles. It also states that the program 

accomplishes this aging management by inspecting for cracks in accordance with the 

staff approved BWRVIP guidelines (e.g., BWRVIP-47-A) and the requirements of ASME Code, 

Section XI, Table IWB 2500-1.

Section 3.2.5, “Other Inspections,” of BWRVIP-47-A indicates that removing or dismantling 

internal components for the purpose of performing inspections is not warranted to ensure safe 

operation; however, on occasion, utilities may have access to the lower plenum because of

maintenance activities that are not part of normal refueling outage activities. It also states that 

in such cases utilities will perform a visual inspection to the extent practical and the results of 

the inspection will be reported to the BWRVIP, which will report these results to the NRC.

The “parameters monitored or inspected” program element of the applicant’s program basis 

document states that the program monitors the effects of cracking caused by SCC and IGSCC 

by performing inspections of the instrumentation nozzles, CRD housing, and ICMH penetrations 

as part of the ISI program. However, the program basis document states that currently, 

BWRVIP-47-A does not require additional inspections of the CRD housing and ICMH 

penetrations. Therefore, it is not clear to the staff if the applicant’s basis document for the BWR 

Penetrations program is consistent with Section 3.2.5 of BWRVIP-47-A in terms of the inclusion 

of the additional inspections.

By letter dated November 18, 2011, the staff issued RAI B.2.1.8-1 requesting the applicant to

justify why its program indicates that BWRVIP-47-A does not require additional inspections for 

the CRD housing and ICMH penetrations. In addition, the RAI requested the applicant describe 

any results of the inspections performed in accordance with Section 3.2.5 of BWRVIP-47-A.

In its response, provided by letter dated December 7, 2011, the applicant confirmed that it 

performs the inspections described in Section 3.2.5 of BWRVIP-47-A as part of its inspections 

for reactor vessel internals (RVIs) and that the inspections are included in the BWR 

Penetrations program. The applicant also indicated that the program basis document was 

revised to delete the sentence indicating that currently the BWRVIP-47-A does not require 

additional inspections of the CRD housing and ICMH penetrations. In addition, the applicant 
3-32

discussed the following inspection results for the lower plenum components, which were 

performed in accordance with BWRVIP-47-A.

During the LGS Unit 2, refueling outage in 2007, nine CRD housing-to-stub-tube welds were 

examined when they were accessible during maintenance of jet pumps and no recordable 

indications were identified as described in a letter from C. Mudrick to the NRC, “LGS Unit 2

Summary Report for Inservice Inspections (2R09),” dated July 3, 2007. In addition, during the 

LGS Unit 1, refueling outage in 2010, eight CRD housing-to-stub-tube welds, eight CRD 

stub-tube-to-reactor-pressurevessel (RPV) welds, and four ICMH-to-RPV penetration welds 

were examined when they were made accessible during cleaning of the RPV bottom head 

drain. No recordable indications were identified as described in letter from W. Maguire to the 

NRC, “LGS Unit 1 Summary Report for Inservice Inspections (1R13),” dated July 9, 2010. The 

applicant stated that these results confirm that the inspection results are consistent with the 

conclusion that the aging effects will be adequately managed.

The staff finds the applicant’s response to RAI B.2.1.8-1 acceptable because the results of the 

applicant’s inspections performed in accordance with BWRVIP-47-A did not identify any 

recordable indication for the lower core plenum penetrations and the applicant’s program basis 

document has been revised to delete the incorrect statement about the additional inspections of 

BWRVIP-47-A. The staff’s concern described in RAI B.2.1.8-1 is resolved.

In its review, the staff noted that Section 3.2, “BWRVIP Inspection Guidelines,” of BWRVIP-47-A 

indicates that if there is bottom head access as a result of normal refueling outage activities, 

ASME Code, Section XI, requires visual inspection of accessible areas in the region to be 

performed. In comparison, the applicant’s onsite procedure indicates that on April 30, 2008, the 

staff approved ISI program relief request such that the use of the BWRVIP Inspection and 

Evaluation Guidelines was authorized in place of ASME Code-required inspections and flaw 

evaluations for ASME Code, Section XI, B-N-1 and B-N-2 category components. The 

applicant’s procedure further indicated that this relief request is applied to “CRD stub tube to 

vessel attachments (inaccessible)” and “CRD housing to stub tube welds (inaccessible).” 

However, Attachment 1 to the staff’s safety evaluation, dated April 30, 2008, of the relief request 

does not list CRD stub tubes or associated welds as components for which the relief request 

was approved. Therefore, the staff needed to clarify why the relief request is applied to the 

CRD stub tubes and associated welds and when the CRD stub-tube-to-vessel attachment welds 

and CRD housing-to-stub-tube welds are accessible for inspections.

By letter dated November 18, 2011, the staff issued RAI B.2.1.8-2 requesting the applicant to 

clarify the discrepancy between its onsite procedure and the approved relief request and when 

the welds described above are accessible for inspections. 

In its response, provided by letter dated December 7, 2011, the applicant stated that the CRD 

stub-tube-to-vessel welds and CRD housing-to-stub-tube welds are located in the lower plenum 

region of the RPV and are only accessible for inspections during certain maintenance activities 

that are not part of normal refueling activities. Access to the lower plenum region of the RPV 

can be through disassembly of jet pumps or through the core plate following removal of control 

rod guide tubes. Examples of the types of maintenance activities that result in access to these 

components to perform inspections include maintenance to the jet pumps and cleaning of the 

RPV bottom head drain. The applicant indicated that its response to RAI B.2.1.8-1 includes 

recent examples of inspections performed on the CRD stub-tube-to-vessel welds, CRD 
3-33

housing-to-stub-tube welds, and ICMH-to-vessel welds when these components were made 

accessible by these maintenance activities. As described in the response to RAI B.2.1.8-1, the 

applicant confirmed that the results of the applicant’s inspections performed in accordance with 

BWRVIP-47-A identified no recordable indications for these lower plenum penetration 

components.

In its response, the applicant also indicated that the implementing procedure was found to be 

incorrect in stating that the relief request applies to examination of the CRD stub-tube-to-vessel 

welds and CRD housing-to-stub-tube welds. In addition, the applicant stated that its procedure 

has been revised to delete the reference to this relief request relative to these welds.

The staff finds the applicant’s response to RAI B.2.1.8-2 acceptable because the applicant 

confirmed that the implementing procedure was revised to clarify that its relief request is not 

applied to these lower plenum penetration welds and the lower plenum penetration components 

are only accessible for inspections during certain maintenance activities that are not part of 

normal refueling activities.

Based on its audit, and review of the applicant’s responses to RAIs B.2.1.8-1 and B.2.1.8-2 of 

the BWR Penetrations program, the staff finds that program elements 1-6 for which the 

applicant claimed consistency with the GALL Report are consistent with the corresponding 

program elements of GALL Report AMP XI.M8.

Review of License Renewal Applicant Action Items: In the staff’s safety evaluation, dated 

September 1, 1999, for BWRVIP-49, “BWR Vessel and Internals Project, Instrument Penetration 

Inspection and Flaw Evaluation Guidelines,” three license renewal applicant action items (AAIs) 

were issued in the report. In addition, the staff’s safety evaluation, dated December 7, 2000, 

issued four licensee renewal AAIs for BWRVIP-47, “BWR Vessel and Internals Project, BWR 

Lower Plenum Inspection and Flaw Evaluation Guidelines (BWRVIP-47).” Three of the four 

AAIs for BWRVIP-47 are essentially identical to the three action items for BWRVIP-49 as 

summarized below. The fourth AAI specific to BWRVIP-47 follows these three AAI:

AAI #1: The license renewal applicant is to verify that its plant is bounded by the 

BWRVIP report. Further, the renewal applicant is to commit to programs 

described as necessary in the BWRVIP report to manage the effects of aging on 

the functionality of the reactor vessel components addressed in the BWRVIP 

report during the period of extended operation. License renewal applicants will 

be responsible for describing any such commitments and identifying how such 

commitments will be controlled. Any deviations from the AMPs within the 

BWRVIP report described as necessary to manage the effects of aging during 

the period of extended operation and to maintain the functionality of the reactor 

vessel components or other information presented in the report, such as 

materials of construction, will have to be identified by the renewal applicant and 

evaluated on a plant-specific basis in accordance with 10 CFR 54.21(a)(3) and 

(c)(1).

AAI #2: 10 CFR 54.21(d) requires that a UFSAR supplement for the facility 

contain a summary description of the programs and activities for managing the 

effects of aging and the evaluation of TLAA (time-limited aging analysis) for the 

period of extended operation. Those applicants for license renewal referencing 

the BWRVIP report for the reactor vessel components shall ensure that the 
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programs and activities specified as necessary in the BWRVIP document are 

summarily described in the UFSAR supplement.

AAI #3: 10 CFR 54.22 requires that each license renewal application include any 

Technical Specification changes (and the justification for the changes) or 

additions necessary to manage the effects of aging during the period of extended 

operation as part of the license renewal application. Those license renewal 

applicants referencing the BWRVIP report for the reactor vessel components 

shall ensure that the inspection strategy described in the BWRVIP report does 

not conflict or result in any changes to their Technical Specifications. If technical 

specification changes do result, then the applicant should ensure that those 

changes are included in its license renewal application.

In addition to these three action items for BWRVIP-49 and BWRVIP-47, the staff safety 

evaluation for the BWRVIP-47 report issues the fourth license renewal action item as follows: 

AAI #4: Due to fatigue of the subject safety-related components, applicants 

referencing the BWRVIP-47 report for license renewal should identify and 

evaluate the projected cumulative usage factor (CUF) as a potential TLAA issue. 

This issue is discussed in more detail in Section 3.5 of BWRVIP-47.

As discussed in SER Section 4.1.2.1.2, the staff issued RAI BWRVIP-1, by letter dated 

January 17, 2012, requesting the applicant to submit the necessary information for each AAI in 

the BWRVIP reports that are applicable to the LGS CLB. By letter dated February 15, 2012, the 

applicant responded to RAI BWRVIP-1, which addresses the necessary information and 

revisions to the LRA for license renewal AAIs in all applicable BWRVIP reports that are credited 

for aging management. In its response, the applicant revised LRA Appendix C, “Response to 

BWRVIP License Renewal Applicant Action Items.” 

The staff reviewed the applicant’s response to AAI #1, which states that the BWRVIP reports 

applicable to the applicant have been reviewed and the applicant’s AMP has been confirmed to 

be bounded by the reports. The applicant also stated in its response that it committed to 

programs described as necessary in the BWRVIP reports to manage the effects of aging during 

the period of extended operations. 

The staff confirmed that LRA Appendix A describes the applicant’s UFSAR supplement and 

adequately identifies staff-approved BWRVIP-47-A and BWRVIP-49-A as the industry 

guidelines to be incorporated in the BWR Penetration program. The applicant confirmed that 

BWRVIP-47-A and BWRVIP-49-A bound the BWR Penetrations program. In addition, the 

applicant stated that if, upon review of a BWRVIP approved guideline, it determines that known 

deviations to full compliance are warranted, the NRC will be notified of the deviation within 

45 days of the receipt of NRC final approval of the guideline, and commitments are 

administratively controlled in accordance with the requirements of Appendix B to 

10 CFR Part 50. The staff finds that the applicant has adequately addressed Action Item #1 

because it confirmed that its program is bounded by BWRVIP-47-A and BWRVIP-49-A and the 

program does not have any other commitment than the ongoing implementation of the existing 

BWR Penetrations program, which is administratively controlled in accordance with Appendix B 

to 10 CFR Part 50.
3-35

The staff reviewed the applicant’s response to AAI #2, which states the UFSAR supplement is 

included in LRA Appendix A and contains a summary description of the programs and activities 

specified as necessary for managing the effects of aging per the BWRVIP reports. The staff 

finds that the UFSAR supplement for the BWR Penetrations program is sufficient to summarize 

the program activities consistent with the SRP-LR and the GALL Report, including the 

inspections and flaw evaluation addressed in BWRVIP-47-A and BWRVIP-49-A. Therefore, the 

applicant has adequately addressed AAI #2 for the BWRVIP reports by providing a sufficient 

UFSAR summary description for the BWR Penetrations program.

The staff reviewed the applicant’s response to AAI #3, which states that there are no technical 

specification changes identified to meet the recommendations of the BWRVIP reports during the 

period of extended operation. The staff confirmed that LRA Appendices C and D indicate that 

no technical specification changes or additions were identified as necessary to manage the 

effects of aging during the period of extended operation. The staff finds the applicant’s 

response to AAI #3 acceptable because the applicant confirmed that no change to the technical 

specifications is needed to manage the aging effects in accordance with the BWRVIP reports. 

The staff reviewed the applicant’s response to AAI #4 specific to BWRVIP-47, which states that 

fatigue usage is considered a time-limited aging analysis (TLAA) for RVIs, including lower 

plenum components. The staff noted that Section 3.5 of the staff safety evaluation for 

BWRVIP-47 indicates that some plants may have lower plenum pressure boundary component 

fatigue CUF greater than the ASME Code design limit of 1.0 for the license renewal term and a 

plant-specific description of how this issue will be addressed is needed for these plants. The 

staff noted that the applicant’s fatigue TLAA of the lower plenum penetrations (i.e., CRD 

housing and in-core monitor penetrations) are addressed in LRA Section 4.3.3 and LRA 

Table 4.3.3-1. In addition, the identification of the fatigue TLAA of these components is 

addressed in the applicant’s AMR results described in LRA Table 3.1.2-2 for RPV components. 

The staff finds the applicant’s response acceptable because the LRA identifies and includes the 

fatigue TLAA of the lower plenum penetration components, consistent with BWRVIP-47-A.

Operating Experience. LRA Section B.2.1.8 summarizes operating experience related to the 

BWR Penetrations program. The applicant stated that, as required by the ASME Code, 

Section XI, an RCPB system leakage test is performed on the reactor vessel instrument 

penetrations and CRD housing and ICMH penetrations for each refueling outage in accordance 

with the ISI program. The applicant also stated that a review of the inspection results from the 

last two refueling outages for both Units (2007, 2008, 2009, and 2010) indicates that there have 

been no leaks identified for these components. In addition, as part of its response to 

RAI B.2.1.8-1, the applicant confirmed that the results of the visual inspections performed in 

accordance with BWRVIP-47-A, Section 3.2.5, identified no recordable indications for the lower 

core plenum penetration components.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicant reviewed the aging effects and industry and plant-specific 

operating experience. 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 found no operating experience to indicate that the applicant’s program would 

not be effective in adequately managing aging effects during the period of extended operation.
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Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.8 provides the UFSAR supplement for the BWR 

Penetrations 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 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 BWR Penetrations 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).

3.0.3.1.8 Flow-Accelerated Corrosion

Summary of Technical Information in the Application. LRA Section B.2.1.10 describes the 

existing Flow-Accelerated Corrosion program as consistent with GALL Report AMP XI.M17, 

“Flow-Accelerated Corrosion.” The program predicts, detects, and monitors wall thinning 

caused by flow-accelerated corrosion of piping components and heat exchangers in steam and 

treated water environments. The program is based on EPRI guidelines in NSAC-202L, 

Revision 3, “Recommendations for an Effective Flow Accelerated Corrosion Program,” and uses 

a predictive computer code, CHECWORKS, to analytically determine critical locations to 

inspect. Inspections are performed using ultrasonic, visual, or other approved testing 

techniques capable of detecting wall thinning. For each inspected component, the program 

uses a PC-based computer program called FAC (flow-accelerated corrosion) Manager, in 

conjunction with CHECWORKS, to calculate component wear rate, projected thickness, and 

remaining life. For components with a remaining life of less than one operating cycle, corrective 

actions, such as repair, replacement, or reevaluation, are implemented.

Staff Evaluation. During the audit, the staff reviewed the applicant’s claim of consistency with 

the GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M17. Based on its audit of the 

Flow-Accelerated Corrosion program, the staff finds that program elements 1-6 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. The LRA provided a summary of the recent inspections, 

which included 102 inspections for LGS Unit 1 in 2010, and 83 inspections for LGS Unit 2 

in 2009. The LRA also described additional inspections performed during outages. These 

inspections led to replacement of selected large- and small-bore piping with material resistant to 

flow-accelerated corrosion containing 1.25 percent chromium. In addition, the LRA described 
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the evaluation of industry operating experience related to feedwater heater shell leakage in 

establishing feedwater heater shell inspection plans. The LRA stated that these examples 

provided objective evidence that the Flow-Accelerated Corrosion program has been effective in 

ensuring that the intended functions are being maintained consistent with the CLB.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicant reviewed the applicable aging effects and industry and 

plant-specific operating experience. 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 found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.10 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. 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 Flow-Accelerated Corrosion program, 

the staff concludes that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M17. 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).

3.0.3.1.9 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 GALL Report AMP XI.M24, 

“Compressed Air Monitoring.” The program is based on the applicant’s response for LGS to 

GL 88-14, “Instrument Air Supply Problems.” The LRA states that the program manages loss of 

material in piping, piping components, piping elements, and valve bodies in air and gas 

environments. The LRA also states that the program includes periodic testing and inspection of 

the compressed air, primary containment instrument gas (PCIG), and traversing in-core probe 

systems. Program activities include air quality monitoring and trending, preventive 

maintenance, and condition monitoring measures to manage the effects of aging. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M24.
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For the “monitoring and trending” program element, the staff determined the need for additional 

information, which resulted in the issuance of an RAI, as discussed below.

The “monitoring and trending” program element in GALL Report AMP XI.M24 recommends that 

daily readings of system dew point be recorded and trended. However, during its audit, the staff 

found that the applicant’s program basis document for the Compressed Air Monitoring program 

states that the instrument air system dew point is continuously monitored and alarmed, 

inspected weekly, and recorded quarterly. The basis document also states that the primary 

containment instrument gas system’s dryer desiccant outlet moisture indicator is confirmed

weekly. Additionally, the program basis document states that trending is accomplished by 

satisfactory completion of the surveillances and quarterly recorded values and issue reports are 

initiated for alarms, test, or inspection results that do not satisfy the established criteria. By 

letter dated January 17, 2010, the staff issued RAI B.2.1.15-1 requesting the applicant to: 

explain why weekly inspections and quarterly recording of the instrument air system dew point 

are sufficient to detect potentially unacceptable levels of moisture; explain why it was using a 

desiccant outlet moisture indicator for the PCIG system instead of monitoring dew point; explain 

why verifying the desiccant outlet moisture indicator on a weekly basis is sufficient to detect 

potentially unacceptable levels of moisture; and state whether prior data points are compared to 

current data points during trending, and, if not, state why the trending of data points will be 

sufficient to detect changes in air quality before degrading air quality affects the ability of the 

instrument air systems to meet their intended function(s).

In its response, provided by letter dated February 15, 2012, with regard to daily recordings and 

trending of the dew point, the applicant stated that the instrument air system is continuously 

monitored and alarmed in the main control room to ensure moisture content is within 

specifications. To supplement the continuous monitoring activity, operators inspect and verify 

that the instrument air dryer outlet dew point is within its required range on a weekly basis. The 

applicant also stated that in response to GL 88-14, it committed to verify instrument air quality at 

safety-related components each refueling outage, and that this verification validates the 

continuous and weekly inspection activities. The applicant concluded that the continuous 

monitoring and alarm system along with weekly operator inspections of the instrument air 

system dew point are sufficient to detect potentially unacceptable levels of moisture within 

components. The applicant further stated that system managers review system health 

parameters quarterly to monitor system performance and ensure early detection of equipment 

problems.

With regard to the desiccant outlet moisture indicator for the PCIG system, the applicant stated 

the system uses the desiccant dryer outlet moisture indicator to monitor moisture and operators 

inspect the moisture indicator weekly to verify that moisture content is in an acceptable range. 

The applicant justified the use of a moisture indicator in place of direct dew point monitoring as 

consistent with the American National Standards Institute (ANSI) ISA-S7.0.01 standard.

With regard to whether prior data points are compared to current data points during trending, 

the applicant stated that it will enhance its program to meet the guidance of ASME 

O/M-S/G-1998, Part 17, which is consistent with the GALL Report recommendations. In 

addition, the applicant revised LRA Sections A.2.1.15 and B.2.1.15, as well as 

Commitment No. 15, to add an enhancement to the Compressed Air Monitoring program to 

perform trending.
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The staff finds the applicant’s response acceptable because the applicant will continuously 

monitor the dew point (instrument air) and the desiccant dryer outlet (PCIG), which will alert the 

applicant to any potential moisture within the systems. Additionally, the applicant will perform 

weekly inspection activities to verify that moisture content is within the acceptable range. Lastly, 

the applicant has included in its UFSAR supplement a commitment (Commitment No. 15) to 

enhance the Compressed Air Monitoring program to perform periodic analysis and trending of 

air quality monitoring results. Trending of the data will reveal any adverse trends and the need 

for system attention. The staff’s concern described in RAI B.2.1.15-1 is resolved.

Enhancement. LRA Section B.2.1.15, as amended by letter dated February 15, 2012, states an 

enhancement to the “monitoring and trending” program element. In this enhancement, the 

applicant stated that it will perform periodic analysis and trending of air quality monitoring 

results. The staff reviewed this enhancement against the corresponding program element in 

GALL Report AMP XI.M24 and finds it acceptable because when it is implemented, the 

applicant’s program will be consistent with the GALL Report.

Based on its audit, and review of the applicant’s response to RAI B.2.1.15-1, of the Compressed 

Air Monitoring program, the staff finds that program elements 1-6 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 enhancement 

associated with the “monitoring and trending,” program element and finds that when 

implemented, the AMP will be 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. A summary of the four examples provided in the LRA is 

given below. 

(1) In February 2002, a low dew point alarm was received in the main control room. An 

issue report was generated following receipt of the alarm. As part of troubleshooting 

and investigation, a replacement moisture monitoring instrument was obtained and 

installed. During the shift following installation, multiple low dew point alarms were 

received and the dryer component continued to be monitored closely. During the 

subsequent monitoring, the trend of dew point continued to improve and the alarms 

cleared. Dew point was confirmed to be maintaining a value in the acceptable range.

(2) In February 2007, carbon steel drain lines from the backup service air compressor were 

identified to be in a rusted condition near their termination point. Evaluation determined 

that continued degradation of the drain lines was not acceptable, and the lines were 

scheduled for replacement with stainless steel lines. Replacement of the lines was 

subsequently completed. 

(3) In November 2005, the 2A instrument air compressor was noted to be making atypical 

noise. While the unit was operating within parameters, the intercooler pressure 

appeared to be fluctuating. The observer generated an issue report for followup 

investigation. The investigation determined that the recently performed surveillance 

capacity test was completed satisfactorily for the unit, but also confirmed that the 

unloader valve was chattering. The unit continued to function within parameters, but it 

was placed on an increased surveillance frequency as a precaution and the condition 

was corrected during the following annual minor overhaul.

(4) In June 2006, nuclear oversight performed an assessment of the scheduled 

maintenance activities package for the 1B instrument air compressor overhaul and 
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aftercooler cleaning and inspection. During the performance of the maintenance 

activities, the nuclear oversight review noted potential for improvement in safety and 

protection for both personnel and equipment. Actions were created to incorporate the 

improvements into future maintenance packages. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicant reviewed applicable aging effects and industry and 

plant-specific operating experience. 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 found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

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 against the recommended description for this type of program as described in 

SRP-LR Table 3.0-1 and noted that it does not credit the response to GL 88-14 and standards 

used as guidance for testing and monitoring air quality and moisture. 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 January 17, 2012, the 

staff issued RAI B.2.1.15-2 requesting the applicant to explain why it is not necessary to 

reference its response to GL 88-14 and standards, such as ISA-S7.0.1, which it uses for air 

quality testing in the UFSAR supplement, or to revise LRA Section A.2.1.15 to include key 

aspects of the program that provide guidance for testing and monitoring air quality and moisture.

In its response, provided by letter dated February 15, 2012, the applicant stated that it revised 

LRA Section A.2.1.15 to reference the GL 88-14 response per the guidance in the SRP, 

Table 3.0-1.

The staff finds the applicant’s response acceptable because it revised its description of the 

program in the UFSAR supplement to reference its response to GL 88-14. Therefore, the 

UFSAR supplement for the Compressed Air Monitoring program is consistent with the 

corresponding program description in SRP-LR Table 3.0-1. The staff’s concern described in 

RAI B.2.1.15-2 is resolved. The staff also noted that the UFSAR supplement contains a 

commitment (Commitment No. 15) to enhance the Compressed Air Monitoring program before

the period of extended operation. The staff finds that the information in the UFSAR supplement, 

as amended by letter dated February 15, 2012, is an adequate summary description of the 

program.

Conclusion. On the basis of its audit and review of the Compressed Air Monitoring program, the 

staff concludes that those program elements for which the applicant claimed consistency with 

the GALL Report are consistent. Also, the staff reviewed the enhancement and confirmed that 

its implementation will make the AMP adequate to manage the applicable aging effects and that 
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the UFSAR supplement contains Commitment No. 15 to implement the enhancement before the 

period of extended operation. 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).

3.0.3.1.10 BWR Reactor Water Cleanup System

Summary of Technical Information in the Application. LRA Section B.2.1.16 describes the 

existing BWR Reactor Water Cleanup System program as consistent with GALL Report 

AMP XI.M25, “BWR Reactor Water Cleanup System.” The LRA states that the AMP is a 

condition monitoring and mitigation program, consisting of augmented ISI for SCC or IGSCC on 

stainless steel RWCU system piping welds outboard of the second primary containment 

isolation valves. The program is implemented in conjunction with the Water Chemistry program 

to minimize the potential of cracking because of SCC or IGSCC in a treated water environment. 

The LRA also states that the program includes measures in NUREG-0313, Revision 2, 

“Technical Report on Material Selection and Processing Guidelines for BWR Coolant Pressure 

Boundary Piping,” dated January 1988, and GL 88-01, “NRC Position on IGSCC in BWR 

Austenitic Stainless Steel Piping,” dated January 25 1988, and its Supplement 1 dated February 

4, 1992. The LRA further states that the staff approved the elimination of examinations of the 

outboard portion of the RWCU system for both units; however, if ongoing inspections in 

accordance with GL 88-01, as performed under the BWR Stress Corrosion Cracking program, 

have confirmed IGSCC or SCC indications on RWCU system welds inboard of the primary 

containment isolation valves, then an additional sample of RWCU system welds outboard of the 

primary containment isolation valves will be examined based on the requirements of GL 88-01.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M25.

Based on its audit of the applicant’s BWR Reactor Water Cleanup System program, the staff 

finds that program elements 1-6 for which the applicant claimed consistency with the GALL 

Report are consistent with the corresponding program elements of GALL Report AMP XI.M25.

Operating Experience. LRA Section B.2.1.16 summarizes operating experience related to the 

BWR Reactor Water Cleanup System program. The LRA states that ongoing inspections of the 

RWCU system welds inboard of the RWCU system containment isolation valves have not 

identified IGSCC or SCC. The LRA also states that no inspection of the outboard RWCU 

system piping is required for LGS Units 1 and 2. No inspections are required for LGS Unit 1,

based on the satisfactory completion of all required actions in GL 89-10, “Safety-Related 

Motor-Operated Valve Testing and Surveillance,” dated June 28, 1989; no IGSCC detected in 

RWCU system piping welds inboard of the second primary containment isolation valves; and no 

IGSCC detected in RWCU system piping welds outboard of the second primary containment 

isolation valves after inspecting a minimum of 10 percent of the susceptible welds. The LRA 

states that no inspections are required for LGS Unit 2, based on the satisfactory completion of 

all required actions in GL 89-10 and the use of IGSCC-resistant piping materials.
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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 found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.16 provides the UFSAR supplement for the BWR 

Reactor Water Cleanup 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 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 BWR Reactor Water Cleanup System 

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).

3.0.3.1.11 Reactor Vessel Surveillance

Summary of Technical Information in the Application. LRA Section B.2.1.21 describes the 

existing Reactor Vessel Surveillance program as consistent with GALL Report 

AMP XI.M31,”Reactor Vessel Surveillance.” LGS Units 1 and 2 use the BWRVIP Integrated 

Surveillance Program (ISP) to monitor the effects of neutron embrittlement in the RPV beltline 

materials. The program satisfies the requirements of 10 CFR Part 50, Appendix H, “Reactor 

Vessel Material Surveillance Program Requirements.” The Reactor Vessel Surveillance 

program is based on the BWRVIP-86-A, “BWR Vessel and Internals Project, BWR Integrated 

Surveillance Program (ISP) Implementation,” and BWRVIP-116 report, “BWR Vessel Internals 

Project Integrated Surveillance Program Implementation for License Renewal” reports. 

The BWRVIP-116 report identifies and schedules additional capsules to be withdrawn and 

tested during the period of extended operation. LGS Units 1 and 2 will continue to participate in 

the ISP during the period of extended operation by implementing the requirements of the 

BWRVIP-116 report. This revised BWRVIP ISP is consistent with 10 CFR Part 50, Appendix H, 

and it will give reasonable assurance that the fracture toughness requirements of 

10 CFR Part 50, Appendix G, will be met through the period of extended operation.
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Staff Evaluation. Appendix H of 10 CFR Part 50 specifies surveillance program criteria for 

40 years of operation. GALL Report AMP XI.M31 specifies additional criteria for 60 years of 

operation. The staff determined that compliance with 10 CFR Part 50, Appendix H criteria for 

capsule design, location, specimens, test procedures, and reporting remains appropriate for this 

AMP because these items, which satisfy 10 CFR Part 50, Appendix H, will stay the same 

throughout the period of extended operation. 

The staff reviewed LRA B.2.1.21 to determine whether the AMP is adequate to manage the aging 

effects for which it is credited. During its review, the staff confirmed the applicant’s claim of 

consistency with the GALL Report. The LRA states that the AMP addresses irradiation 

embrittlement of the RPV beltline and extended beltline materials through testing that monitors 

the properties of the materials. The LRA stated that the Reactor Vessel Surveillance program 

will follow the requirements of the BWRVIP ISP and will apply the BWRVIP ISP data to LGS 

Units 1 and 2.

For the current period of operation, the applicant has implemented the BWRVIP ISP, which is 

based on the BWRVIP-86-A report. This report is consistent with GALL Report AMP XI.M31 for 

the current period of operation. For the current license period, the staff had concluded that the 

BWRVIP ISP in BWRVIP-86-A is acceptable for BWR applicant implementation provided that all 

participating applicants use one or more of the compatible neutron fluence methodologies 

acceptable to the staff for determining surveillance capsule and RPV neutron fluences. The 

staff’s acceptance of the BWRVIP ISP for the current term at LGS is documented in License 

Amendment 163 for LGS Unit 1 and License Amendment 130 for LGS Unit 2, both dated 

November 4, 2003.

For the period of extended operation, the applicant has stated that the existing program will be 

consistent with GALL Report AMP XI.M31 by implementing BWRVIP-116. BWRVIP-116 

provides guidelines for the ISP to monitor neutron irradiation embrittlement of the RPV beltline 

materials for all U.S. BWR power plants for the period of extended operation. 

Based on its audit of the Reactor Vessel Surveillance program, the staff finds that program 

elements 1-6 for which the applicant claimed consistency with the GALL Report are consistent 

with the corresponding program elements of GALL Report AMP XI.31.

Operating Experience. LRA Section B.2.1.21 summarizes operating experience related to the 

Reactor Vessel Surveillance program. The staff notes that the plants are part of the BWRVIP 

ISP and that LGS Units 1 and 2 are not required to withdraw any capsules during the period of 

extended operation. The applicant cited the plants’ evaluation of results from the BWRVIP ISP, 

reported in BWRVIP-135, to demonstrate that the materials met the requirements for continued 

safe operation. The evaluation results also provide evidence that the existing Reactor Vessel 

Surveillance program will be capable of monitoring the aging effects associated with the loss of 

fracture toughness caused by neutron irradiation embrittlement of the RPV beltline materials. 

The staff concurred with the applicant’s conclusion as supported by the staff’s approval of the 

current reflood thermal shock evaluation and pressure-temperature (P-T) limits (see 

Sections 4.2.7 and 4.2.4 of this SER) using information from all surveillance data in accordance 

with RG 1.99, Revision 2. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 
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aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.21 provides the UFSAR supplement for the Reactor 

Vessel Surveillance 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 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 Reactor Vessel Surveillance 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).

3.0.3.1.12 One-Time Inspection

Summary of Technical Information in the Application. LRA Section B.2.1.22 describes the new 

One-Time Inspection program as consistent with GALL Report AMP XI.M32, “One-Time 

Inspection.” The LRA states that the program manages the aging effects of loss of material, 

cracking, and loss of heat transfer in metallic piping, piping components, piping elements, and 

heat exchangers. The LRA also states that the program proposes to manage these aging 

effects through inspections focused on areas that are most susceptible to aging because of time 

in service and severity of operating conditions, such as regions isolated from the main flow 

stream with low flow or stagnant conditions.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M32. 

Based on its audit of the One-Time Inspection program, the staff finds that program elements 

1-6 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.2.1.22 summarizes operating experience related to the 

One-Time Inspection program. The LRA states operating experience for this new program that 

demonstrates that inspection, identification and corrective action steps for components within 

AMR are readily available for this program’s use and implementation before 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.
3-45

During its review, the staff found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

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 the program, when 

implemented, can adequately manage the effects of aging on SSCs within the scope of the 

program.

UFSAR Supplement. LRA Section A.2.1.22 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 UFSAR supplement contains a commitment (Commitment No 22) to 

implement the new One-Time Inspection program before entering the period of extended 

operation for managing aging of applicable components and to perform the one-time inspections 

within the 10 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 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).

3.0.3.1.13 Selective Leaching

Summary of Technical Information in the Application. LRA Section B.2.1.23 describes the new 

Selective Leaching program as consistent with GALL Report AMP XI.M33, “Selective Leaching 

of Materials.” The LRA states that the program manages loss of material because of selective 

leaching for copper alloy with greater than 15 percent zinc and gray cast iron piping and fittings, 

valve bodies, pump casings, heat exchanger components, tanks, and fire hydrants exposed to 

raw water, treated water, closed cycle cooling water, waste water, and soil. The LRA also 

states that the program will provide for one-time inspections of a representative sample of 

susceptible components using visual inspections, and hardness tests or other appropriate 

mechanical examinations, to identify and confirm existence of the loss of material because of

selective leaching. The LRA states that the Selective Leaching program will be implemented 

before the period of extended operation, and that the one-time inspections will be performed 

within the 5 years before entering 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 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M33.

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.
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The “acceptance criteria” program element in GALL Report AMP XI.M33 recommends that there 

be no visible evidence of selective leaching or no more than a 20 percent decrease in hardness. 

For copper alloys with greater than 15 percent zinc, the criterion is no noticeable change in color 

from the normal yellow color to the reddish copper color. The LRA program basis document for 

the Selective Leaching program states similar acceptance criteria. The applicant also proposes 

to use alternative mechanical examination techniques for which the hardness testing 

acceptance criterion is not applicable. By letter dated January 17, 2012, the staff issued 

RAI B.2.1.23-1 requesting the applicant to state what acceptance criterion will be used when 

alternative mechanical examination techniques are implemented. 

In its response, provided by letter dated February 15, 2012, the applicant stated that the 

alternative mechanical examinations, such as chipping or scraping, would be used where 

hardness testing cannot be performed. The applicant further stated that the chipping or 

scraping of the inspected surfaces would expose signs of selective leaching. These signs can 

be visually inspected because selective leaching leaves behind a porous material with voids and 

rust or a weakened and corroded structure. Therefore, the acceptance criterion of “no visible 

signs of selective leaching” will be used when the alternative mechanical examination 

techniques are applied.

When selective leaching occurs in gray cast iron, in particular, it is difficult to detect by visual 

inspection. Therefore, a hardness test or mechanical methods, such as chipping or scraping,

are essential for detection of selective leaching. Since the applicant will perform a visual

inspection of surfaces where chipping and scraping are used, and if there is any visible sign of 

selective leaching (e.g., porous material, voids, rust), it will take corrective action, the staff finds 

the applicant’s response acceptable. The staff’s concern described in RAI B.2.1.23-1 is 

resolved.

Based on its audit and review of the Selective Leaching program, and the applicant’s response 

to RAI B.2.1.23-1, the staff finds that program elements 1-6 for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.M33. 

Operating Experience. LRA Section B.2.1.23 states no occurrences of selective leaching have 

been identified at LGS 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. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

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 the program, when 

implemented, can adequately manage the effects of aging on SSCs within the scope of the 

program.
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UFSAR Supplement. LRA Section A.2.1.23 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 UFSAR contains a commitment (Commitment No. 23) to implement the new 

Selective Leaching program before entering the period of extended operation, and to perform 

the one-time inspections for selective leaching of components within the 5 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 Selective Leaching 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).

3.0.3.1.14 One-Time Inspection of ASME Code Class 1 Small-Bore Piping

Summary of Technical Information in the Application. LRA Section B.2.1.24 describes the new 

One-Time Inspection of ASME Code Class 1 Small-Bore Piping program as consistent with 

GALL Report AMP XI.M35, “One-Time Inspection of ASME Code Class 1 Small-Bore Piping.” 

The LRA states that this program manages cracking of ASME Code Class 1 piping less than 

4 inches and greater than or equal to 1-inch nominal pipe size (NPS) in a reactor coolant 

environment. The LRA also states that the program consists of a one-time volumetric 

examination of a representative sample of small-bore piping locations susceptible to cracking, 

which will include both socket welds and butt welds. For socket welds, the LRA states that if a 

demonstrated volumetric examination technique is not available by the time of the inspections, 

then destructive examinations will be conducted. In addition, the LRA states that the inspection 

locations will be based on susceptibility, inspectability, dose considerations, operating 

experience, and limiting locations of the total population of ASME Code Class 1 small-bore 

piping. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 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 an RAI, as discussed below.

The “detection of aging effects” program element in GALL Report AMP XI.M35 recommends 

that the inspection sample should include 10 percent of the weld population or a maximum of 

25 welds of each weld type (e.g., butt welds and socket welds) using a methodology to select 

the most susceptible and risk-significant welds. However, during its audit, the staff found that 

the One-Time Inspection of ASME Code Class 1 Small-Bore Piping program does not clearly 

provide the socket weld population within the scope of the program. Regarding the size of the 

inspection sample, the LRA states that, for socket weld volumetric examinations, 25 welds at 

each unit will be examined and the number of welds examined represents “more than 

38 percent of the high and medium consequence ranked socket welds.” It was not clear to the 

staff whether the applicant’s program is consistent with GALL Report AMP XI.M35 because the 
3-48

staff could not determine the total population of ASME Code Class 1 butt welds and socket 

welds at each unit within the scope of the program, and how the percentage was calculated. By 

letter dated November 18, 2011, the staff issued RAI B.2.1.24-1 requesting the applicant to

describe the total population of ASME Code Class 1 butt welds and socket welds at each unit 

within the scope of the program, and to clarify the inspection sample size for socket welds in 

terms of the percentage of the weld population. 

In its response, provided by letter dated December 7, 2011, the applicant described the 

populations of ASME Code Class 1 small-bore piping welds at each unit. Concerning butt 

welds, the applicant stated that LGS Unit 1 has 77 and LGS Unit 2 has 84. The applicant stated 

that it will inspect eight and nine of these welds, respectively, which correspond to greater than 

10 percent of the butt weld populations at each unit. Regarding socket welds, the applicant 

stated that LGS Unit 1 has 85 and LGS Unit 2 has 83 greater than 1-inch NPS and less than 

4 inches NPS, and it estimates that there are several hundred socket welds at each unit that are 

equal to 1-inch NPS. The applicant further stated that the inspection sample size for socket 

welds at each unit will be 25, which is the maximum inspection size recommended in GALL 

Report AMP XI.M35. The applicant also revised LRA Section B.2.1.24 to clarify the total 

populations of butt and socket welds at each unit within the scope of the program and the 

number of these welds that will be inspected. 

Based on its review, the staff finds the applicant’s response acceptable because the number of 

butt and socket welds to be inspected at each unit is consistent with the sampling guidance and 

recommendations in GALL Report AMP XI.M35. The staff’s concern described in 

RAI B.2.1.24-1 is resolved.

The staff noted that the applicant will implement a risk-informed methodology to select the most 

susceptible and risk-significant welds. The “detection of aging effects” program element of 

GALL Report AMP XI.M35 recommends a methodology to select the most susceptible and 

risk-significant welds. Therefore, the staff finds that the sample selection methodology is 

consistent with GALL Report AMP XI.M35. The LRA also states that the one-time inspections 

will be completed within 6 years before the period of extended operation. The staff finds this 

implementation schedule consistent with the recommendations of the “detection of aging 

effects” program element of GALL Report AMP XI.M35 regarding timely implementation of the 

one-time inspections and, therefore, acceptable. The staff determined that aging management 

of ASME Code Class 1 small-bore piping is adequately addressed because the scope of the 

program, number of welds to be inspected, selection methodology, and the timely 

implementation of the small-bore piping inspection are consistent with the recommendations in 

the GALL Report. 

Based on its audit, and review of the applicant’s response to RAI B.2.1.24-1, of the One-Time 

Inspection of ASME Code Class 1 Small-Bore Piping program, the staff finds that program 

elements 1-6 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.2.1.24 summarizes operating experience related to the 

One-Time Inspection of ASME Code Class 1 Small-Bore Piping program. The LRA indicates 

that this program is based on relevant plant and industry operating experience. The applicant 

provided some plant-specific operating experience in the LRA. The LRA states that there was 

one case in which the applicant detected a small leak from a LGS Unit 2 reactor vessel 

instrumentation nozzle in the nozzle safe-end to piping socket weld during an outage inspection 
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in 1997. The applicant performed a metallurgical analysis and an evaluation of the crack and 

determined that it was caused by improper fit-up during the weld installation. As part of its 

corrective actions, the applicant replaced the affected piping and performed inspection on all 

similar instrumentation nozzles at both LGS Unit 1 and LGS Unit 2. No additional adverse 

conditions were identified from the inspection. The applicant further stated that no cracking has 

since been observed for ASME Code Class 1 small-bore pipe welds. 

The staff noted that the applicant has performed design changes to mitigate the cause of failure, 

performed additional inspections to determine the extent of condition, and implemented 

corrective actions to prevent recurrence, and that there have not been any similar failures since 

the small leak detected during the 1997 outage inspection. Therefore, consistent with GALL 

Report AMP XI.M35, the use of the One-Time Inspection of ASME Code Class 1 Small-Bore 

Piping program is still applicable because this previous failure was successfully mitigated.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicant reviewed applicable aging effects and industry and 

plant-specific operating experience. 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 found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

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 the program, 

when implemented, can adequately manage the effects of aging on SSCs within the scope of 

the program. 

UFSAR Supplement. LRA Section A.2.1.24 provides the UFSAR supplement for the One-Time 

Inspection of ASME Code Class 1 Small-Bore Piping 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 and noted that the recommended description 

includes the statement: “Should evidence of cracking be revealed by a one-time inspection, 

periodic inspection is also proposed, as managed by a plant-specific AMP.” However, the 

UFSAR supplement for the program, as described in LRA Section A.2.1.24, does not include 

any statement on actions to be taken in the event that evidence of cracking is revealed by the 

One-Time Inspection of ASME Code Class 1 Small-Bore Piping program. The licensing basis 

for this program for the period of extended operation may not be adequate if the applicant does 

not incorporate this information into its UFSAR supplement. By letter dated 

November 18, 2011, the staff issued RAI B.2.1.24-2 requesting the applicant to amend the 

UFSAR supplement to indicate that, if evidence of cracking is revealed by the program, periodic 

inspections will be implemented under a plant-specific AMP. 

In its response, provided by letter dated December 7, 2011, the applicant revised LRA 

Section A.2.1.24 to include the statement: “A plant-specific periodic inspection program will be 

implemented if evidence of cracking caused by IGSCC or fatigue is revealed in ASME Class 1 

small-bore piping.” The staff finds the applicant’s response acceptable because the description 

in the UFSAR supplement, as amended, adequately captures the need to implement a 

plant-specific periodic inspection program to manage aging during the period of extended 

operation if cracking is revealed in ASME Code Class 1 small-bore piping. Therefore, the 
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UFSAR supplement for the One-Time Inspection of ASME Code Class 1 Small-Bore Piping 

program is consistent with the corresponding program description in SRP-LR Table 3.0-1. The 

staff’s concern described in RAI B.2.1.24-2 is resolved.

The staff also noted that the UFSAR supplement contains a commitment (Commitment No. 24) 

to implement the new One-Time Inspection of ASME Code Class 1 Small-Bore Piping program 

before entering the period of extended operation and perform one-time inspections within the 

6 years before the period of extended operation for managing aging of applicable components.

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

December 7, 2011, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the One-Time Inspection of ASME 

Code Class 1 Small-Bore Piping 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).

3.0.3.1.15 External Surfaces Monitoring of Mechanical Components

Summary of Technical Information in the Application. LRA Section B.2.1.25 describes the new

External Surfaces Monitoring of Mechanical Components program as consistent with GALL 

Report AMP XI.M36, “External Surfaces Monitoring of Mechanical Components.” The LRA 

states that the program directs visual inspections of external surfaces of components to be 

performed during system inspections and walkdowns. The LRA also states that the program

consists of periodic visual inspection of metallic and elastomeric components such as piping, 

piping components, ducting, and other components. The LRA further states that the program

will also include visual inspections augmented by physical manipulation as necessary for 

evidence of hardening and loss of strength.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M36. 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.M36 recommends that the 

program manages cracking of stainless steel components exposed to an air environment 

containing halides. However, during its audit, the staff found that the applicant’s program does 

not state that it manages cracking nor does it include inspections of stainless steel components 

in auxiliary systems for cracking. The staff issued RAI B.2.1.25-1 to address this concern. The 

applicant’s response to this RAI and the staff’s evaluation is documented in SER Sections 

3.3.2.2.3 and 3.4.2.2.2.

Operating Experience. LRA Section B2.1.25 summarizes operating experience related to the 

External Surfaces Monitoring of Mechanical Components program. 
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 • In 2008, a comprehensive inspection of external surfaces on LGS plant systems was 

conducted. The purpose of the LGS inspection was to identify and resolve degraded 

conditions on piping systems where unprotected or uncoated carbon steel piping was 

exposed to a wet environment. Results of the inspection indicated that the components 

were in good condition. Some occurrences of exterior corrosion were identified; these 

issues were entered into the CAP. Surfaces were cleaned or recoated as necessary.

 • During a routine walkdown in 2008, corrosion was identified on the LGS Unit 2 D22 

emergency diesel generator (EDG) jacket water heat exchanger outlet piping at a location 

where the external coating was no longer present. The issue was entered into the CAP, and 

a work order was generated to correct the condition. These surfaces were repainted.

 • During a visual inspection in 2003, a LGS Unit 2 circulating water system elastomer 

expansion joint was observed to have abnormal bulges indicating that the component is 

degraded. The issue was entered into the CAP. An engineered replacement was installed, 

followup actions were developed, and an extent of condition review was performed.

 • In 2007, an issue report was generated to document 15 compressed air system carbon steel 

drain lines that were severely corroded. This issue was entered into the CAP, and the 

corroded lines were replaced.

 • In 2007, an issue report was generated to document a degraded flexible boot on a 

ventilation exhaust fan discharge line. This issue was entered into the CAP, and a new 

flexible boot was installed.

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 found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

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 the program, when 

implemented, can adequately manage the effects of aging on SSCs within the scope of the 

program.

UFSAR Supplement. LRA Section A.2.1.25 provides the UFSAR supplement for the External 

Surfaces Monitoring for 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. The staff also noted that the UFSAR supplement contains a 

commitment (Commitment No. 25) to implement the new External Surfaces Monitoring for 

Mechanical Components before entering the period of extended operation for managing 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 audit and review of the External Surfaces Monitoring for 

Mechanical Components program, the staff concludes that those program elements for which 
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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).

3.0.3.1.16 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Summary of Technical Information in the Application. LRA Section B.2.1.26 describes the new 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program as 

consistent with GALL Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components.” The LRA states that the program addresses metallic and 

polymeric piping, piping elements and piping components, ducting components, tanks, heat 

exchangers, elastomers, and other components exposed to air/gas wetted, closed cycle cooling 

water, diesel exhaust, fuel oil, lubricating oil, raw water, treated water and waste water 

environments to manage the effects of loss of material for metallic and elastomeric components, 

loss of fracture toughness, reduction of heat transfer, cracking, and hardening and loss of 

strength for elastomers. The LRA also states that the program will manage these aging effects 

through visual inspections of component internal surfaces when surfaces are made accessible 

during surveillances, maintenance, and scheduled outages. The LRA further states that for 

flexible elastomers, the visual inspections will be augmented by physical manipulation. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M38, “Inspection of Internal Surfaces 

in Miscellaneous Piping and Ducting Components.” For the “scope of program” program 

element, the staff determined the need for additional information, which resulted in the issuance 

of RAIs, as discussed below.

The “scope of program” program element in GALL Report AMP XI.M38 recommends that the 

aging effects included in the program’s scope are to be inclusive of all those to be managed 

within the program. However, during its audit, the staff found that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components program omits the aging effects of 

loss of fracture toughness and reduction of heat transfer and cracking associated with Table 2 

items in the LRA. By letter dated January 17, 2012, the staff issued RAI B.2.1.26-1 requesting 

the applicant to revise the LRA AMP to include the program’s aging effects of loss of fracture 

toughness and reduction of heat transfer and cracking. The applicant also was requested to 

including the appropriate details, such as parameters to be monitored, acceptance criteria, and 

detection of aging effect elements necessary to support these program’s additional aging 

effects.

In its response, provided by letter dated February 15, 2012, the applicant stated that LRA 

AMP B.2.126 and LRA UFSAR supplement Section A.2.1.26 were revised (per Enclosure B of 

the letter) and loss of fracture toughness and reduction of heat transfer and cracking were 

added to those LRA Sections. The applicant also stated that loss of fracture toughness is 

applied to the ASME Code Class 3, B and C RWCU pump casings not applicable to the 

requirements of GALL Report AMP XI.M12, “Thermal Aging Embrittlement of Cast Austenitic 

Stainless Steel (CASS)” because that program only applies to ASME Code, Class 1 

components. The applicant also stated that the Inspection of Internal Surfaces in Miscellaneous 
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Piping and Ducting Components program will use visual inspections for these components to 

monitor for cracking, which follows the inspection and monitoring guidelines found to manage 

this aging effect in GALL Report AMP XI.M12, but that could not be applied with these ASME 

Code, Class 3 components. The applicant also stated that reduction of heat transfer aging 

effect will be managed for the reactor enclosure and control enclosure ventilation system 

coolers, and the EDG system combustion air coolers, using visual inspections. The applicant 

also stated that cracking will be managed for stainless steel components in the waste water 

exposed to greater than a 140 °F environment. The applicant also stated that since these 

components are in a more aggressive environment than environments addressed by GALL 

Report AMP XI.M32, One-Time Inspection program, the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program will be used and visual inspections will 

be used to manage cracking of stainless steel components in the waste water exposed to 

greater than 140 °F environment. The staff finds the applicant’s response acceptable because 

the applicant has identified all the aging effects that will be addressed by the program, including 

loss of fracture toughness, reduction of heat transfer, and cracking and the associated program 

inspections for these aging effects are adequate methods to manage these aging effects. The 

staff’s concern described in RAI B.2.1.26-1 is resolved.

The “scope of program” program element in GALL Report AMP XI.M38 recommends that the 

program’s scope include “...any water system other than open-cycle cooling water system 

(XI.M20), closed treated water system (XI.M21A), and fire water system (XI.M27).” However, 

during its audit, the staff found that the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components program included components in environments of fuel oil, lube oil, and 

closed cycle cooling water (i.e., closed treated water). By letter dated January 17, 2012, the 

staff issued RAI B.2.1.26-2 requesting the applicant to provide a technical justification for this 

enhancement to GALL Report AMP XI.M38, including how applying this AMP will ensure 

appropriate preventive actions and aging detection activities will be performed for components 

exposed to fuel oil, lubricating oil, or located within closed cycle cooling water systems. 

In its response, provided by letter dated February 15, 2012, the applicant stated that the 

components exposed to a fuel oil environment are associated with the dirty fuel oil portion of the 

EDG system and the fuel oil drain tank’s associated piping and valves that are beyond the 

boundary and preventative measures of GALL Report AMP XI.M30 “Fuel Oil Chemistry,” which,

therefore, would not be effective to manage this aging effect. The applicant also stated that 

these component environments have similar attributes of the waste water environments 

monitored by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program. This program already includes visual inspection of metallic components,

which is effective in identifying loss of material because of corrosion and it is why this program 

was selected for the fuel oil environment components. 

The applicant also stated that the components exposed to a lubricating oil environment are the 

elastomeric hoses in the lube oil portion of the EDG system that may indirectly benefit from the 

Lubricating Oil Analysis program, but which would not address aging effects associated with 

elastomeric components and would not be effective in managing this aging. The applicant also 

stated that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

program already includes visual inspection and manual manipulation of elastomeric components 

that effectively identifies hardening and loss of strength caused by elastomeric degradation,

which is why this program was selected to manage these components consistent with the GALL 

Report. 
3-54

The applicant also stated that the components exposed to a closed treated water environment 

are the hoses in the jacket cooling water portion of the EDG system. The GALL Report, in AMR 

item VII.C2.AP-259, recommends the use of the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program to manage hardening and loss of 

strength caused by elastomeric degradation of components in a closed-cycle cooling water 

environment. The applicant also stated that these components may indirectly benefit from 

preventive measures in the Closed Treated Water Systems program. However, that program 

does not address aging effects associated with elastomeric components, whereas the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program 

already includes visual inspection and manual manipulation of elastomeric components effective 

in identifying hardening and loss of strength caused by elastomeric degradation, which is why 

this program was selected to manage these components consistent with the GALL Report. 

The staff finds the applicant’s response acceptable because the measures within the Fuel Oil 

Chemistry, Lubricating Oil Analysis, or Closed Treated Water Systems programs are not 

applicable to manage the aging effects for the components discussed above; however, the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program does 

include inspection techniques with suitable and adequate methods for the management of these 

aging effects involved with these components. 

Based on its audit, the staff finds that the program elements 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.2.1.26 summarizes operating experience related to the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program. The 

applicant provided relevant operating experiences in which internal inspections effectively 

identified and corrected degraded conditions in conjunction with the use of the CAP. In one 

example, the applicant discussed internal inspections of the main condenser performed during 

the refueling outages’ routine maintenance. These inspections identified degraded conditions 

that were entered into the CAP and led to immediate repairs, or operability evaluations followed 

by scheduled repairs. In another operating experience example, the applicant identified the 

need to clean the exhaust silencer drain pots for an EDG. The drain pots were cleaned and the 

issue was placed in the CAP, which led to an extent of condition review and the cleaning of 

each of the other EDGs’ drain pots. 

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 found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

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 the program, when 

implemented, can adequately manage the effects of aging on SSCs within the scope of the 

program.
3-55

UFSAR Supplement. LRA Section A.2.1.26 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 

the recommended description in SRP-LR Table 3.0-1. The staff also noted that the UFSAR 

supplement contains a commitment (Commitment No. 26) to implement the new Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components program before entering the 

period of extended operation for managing 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 audit and review of the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program, the staff concludes that the program 

elements for which the applicant claimed consistency with the GALL Report are consistent with 

the corresponding program elements of GALL Report AMP XI.M38. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that he 

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). 

3.0.3.1.17 Lubricating Oil Analysis

Summary of Technical Information in the Application. LRA Section B.2.1.27 describes the 

existing Lubricating Oil Analysis program as consistent with GALL Report AMP XI.M39, 

“Lubricating Oil Analysis.” The applicant stated that the program provides oil condition 

monitoring activities to manage 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. It is further stated that sampling, analysis, and 

condition monitoring activities identify specific wear products and contamination and determine 

the physical properties of lubricating oil within operating machinery. The applicant stated that 

these activities are used to verify that the wear products and contamination levels and the 

physical properties of the lubricating oil are maintained within acceptable limits to ensure that 

intended functions are maintained. This program identifies detrimental contaminants such as 

water, sediments, specific wear elements, and elements from an outside source. The applicant 

also stated that contaminant levels are trended in the program’s database, and 

recommendations are made when adverse trends are observed.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M39.

Based on its audit of the Lubricating Oil Analysis program, the staff finds that program elements 

1-6 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.2.1.27 summarizes operating experience related to the 

Lubricating Oil Analysis program. 
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The applicant provided the following for operating experience:

The applicant stated that in 2010, an analysis of lubricating oil from the Unit 1,

reactor core isolation cooling (RCIC) pump bearings indicated the presence of 

unexpected additives for the correct grade of lubricating oil. It indicated that zinc, 

phosphorus and calcium were the additives detected in the oil that is specified for 

the equipment and all other parameters were in the normal range. An Issue 

Report was created and it was determined that the most likely source was 

inadvertent combination of DTE 732 and DTE 26 oil in a container used for 

another component. It was stated that an evaluation and consultation with the 

lubricant supplier was conducted and it was determined that there was no 

adverse impact to the properties of the oil. The applicant stated that as a result, 

the RCIC pump bearings were flushed and the oil replaced.

In March 2009, it was reported that an analysis of the lubricating oil for the Unit 1,

RCIC turbine indicated an elevated particle count in the alert range for this 

component. The oil was required to be changed during the next refueling outage 

per the Oil Analysis Interpretation Guideline. It was stated that the alert range 

indicated a low probability of damage or failure of equipment and additional 

monitoring or analysis may have been required. Subsequently, the applicant 

stated that the RCIC turbine lubrication oil was changed in September 2009.

The applicant stated that in November 2008, the lubrication oil sample results for 

the “C” Schuylkill River makeup pump motor indicated high viscosity. It was 

reported that the viscosity for the upper bearing oil was in the fault range and the 

lower bearing was just below the alert range. The applicant stated that the high 

viscosity indicates that the oil is approaching the end of life. The applicant stated 

that a recommendation was made to replace the 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.

During its review, the staff found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.27 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 
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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 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).

3.0.3.1.18 10 CFR Part 50, Appendix J

Summary of Technical Information in the Application. LRA Section B.2.1.33 revised by a letter 

dated March 20, 2012, describes the existing 10 CFR Part 50, Appendix J condition monitoring 

program as consistent with GALL Report AMP XI.S4, “10 CFR Part 50, Appendix J.” The LRA 

states that the program addresses the containment steel structures, concrete embedments, 

penetration sleeves/pressure boundary access points, hatches, airlock, bolting, exposed to 

indoor air and treated water environments to manage the effects of loss of material, loss of 

sealing/degradation of gaskets, leakage, and loss of bolt preload. The LRA also states that the 

program proposes to manage these aging effects through containment leak-rate tests (LRTs) in 

accordance with the 10 CFR Part 50, Appendix J, “Primary Reactor Containment Leakage 

Testing for Water-Cooled Power Reactors,” on a performance-based approach (Option B) for 

the testing frequency. The LRTs are performed in accordance with NRC RG 1.163 

“Performance-Based Containment Leak-Test Program,” NEI 94-01 “Industry Guidance for 

Implementing Performance-Based Options of 10 CFR Part 50, Appendix J,” and ANSI/ANS 

56.8, “Containment System Leakage Testing Requirements.” The LRTs are performed to 

assure that the leakage through the primary containment and systems and components 

penetrating primary containment will not exceed allowable limits specified in Technical 

Specifications. An integrated leak rate test (ILRT) is performed during a period of reactor 

shutdown, and local leak rate tests (LLRTs) are performed on isolation valves and containment 

access penetrations not to exceed 10 CFR Part 50, Appendix J, Option B specified frequencies.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.S4. For the “scope of program,” and 

“detection of aging effects,” program elements, the staff determined the need for additional 

information, which resulted in the issuance of three RAIs as discussed below.

The “scope of program” program element in GALL Report AMP XI.S4 recommends to include in 

the LRTs all of the containment boundary pressure-retaining components. However, during the 

audit the applicant stated that certain components subjected to Type B and C tests have been 

exempted/excluded from the 10 CFR Part 50, Appendix J LLRTs. The original staff evaluation 

of the exemptions from the requirements of 10 CFR Part 50, Appendix J testing are contained in 

the LGS Units 1 and 2 SER and its Supplement 3, dated August 1983. The NRC, by letter 

dated August 8, 1985, approved certain exemptions for LGS Unit 1 (LGS Unit 2 became 

operational in 1989 and has the same exemptions) and letter dated February 8, 1996 eliminated 

requirements for certain Type C components from the 10 CFR Part 50, Appendix J testing for 

LGS Units 1 and 2. The applicant stated that during the period of extended operation they 
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intend to manage aging effects for these exempted/excluded components through other AMPs. 

It was not clear to the staff which AMPs the applicant would use to manage the aging effects for 

the exempted/excluded components. By letter dated January 30, 2012, the staff issued RAI 

B.2.1.33-1 requesting the exempted or excluded components (valves, penetrations, and other 

components) from the 10 CFR Part 50, Appendix J program to be identified along with the basis 

for their exemption or exclusion and the proposed AMPs to be used to manage the applicable 

aging effects during the period of extended operation. 

In its response to RAI B.2.1.33-1, dated February 28, 2012, the applicant stated that the 

components that are exempted from both LGS Unit 1 and Unit 2 are the traversing in-core probe 

(TIP) system shear valves. The applicant stated that these valves are the outboard isolation 

valves for containment penetrations 35C-G. Type C LLRTs of the shear valves are not practical 

because squib detonation is required for closure. Instead, the applicant proposes to manage 

the aging effects for the TIP system shear valves by the Compressed Air Monitoring program. 

In addition the applicant stated that it has excluded penetration number 240 and the associated 

components from LLRTs. The associated components of the penetration, consist of a 

suppression pool water seal inboard isolation barrier, a blind flange outboard isolation barrier, 

and a closed system outside containment. The applicant justified this exclusion by stating that 

the blind flange is not exposed to the primary containment atmosphere because the line 

terminates below the minimum water level of the suppression pool and hence there would be a 

water seal in the case of LOCA, thus excluding the necessity for 10 CFR Part 50, Appendix J 

LLRT. The applicant proposes to manage aging effects for the excluded components

associated with penetration number 240 and included in the LRA Table 3.2.2-5, “Residual Heat 

Removal (RHR) System Summary of Aging Management Evaluation,” with the Bolting Integrity 

program for bolting, and the External Surfaces Monitoring of Mechanical Components, Water 

Chemistry, and One-Time Inspection programs for piping, piping components, piping elements, 

and valves.

The applicant also stated in its response to RAI B.2.1.33-1, that certain isolation valves, 

identified in UFSAR Table 6.2-25, “Containment Penetrations Compliance with 10 CFR 50, 

Appendix J,” have been excluded from 10 CFR Part 50, Appendix J program LLRTs. The 

applicant proposed to manage the aging effects for the excluded valves with the External 

Surfaces Monitoring of Mechanical Components, the Water Chemistry, and the One-Time 

Inspection programs. The valves excluded from LLRTs are the RHR system isolation valves 

associated with penetrations 203 A-D, 204A and B, 226A and B, 238, 239; the CS system 

isolation valves associated with penetrations 206A-D, 207A and B, 208B; and 235, the HPCI

system isolation valves associated with penetrations 209, 210, 212, and 236; and the RCIC

system isolation valves associated with penetration 214, 215, and 216. 

The staff reviewed Table 6.2-25 of the UFSAR and the applicant’s response to RAI B.2.1.33-1, 

and confirmed that for all penetrations (with the exception of penetration 240) that “[t]he isolation 

provisions consist of a suppression pool water seal, at least one isolation valve outside 

containment, and a closed system outside containment.” The UFSAR also states that “[t]he 

isolation valve is not exposed to the primary containment atmosphere because the line 

terminates below the minimum water level of the suppression pool. The closed system is 

missile-protected, seismic Category I, quality group B, and designed to the temperature and 

pressure conditions that the system will encounter post-LOCA.” For penetration 240, the staff 

noted that Table 6.2-25, of the UFSAR does not list any valves. The applicant responded that 

this penetration is subject to Type A ILRT. 
3-59

The staff determined that the applicant’s plans to manage the capacity of leak tightness and 

associated aging effects of the exempted/excluded containment pressure boundary components 

through mechanical programs consistent with the GALL Report and acceptable, because they 

will monitor age-related pressure boundary degradation loss of material, loss of sealing, loss of 

leak tightness, and loss of bolting preload. The staff’s concern described in RAI B.2.1.33-1 is 

resolved. 

The staff noted discrepancies that affect the “scope of program” program element between the 

UFSAR Tables that include the containment boundary pressure retaining components subject to 

LLRTs and the Technical Requirements Manual (TRM) containing the plant’s testing 

requirements. The staff also noted a condition report recognizing discrepancies between the 

UFSAR and the TRM documentation. It is to be noted that the “scope of program” program 

element in GALL Report AMP XI.S4 includes the LRTs of all of the containment boundary 

pressure-retaining components. Although, the discrepancies are being tracked by the applicant, 

it was not clear which document, the UFSAR or the TRM, the applicant would use for the 

10 CFR Part 50, Appendix J program testing of systems and components (SCs) during the 

period of extended operation. By letter dated March 9, 2012, the staff issued RAI B.2.1.33-3, 

requesting the applicant to identify which document would be followed for testing of SCs during 

the period of extended operation. The staff also requested the applicant to update the LRA to 

reflect the document to be followed during the implementation of the 10 CFR Part 50, 

Appendix J program testing.

In its response to RAI B.2.1.33-3, dated March 20, 2012 the applicant stated that for LGS 

Units 1 and Unit 2, neither the UFSAR nor the TRM are to be used to provide listing of Type A, 

B, and C for leak rate testing of SCs during the period of extended operation. The applicant 

also stated that the discrepancies in these documents are resolved. The leak rate testing of 

SCs follows the plant test procedures, which are based on the licensing basis described in the 

UFSAR and TRM. In addition, the applicant revised the program description to indicate that 

plant procedures are the governing documents for administering the LRTs.

The staff reviewed the applicant’s response to RAI B.2.1.33-3 and noted that the revised 

program description stating that the “[c]ontainment leak rate tests are performed using plant 

procedures,” is acceptable, because the applicant has appropriately designated the plant 

procedures to identify and control all SCs subject to LRTs and their status during testing. The 

staff’s concern described in RAI B.2.1.33-3 is resolved. 

The “detection of aging effects” program element in GALL Report AMP XI.S4 states that while 

the calculation of leakage rates and satisfactory performance of containment leakage rate 

testing demonstrates the leak-tightness and structural integrity of the containment, it does not by 

itself provide information that would indicate that aging degradation has initiated or that the 

capacity of the containment may have been reduced. The NRC through generic Information 

Notices (INs), identified conditions that could impact leak tightness and aging degradation of the 

containment boundary pressure-retaining SCs. IN 2005-23 “Vibration Induced Degradation of 

Butterfly Valves,” and IN 2006-15 “Vibration Induced Degradation and Failure of Safety-Related 

Valves,” have been issued stating that vibration induced stress, wear, and degradation could 

involve leakage and other long-term effects that could affect valve operation. The staff also 

noted that the plant’s operating experience database indicated that LGS, Unit 2 main steam 

isolation valve (MSIV) experienced vibration and or shuddering. It was not clear how these INs 

were addressed and resolved by the applicant. By letter dated March 9, 2012, the staff issued 

RAI B.2.1.33-2, requesting the applicant to describe how IN 2005-23 and IN 2006-15 have 
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been, and will continue to be addressed so that the integrity of potentially affected containment 

pressure boundary SCs would not be compromised during the period of extended operation.

In its response to RAI B.2.1.33-2, dated March 20, 2012 the applicant stated that LGS Units 1 

Unit 2 addressed IN 2005-23 for vibration induced degradation of butterfly valves in water 

systems and evaluated its applicability to LGS in December of 2006. Containment penetrations 

X-25, X-26, X-201A, and X-202 are the only LGS penetrations that use butterfly valves for 

containment isolation valves. The applicant also stated that these penetrations are for the 

drywell and suppression pool purge supply and exhaust piping, which is an air environment and 

concluded that these butterfly valves are not susceptible to the vibration induced degradation 

experienced by butterfly valves in water systems. As for IN 2006-15 which identifies the issue 

of vibration-induced degradation and failure of safety-related valves, the applicant stated that 

this has been addressed in the preventive maintenance process, which classifies components 

based on criticality and service and specifies inspections and inspection frequencies as 

appropriate. The applicant then referenced its letter dated March 13, 2012, in response to RAI 

B.1.4-1, addressing operating experience. The staff’s evaluation of the applicant response to 

RAI B.1.4-1 is addressed in SER 3.0.3.5. The RAI response stated that LGS considers internal 

and external plant operating experience through a broad set of sources that includes Institute of 

Nuclear Power Operations (INPO) event report operating experience documents, NRC bulletins, 

generic letters, INs and regulatory issue summaries, as well as topical reports and vendor 

correspondence (including 10 CFR Part 21 information). It is in this context that the applicant

will readdress the specifics of the INs related to vibratory environments in a global setting and in 

an ongoing basis, capturing new insights on vibration-induced degradation and long-term effects 

on valves including those activities performed by the 10 CFR Part 50, Appendix J program. 

The staff reviewed the applicant’s response to RAI B.2.1.33-2 and finds it acceptable, because 

the applicant continuously reviews its own operating experience, and industrial and regulatory 

sources as appropriate for the 10 CFR Part 50, Appendix J program. The staff’s concern 

described in RAI B.2.1.33-2 is resolved. 

Based on its audit and review of the applicant’s responses to RAIs B.2.1.33-1, B.2.1.33-3, 

B.2.1.33-2 of the 10 CFR Part 50, Appendix J program, the staff finds that program elements 

1-6 for which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.S4.

Operating Experience. LRA Section B.2.1.33 summarizes operating experience related to the 

10 CFR Part 50, Appendix J program. The applicant demonstrated through the 10 CFR Part 50, 

Appendix J program test results that the effects of aging are effectively managed. These results 

show that SCs are adequately maintained, and that the tested SCs are maintained with 

significant safety margins between the technical specifications allowable leakage rate limits and 

the as-tested leakage rates. 

Periodic self-assessments of the 10 CFR Part 50, Appendix J program are performed to identify 

the areas that need improvement to maintain the quality performance of the program. The staff 

reviewed a 2007 focused area self-assessment for the 10 CFR Part 50, Appendix J program, 

which considered industry and plant operating experience. The self-assessment concluded that 

the program was strong, had no deficiencies, and findings were tracked to resolution. This 

example provides evidence that industry and plant operating experience reviews are performed 

and that program procedural compliance is achieved. 
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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 found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.33 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 conforms to the recommended description for this type of program 

as described 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 review of the 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). 

3.0.3.1.19 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.2.1.38 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 applicant stated 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. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.E1.
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Based on its audit of the Insulation Material for Electrical Cables and Connections Not Subject 

to 10 CFR 50.49 Environmental Qualification Requirements program, the staff finds that 

program elements 1-6 for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.E1.

Operating Experience. LRA Section B.2.1.38 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 applicant stated that regular 

maintenance inspections have identified cable jacket cracking and embrittlement that were 

repaired with no loss of function.

The LRA states that in March 2009, during performance of a routine functional check of a level 

switch for the LGS Unit 2 moisture separator drain tank, it was identified that the outer jacket for 

the level switch circuit was breaking down and brittle. The wire insulation appeared to be in 

general good condition. The cable jacket was repaired by standard process using heat shrink 

electrical tape. The associated switch was found in calibration during post-maintenance testing, 

confirming circuit integrity. 

The LRA also states that in March 2010, during performance of a LGS Unit 1 Limitorque motor 

operated valve preventive maintenance task on a main steam branch isolation valve, it was 

identified that the outer jacketing on the power and control cable was cracked and brittle. The 

cable jacket was repaired by standard process using Raychem sleeving. 

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 found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

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 the program, 

when implemented, can adequately manage the effects of aging on SSCs within the scope of 

the program. 

UFSAR Supplement. LRA Section A.2.1.38 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 UFSAR supplement contains a commitment (Commitment No. 38) to implement the new 

Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements program prior to entering the period of extended 

operation.
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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 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).

3.0.3.1.20 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.2.1.39 describes the new 

Insulation Material for Electrical Cables and Connections 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 applicant stated the in-scope process radiation monitoring and 

neutron monitoring circuits are sensitive instrumentation circuits with high-voltage, low-level 

current signals located in areas where the cables and connections could be exposed to adverse 

localized environments caused by temperature, radiation, or moisture. The applicant also 

stated that adverse localized environments can result in reduced insulation resistance causing 

increases in leakage currents.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.E2.

Based on its audit, of the Insulation Material for Electrical Cables and Connections Not Subject 

to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits 

program, the staff finds that program elements 1-6 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.2.1.39 summarizes operating experience related to the 

Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Used in Instrumentation Circuits program. The LRA 

states that in March 2006, it was identified that a LGS Unit 1 low-power range monitor (LPRM)

had a defective connector on the under vessel end of the cable that connects the detector to the 

pull box in the drywell. Troubleshooting identified that the electrical connection under vessel 

was affecting continuity and causing the less than adequate LPRM performance. The cable and 

connector were replaced. Subsequent circuit testing was completed and met acceptance 

criteria.

The LRA also states that in February 2009, during performance of calibration for preventive 

maintenance it was identified that a LGS Unit 2 intermediate range monitor detector did not 
3-64

meet the acceptance criteria for the I/V (current to voltage) curve test. Troubleshooting was 

performed, which included direct cable tests of the complete circuit, testing of outboard and 

inboard penetration connections, testing of under vessel connections, and direct cable tests of 

the circuit upstream of the under vessel connections. It was determined that the under vessel 

connection was the cause of not meeting test acceptance criteria. The connection was replaced 

and post-connection replacement results were satisfactory. 

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 found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

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 the program, when 

implemented, can adequately manage the effects of aging on SSCs within the scope of the 

program.

UFSAR Supplement. LRA Section A.2.1.39 provides the UFSAR supplement for the Insulation 

Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualifications Requirements Used in Instrumentation Circuits 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 UFSAR supplement contains a commitment (Commitment No. 39) to implement the new 

Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Used in Instrumentation Circuits program before

entering the period of extended operation for managing 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 review of the Insulation Material for Electrical Cables and 

Connections 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).
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3.0.3.1.21 Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements

Summary of Technical Information in the Application. LRA Section B.2.1.40 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 LRA 

states that the AMP manages non-environmental qualification (EQ), in-scope, inaccessible 

power cables exposed to significant moisture. The LRA defined inaccessible power cables for 

this program as greater than or equal to 400 volts. The LRA also states that the in-scope cables 

of this program will be tested at least once every 6 years using a proven test for detecting 

deterioration of the insulation system because of significant moisture. The first tests will be 

completed before the period of extended operation. 

The LRA stated that inspection for water collection in manholes with subsequent corrective 

actions (e.g., water removal), as necessary will be performed at least annually. The LRA also 

states that before the period of extended operation, the frequency of inspections for 

accumulated water will be established and adjusted based on plant-specific inspection results. 

The LRA further stated that the operation of dewatering devices will be confirmed before any 

known or predicted heavy rain or flooding event. The LRA further states that the first 

inspections are to 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 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.E3. 

For the “preventive actions” and “detection of aging effects” program element, LRA 

Table 2.5.2-1, and the applicant’s draft procedure for implementing the program, the staff 

determined the need for additional information, which resulted in the issuance of RAIs as 

discussed below.

GALL Report AMP XI.E3 recommends periodic actions to be taken to prevent inaccessible 

power cables from being exposed to significant moisture, such as identifying and inspecting 

accessible cable conduit ends and cable manholes within the scope of license renewal for water 

collection and draining the water, as needed.

However, during its audit, the staff found that the applicant’s program description and 

“preventive action” program element of the applicant’s program basis document, LRA

Sections A.2.1.40, and B.2.1.40, and LRA Table A.5, Commitment No. 40, are not consistent in 

describing the applicant’s program to manage inaccessible power cables subject to significant 

moisture (e.g., exposed to significant moisture, minimize exposure, and prevent exposing 

cables to significant moisture). It was not clear that these statements are consistent with GALL 

Report AMP XI.E3, which recommends that actions be taken to prevent cables from being 

exposed to significant moisture whereas the applicant’s AMP, and LRA, including 

Sections B.2.1.40 and A.2.1.40, and LRA Table A.5, Commitment No. 40 describe the program 

as minimizing potential exposure to significant moisture. By letter dated January 30, 2012, the 

staff issued RAI B.2.1.40-1 requesting that the program basis document, LRA 

Sections B.2.1.40, and A.2.1.40, and LRA Table A.5, Commitment No. 40 provide consistency 

with GALL Report AMP XI.E3 in the management of inaccessible power cable exposed to 

significant moisture.
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In its response, dated February 28, 2012, the applicant stated that the Inaccessible Power 

Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program is a 

new program that is consistent with GALL Report AMP XI.E3. The applicant also stated that 

inaccessible power cables in the scope of this program may at times be exposed to significant 

moisture. The applicant stated that these cables will be tested using a proven test for detecting 

reduced insulation resistance of the cables’ insulation system because of wetting or 

submergence. The applicant further stated that the Inaccessible Power Cables Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements program, LRA Sections A.2.1.40 and 

B.2.1.40, and LRA Table A.5, Commitment No. 40, were revised to clarify that periodic actions 

will be taken to prevent inaccessible cables from being exposed to significant moisture. 

Additionally, the applicant stated that the program basis document will also be revised for this 

clarification. 

The staff finds the applicant’s response acceptable because LRA Sections B.1.2.40 and 

A.2.1.40, and LRA Table A.5, Commitment No. 40 were revised consistent with GALL Report 

AMP XI.E3 such that periodic actions are taken to prevent inaccessible cables from being 

exposed to significant moisture. In addition, the applicant’s program basis document also will 

be revised to reflect this change. The staff’s concern described in RAI B.2.1.40-1 is resolved.

GALL Report item VI.A.LP-35 addresses conductor insulation for inaccessible power cables 

greater than or equal to 400 volts (e.g., installed in conduit or direct buried) constructed of

various organic polymers and recommends GALL Report AMP XI.E3, “Inaccessible Power 

Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements” to manage

reduced insulation resistance caused by moisture.

During its audit, the staff noted that the LRA uses the term “Electrical Continuity” in describing 

the intended function in LRA Table 2.5.2-1, for the commodity “Insulation Material for Electrical 

Cables and Connections.” LRA Table 3.6.2-1 uses “Electrical Continuity” for the intended 

function for component types, “Conductor Insulation for Inaccessible Power Cables Greater 

Than or Equal to 400V,” “Fuse Holders (Not Part of Active Equipment): Insulation Material,”

“Insulation Material for Electrical Cables and Connections,” “Insulation Material for Electrical 

Cables and Connections Used in Instrumentation Circuits,” and LRA Section 2.5.2.5.2, 

“Electrical Penetrations.” In addition, component type, “Electrical Equipment Subject to 

10 CFR 50.49 EQ Requirements,” in LRA Table 3.6.2-1 lists the materials “Various Polymeric 

and Metallic Materials,” and, therefore, also should include the intended function “Insulate 

(Electrical).” The use of the intended function, “Electrical Continuity” in the above examples is 

inconsistent with the material (various organic polymers) listed for the component types 

referenced. By letter dated January 30, 2012, the staff issued RAI B.2.1.40-2 requesting the 

applicant to provide revised intended functions for LRA Table 2.5.2-1, Insulation Material for 

Electrical Cables and Connections, and LRA Table 3.6.2-1, Component Types (Conductor 

Insulation for Inaccessible Power Cables Greater Than or Equal to 400V, Electrical Equipment 

Subject to 10 CFR 50.49 EQ Requirements, Fuse Holders (Not Part of Active Equipment): 

Insulation Material, Insulation Material for Electrical Cables and Connections, and Insulation 

Material for Electrical Cables and Connections Used in Instrumentation Circuits). 

In its response, provided by letter dated February 28, 2012, the applicant stated that the 

intended function for insulation materials subject to an AMR is “Insulate (Electrical)” and LRA 

Section 2.5.2.5.2 was revised to remove electrical continuity. The applicant also stated that 

LRA Table 2.5.2-1 was revised to identify the intended function of Insulation Material for 
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Electrical Cables and Connections as “Insulate (Electrical)” and to clarify the name of the fuse 

holder commodity to “Fuse Holders: Metallic Clamps.” In addition, the applicant stated that 

LRA Table 3.6.2-1 was revised to change the intended functions for insulation material 

component types to “Insulate (Electrical)” for the following items: Conductor Insulation for 

Inaccessible Power Cables Greater Than or Equal to 400V, Electrical Equipment Subject to 

10 CFR 50.49 EQ Requirements Made of Various Polymeric Materials, Fuse Holders (Not Part 

of Active Equipment): Insulation Material, Insulation Material for Electrical Cables and 

Connections, and Insulation Material for Electrical Cables and Connections Used in 

Instrumentation Circuits.

The staff finds the applicant’s response acceptable because LRA Section 2.5.2.5.2 has been

clarified with regard to intended function and LRA Tables 2.5.2-1 and 3.6.2-1 have been revised 

to change the intended functions for insulation material to “Insulate (Electrical),” making the use 

of “Insulate (Electrical)” consistent with the material listed for the component types referenced. 

The staff’s concern described in RAI B.2.1.40-2 is resolved.

GALL Report AMP XI.E3 recommends that inaccessible power cables exposed to significant 

moisture be tested at a frequency of at least every 6 years, and test frequencies adjusted based 

on test results and operating experience. 

During its audit, the staff noted that draft procedure implementing the program specifies a test 

frequency of every third refueling outage. The “detection of aging effects” program element of 

the applicant’s AMP basis document states that the testing will be performed every 6 years and 

does not include a provision that test frequencies are adjusted based on test results and 

operating experience. It is not clear to the staff that the applicant’s program, when 

implemented, will be consistent with GALL Report AMP XI.E3 such that testing will occur at 

least every 6 years and more frequent testing will occur based on test results and operating 

experience. By letter dated January 30, 2012, the staff issued RAI B.2.1.40-3 requesting the 

applicant to explain why the “detection of aging effects” program element in the applicant’s AMP 

basis document, along with draft work order revisions, specify only a 6-year test interval but do 

not specify a test frequency of at least every 6 years, and that test frequencies are adjusted 

based on test results and operating experience. In addition, the staff asked the applicant to 

explain why LRA Sections A.2.1.40, and B.2.1.40, and LRA Table A.5, Commitment No. 40 

specify only a test interval of at least every 6 years but do not specify that test frequencies are 

adjusted based on test results and operating experience.

In its response, dated February 28, 2012, the applicant stated that the Inaccessible Power 

Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program 

including implementing work orders are subjected to the applicant’s CAP, in accordance with 

the “corrective action” program element. The applicant also stated that under the “corrective 

action” program, unacceptable results are subject to engineering evaluation with the evaluation 

considering the significance of the test results when determining corrective actions. The 

applicant stated that one potential corrective action would be more frequent cable testing. The 

applicant further stated that for clarity and alignment the “detection of aging effects” program 

element, LRA Sections A.2.1.40 and B.2.1.40, and LRA Table A.5, Commitment No. 40 were

revised to clarify a cable test frequency of at least every 6 years and that more frequent testing 

may occur based on test results and operating experience. Additionally, the applicant stated 

that the program basis document and work order revision requests also will be revised for this 

clarification. 
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The staff finds the applicant’s response acceptable because LRA Sections A.2.1.40 and 

B.2.1.40, and LRA Table A.5, Commitment No. 40 have been revised to include a provision that 

more frequent testing may occur based on test results consistent with GALL Report AMP XI.E3. 

In addition, the applicant’s program basis document will be revised to reflect this change. The 

staff’s concern described in RAI B.2.1.40-3 is resolved.

GALL Report AMP XI.E3, program element “preventive actions,” recommends that inspections 

are performed periodically based on water accumulation over time and for event-driven

occurrences, such as heavy rain or flooding.

During its audit, the staff found that the applicant’s AMP basis document and LRA 

Sections A.2.1.40 and B.2.1.40, and LRA Table A.5, Commitment No. 40 are not consistent with 

GALL Report AMP XI.E3 in that event-driven inspection (e.g., for heavy rain or flooding events) 

are not specified to be performed. By letter dated January 30, 2012, the staff issued 

RAI B.2.1.40-4 requesting the applicant to explain why the AMP basis document, LRA 

Sections A.2.1.40 and B.2.1.40, and LRA Table A.5, Commitment No. 40 do not specify 

inspections will be performed for event-driven occurrences. 

In its response, dated February 28, 2012, the applicant stated that the “preventive actions”

program element for the Inaccessible Power Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements program, LRA Sections A.2.1.40 and B.2.1.40, and 

LRA Table A.5, Commitment No. 40 were revised to include a provision that the inspection 

frequency for manholes will be established and performed based on water accumulation over 

time and event-driven occurrences, such as heavy rain or flooding. The applicant also stated 

that the program basis document will be revised to include this change.

The staff finds the applicant’s response acceptable because LRA Sections A.2.1.40 and 

B.2.1.40, and LRA Table A.5, Commitment No. 40 has been revised to include a provision that

the inspection frequency for manholes will be established and performed based on water 

accumulation over time and event-driven occurrences, such as heavy rain or flooding,

consistent with GALL Report AMP XI.E3. In addition, the applicant’s program basis document 

will be revised to reflect this change. The staff’s concern described in RAI B.2.1.40-4 is 

resolved.

Based on its audit of the Inaccessible Power Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements program, and review of the applicant’s responses to 

RAIs B.2.1.40-1, B.2.1.40-2, B.2.1.40-3, and B.2.1.40-4, the staff finds that program elements 

1-6 for which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.E3.

Operating Experience. LRA Section B.2.1.40 summarizes operating experience related to the 

Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements program. The applicant stated that operating experience examples provide 

objective evidence that the applicant’s program will be effective in ensuring that intended 

function is maintained consistent with the CLB for the period of extended operation. 

A review of the applicant’s response to GL 2007-01 indicated that the applicant identified five 

cable failures. Four of the cable failures were associated with the 13 kV power feeds for 

circulating water pumps; 1A-P501, 1B-P501, and 1C-P501. Two of the four failures occurred in 

service while the other two failures were identified during testing. The remaining failure 
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occurred in the feed to the 222 transformer. All of the failures were attributed to manufacturing 

defects. As stated in the GL 2007-01 response, three of the cable failures occurred in 1995 with 

one additional failure each in 2000 and 2005. The applicant stated in the LRA that the specific 

manufacturing defects were caused by voids and impurities in the insulation coupled with 

operation in a wet environment. The applicant also stated in the LRA that there have been no 

failures of cables that are in the scope of license renewal. In accordance with the applicant’s 

GL 2007-01 response, as a result of these failures, potentially wetted cables energized at 

13.8 kV are now periodically tested. The staff also reviewed integrated inspection reports 

05000352/2008005 and 05000353/2008005, dated January 30, 2009; 05000352/2008003 and 

05000353/2008003, dated August 13, 2008; and 05000352/2010005 and 05000353/2010005,

dated January 24, 2011. In inspection report 05000352/2010005 and 05000353/2010005, the 

inspectors noted that the applicant experienced three additional cable failures associated with 

the 122 plant services transformer supply cable, the 144D technical support center transformer 

power supply cable, and the 222 plant services transformer supply cable. The inspectors also 

noted two other 13kV power supply cables identified by testing as degraded. Because of recent 

failures, the applicant planned to expedite cable replacement of known degraded cables and the 

testing of remaining cables. The three additional cable failures occurred in 2010.

The LRA references significant event notification 272, which documented how a degraded 

underground cable resulted in a phase-to-ground fault and loss of offsite power to safety-related 

busses at another plant. The applicant stated that the specific evaluation performed for LGS 

addressed several factors for cable condition monitoring. As a result of this evaluation, LGS 

identified and documented its inaccessible medium voltage cables, cable functions, and the 

associated potential consequence of failure. The evaluation also identified cable testing 

strategies and preparedness for cable replacement.

The LRA also notes that a 2009 inspection of nonsafety-related manholes identified degradation 

of supports and internal commodities because of water intrusion. The LRA states that additional 

inspections were performed for three other manholes and water intrusion was observed in them. 

The applicant stated that a dewatering plan for these four manholes, as well as the other 

40 manholes, was developed that included actions to initiate modification for sump pumps or 

other dewatering devices for manholes susceptible to water intrusion. 

The applicant also stated in the LRA that in 2010, corporatewide actions were initiated to 

identify cables subject to wetting and to assess and subsequently improve associated manhole 

configurations. The applicant further stated that corrective actions include: (1) identifying

inaccessible underground cables, (2) identifying which of these cables are in-scope for 

maintenance rule or license renewal, (3) identifying current inspection or dewatering strategy for 

underground structures and manholes, (4) developing a schedule for inspections and, if needed,

dewatering, (5) ranking cables routed in underground structures and manholes with respect to 

their safety or generation critical functions, and (6) developing a long-term plan for condition 

monitoring of safety-related or generation critical cables routed in underground structures 

considering testing, rerouting, or replacement. The applicant further stated that these corrective 

actions are currently in progress. 

During the audit, the staff walked down nonsafety manhole MH001 located in the protected 

area. A review of recent work orders (August 2010 through August 2011) for inspection of 

MH001 indicated that this manhole has a history of water intrusion and submerged cable. 
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The staff also reviewed manhole inspection results for nonsafety and safety-related manholes

within the scope of license renewal. The results of these inspections indicate that the nonsafety 

manholes within the scope of license renewal have experienced water intrusion with cables 

found submerged, requiring water to be drained from the manhole. A review of safety-related 

manhole inspection results also indicates that all in-scope safety-related manholes have 

experienced water intrusion and submerged cables. Applicant corrective actions for the 

nonsafety manholes include the installation of level transmitters to identify manhole water 

intrusion, track water intrusion rates, provide level alarms, and establish manhole pump down 

frequencies, including frequencies for in-scope nonsafety manholes (MH001 and 002). The 

staff walked down the completed level transmitter system for manhole MH001 and was provided 

level transmitter data for MH001 from September 20, 2011, to October 13, 2011. The data 

included level indications, alarm activation, and pump down results. The applicant stated that 

the level transmitter work orders have been completed and the system installation is complete 

for nonsafety-related manholes. The applicant also has initiated an action that requests 

installation of permanent sump pumps for in-scope safety-related manholes. 

The applicant has completed cable testing and established recurring task work orders (on a

2-or 3-year schedule, depending on the circuit) for testing of inaccessible medium voltage cable

within the scope of license renewal. It also has initiated an action to develop test procedures 

and implementation for low-voltage power cable within the scope of license renewal. 

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 found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

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 the program, when 

implemented, can adequately manage the effects of aging on SSCs within the scope of the 

program.

UFSAR Supplement. LRA Section A.2.1.40 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 

against the recommended description for this type of program as described in SRP-LR 

Table 3.0-1. The UFSAR supplement provided in LRA Section A.2.1.40 was revised in 

response to staff RAIs as discussed below.

In its response to RAI B.2.1.40-3, which is discussed above in the “staff evaluation,” the 

applicant stated that for clarity and alignment with the “detection of aging effects” program 

element, the UFSAR supplement provided in LRA Section A.2.1.40 and LRA Table A.5, 

Commitment No. 40, were revised to specify a cable test frequency of at least every 6 years and 

that more frequent testing may occur based on test results and operating experience. 
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The staff finds the revised UFSAR supplement acceptable because LRA Section A.2.1.40 and 

LRA Table A.5, Commitment No. 40, have been revised to include a provision that more 

frequent testing may occur based on test results consistent with GALL Report AMP XI.E3.

In its response to RAI B.2.1.40-4, which is discussed above in the “staff evaluation,” the 

applicant revised the UFSAR supplement in LRA Section A.2.1.40 and LRA Table A.5, 

Commitment No. 40 to include a provision that the inspection frequency for manholes will be 

established and performed based on water accumulation over time and event-driven 

occurrences, such as heavy rain or flooding.

The staff finds the revised UFSAR supplement acceptable because LRA Section A.2.1.40 and 

LRA Table A.5, Commitment No. 40, were revised to include a provision that the inspection 

frequency for manholes will be established and performed based on water accumulation over 

time and event-driven occurrences, such as heavy rain or flooding, consistent with GALL Report 

AMP XI.E3.

Based on its review of the LRA, and the applicant’s response to RAI B.2.1.40-3 and 

RAI B.2.1.40-4, the staff finds that the UFSAR supplement for the Inaccessible Power Cables 

Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program is consistent 

with the corresponding program description in SRP-LR Table 3.0-1.

The staff also noted that the UFSAR contains a commitment (Commitment No. 40) to implement 

the new Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements program before entering the period of extended operation for managing aging of 

applicable components.

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

February 28, 2012, is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the Inaccessible Power Cables 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). 

3.0.3.1.22 Metal Enclosed Bus 

Summary of Technical Information in the Application. LRA Section B.2.1.41 describes the new 

Metal Enclosed Bus program as consistent with GALL Report AMP XI.E4, “Metal Enclosed 

Bus.” The LRA states that the Metal Enclosed Bus program is a new program that will be used 

to manage aging of in-scope metal-enclosed bus during the period of extended operation. The 

internal portions of the bus enclosure assemblies will be inspected for cracks, corrosion, foreign 

debris, excessive dust buildup, and evidence of water intrusion. The LRA also stated that bus 

insulation will be visually inspected for signs of reduced insulation resistance, such as 

embrittlement, cracking, chipping, melting, discoloration, swelling, or surface contamination. 

The internal bus insulating supports will be visually inspected for structural integrity and signs of 

cracks. Enclosure assembly elastomers will be visually inspected for surface cracking, crazing, 
3-72

scuffing, dimensional change, shrinkage, discoloration, hardening, and loss of strength. 

Furthermore, the LRA stated that a sample of accessible bolted connections will be inspected 

for increased resistance of connection using thermography. The sample will be 20 percent of 

the accessible metal enclosed bus (MEB) bolted connection population with a maximum sample 

size of 25.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.E4. 

For the “parameters monitored or inspected,” and “detection of aging effect” program elements, 

the staff determined the need for additional information, which resulted in the issuance of RAIs, 

as discussed below.

The “parameters monitored or inspected” program element of the applicant’s AMP basis 

document states that it is consistent with the GALL Report XI.E4 AMP. It requires that a sample 

of accessible bolted connections be inspected for increased resistance using thermography, 

and not by retorquing. However, the implementing procedure for the program requires bus joint 

nuts and bolts to be retorqued. EPRI TR-104213s, “Bolted Joint Maintenance and Application 

Guide,” states that bolted joints should be inspected for evidence of overheating, signs of 

burning or discoloration, and indications of loose bolts. The bolts should not be retorqued, 

unless the joint either requires service or the bolts are clearly loose. Verifying the torque is not 

recommended. The torque required to turn the fastener in the tightening direction (restart 

torque) is not a good indicator of the preload once the fastener is in service. Because of 

relaxation of the parts of the joint, the final loads are likely to be lower than the installed loads. 

In addition, the applicant’s AMP basis document, as well as GALL Report AMP XI.E4, does not 

recommend retorquing. The applicant’s AMP implementation procedure is not consistent with 

the program’s AMP basis document. The GALL Report recommends measuring the connection 

resistance of bolted joints using a micro-ohmmeter. By letter dated January 30, 2012, the staff 

issued RAI B.2.1.41-1, requesting the applicant to provide technical justification of why 

retorquing of bus connections are a good engineering practice to check for bolt loosening and to 

clarify the discrepancy between the AMP’s basis document and its implementing procedure. 

In its response, dated February 28, 2012, the applicant stated that retorquing of metal enclosed

bus, bolted bus connections is not part of the LGS Metal Enclosed Bus program. The LGS 

program will perform thermography of a sample of accessible bolted connections to inspect for 

increased resistance of bus connections. To implement the Metal Enclosed Bus program, the 

applicant stated that existing maintenance procedures and work orders will be revised to 

specifically annotate included license renewal activities, acceptance criteria, and inspection 

frequency. These procedures also contain activities not part of the Metal Enclosed Bus 

program. The applicant also stated that drafted revisions to program implementing procedures 

and work orders do not include annotation of bus connection retorque for license renewal. The 

applicant further stated that a search of work order history revealed that LGS MEB joint nuts 

and bolts have not been retorqued to date. This approach is consistent with GALL Report 

AMP XI.E4 recommendations. The applicant stated that the existing maintenance procedure 

and work order steps for torque checks do not apply to MEB connections. The applicant stated 

that because bolted connection retorque has not been performed for MEB connections and is 

not part of the Metal Enclosed Bus program, technical justification of retorquing of bus 

connections is not provided. Additionally, the applicant stated that because bolted connection 

retorque has not been performed for MEB connections and is not part of the Metal Enclosed 
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Bus program, there is no discrepancy between the program basis document and the drafted, 

annotated portions of the maintenance procedure and work orders that implement the Metal 

Enclosed Bus program. 

The staff finds the applicant’s response acceptable because the applicant has confirmed that it 

has not retorqued MEB bolted connections to date. The applicant will perform thermography on 

a sample of bolted connections to inspect for increased resistance of bus connections. The 

program implementing procedures do not include bus connection retorque for license renewal. 

Additionally, the existing maintenance procedures and work orders will be revised to assure 

there will be no discrepancy between the program’s AMP basis document and the maintenance 

procedure that implement the Metal Enclosed Bus AMP. The staff’s concern described in 

RAI B.2.1.41-1 is resolved.

The “detection of aging effects” program element of the applicant’s AMP basis document states 

that a sample of the MEB accessible bolted connections in each bus section shall be inspected 

using thermography for increased resistance. The inspections are performed on all accessible 

bus sections while the bus is energized. GALL Report AMP XI.E4 recommends inspecting a 

sample of the accessible bolted connections for increased resistance using thermography or 

connection resistance measurements. The applicant provided the staff a photograph of 

thermography showing a heat source from a space heater inside an MEB. However, the 

applicant did not provide any photographs taken from outside the bus duct showing the 

temperature difference between the bus connection because of increased resistance. In 

general, keeping with the best practices, windows normally are installed on the MEB for 

thermography inspections. The metal enclosed cover and the space heater may mask the heat 

created by loosening of bus connections and the temperature differences between bus 

connections that may not be detected if windows are not installed on MEBs. By letter dated 

January 30, 2012, the staff issued RAI B.2.1.41-2, requesting the applicant to discuss the 

plant-specific operating experience with thermography taken from outside a bus duct showing 

the bus connection difference because of bolt loosening. In addition, the staff requested the 

applicant to discuss the manufacturer’s recommendation for inspecting bolted connections from 

outside a bus enclosure. The staff also requested the applicant to explain how thermography 

inspection is effective to detect bolted connection for increased resistance. 

In its response, dated February 28, 2012, the applicant stated that the operating experience for 

the MEB within the scope of license renewal is documented in LRA Appendix B, Section 

B.2.1.41, and in the Metal Enclosed Bus program basis document, element 10, “operating 

experience.” There have been no failures of the 4 kV MEBs within the scope of license renewal 

at LGS. There is no adverse trend in the associated thermography inspection results for the 

4 kV metal enclosed buses within the scope of license renewal at LGS. The applicant further 

stated that routine maintenance results do not indicate a loosening of MEB connections. Since 

there is not a thermography picture available of a loose bolted connection for LGS’s MEB, a 

picture of thermography showing a heat source from a space heater inside a MEB was provided 

during the onsite audit to demonstrate the sensitivity of the thermography equipment to detect 

heat through the metal enclosure and the emissivity of the enclosure. The applicant stated that 

there are physical location differences between the bolted connections and the electric heaters. 

An electric heater is located within a segment of the enclosure, along the outside edge. In 

contrast, bolted bus connections are located where sections of the MEB are joined together, 

both the bus and the enclosure. Therefore, electric heaters and bolted connections are not in 

the same physical location in the MEB. The applicant also stated that the heat signature for an 

electric heater shows a pinpointed heat source with decreasing temperatures as distance from 
3-74

the center increases. The heat signature for resistance for a loose connection would be 

ring-like, encircling the bolted connection for the bus bar. The heat signature for the electric 

heater would not mask or be misinterpreted as a potential degraded connection. The applicant 

stated that manufacturer’s recommendations for testing include factory tests and 

post-installation tests to ensure no damage from shipping or installation. The applicant also 

stated that the LGS themography procedure follows established industry practices for 

thermography. GALL Report AMP XI.E4 and the SRP-LR associated AMP recommendations

do not present industry operating experience to counter existing standards and methodology. 

The applicant further stated that the current thermography inspection methodology is, and will 

continue to be, effective in detecting increased resistance of bolted connections.

The staff finds the applicant’s response acceptable because the applicant has confirmed that 

plant-specific operating experience has not experienced MEB connection failures and routine 

maintenance has not indicated a loosening of MEB connections. The applicant also confirmed 

that the electric heaters and bus connections are in different physical locations. The heat 

images from the electric heaters will not mask those from the bus connections. The staff finds 

that current infrared thermography inspection from the outside of bus ducts when the bus is 

energized is used by the industry as a predictive maintenance program for inspection of MEB

connections. The staff also finds that thermography inspection is consistent with GALL Report 

AMP XI.E4. The staff’s concern described in RAI B.2.1.41-2 is resolved.

Based on its audit of the Metal Enclosed Bus program, and review of the applicant’s responses 

to RAIs B.2.1.41-1 and B.2.1.41-2, the staff finds that program elements 1 to 6 for which the 

applicant claimed consistency with the GALL Report are consistent with the corresponding 

program elements of GALL Report AMP XI.E4. 

Operating Experience. LRA Section B.2.1.41 summarizes operating experience related to the 

Metal Enclosed Bus program. The applicant stated that in October 2002, a nuclear event report 

was issued to Exelon stations for an isophase bus duct insulator failure at another plant. The 

cause was identified as internal arcing. Fleetwide corrective actions included implementation of 

hi-pot testing of isophase and nonsegregated metal enclosed buses every 6 years. The 

applicant also stated that in February 2009, LGS performed an evaluation of industry operating 

experience for nonsegregated bus degradation at a pressurized-water reactor (PWR). This 

operating experience item was issued as a result of corrosion found during bus bar inspection.

The PWR plant investigation identified that the lack of periodic visual inspections allowed for 

water intrusion that resulted in degradation and corrosion. The LGS evaluation for applicability 

identified that previously initiated corporatewide corrective actions for the nuclear event report

already had ensured implementation of prudent MEB condition monitoring. 

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 found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.
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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 the program, 

when implemented, can adequately manage the effects of aging on SSCs within the scope of 

the program. 

UFSAR Supplement. LRA Section A.2.1.41 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 UFSAR supplement contains a commitment (Commitment No. 41) to 

implement the Metal Enclosed Bus program before entering the period of extended operation for 

managing 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 audit and review of the Metal Enclosed Bus 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).

3.0.3.1.23 Fuse Holders

Summary of Technical Information in the Application. LRA Section B.2.1.42 describes the new 

Fuse Holders program as consistent with GALL Report AMP XI.E5, “Fuse Holders.” The LRA 

states that the Fuse Holders program applies to fuse holders located outside of active devices 

that have been identified as susceptible to aging effects. Fuse holders located inside an active 

device are not within the scope of this program. The program will be used to manage aging of 

the metallic portions of fuse holders. Stressors managed by this program include frequent 

manipulation, vibration, chemical contamination, corrosion, oxidation, ohmic heating, thermal 

cycling, and electrical transients. The LRA also states that fuse holders subject to increased 

resistance of connection or fatigue, will be tested by a proven test methodology at least once 

every 10 years for indications of aging degradation. Visual inspection is not part of this 

program. The new Fuse Holders program will be implemented before the period of extended 

operation. In addition, the first tests 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 1-6 of the applicant’s program to the 

corresponding elements of GALL Report AMP XI.E5. 

Based on its audit, the staff finds that program elements 1-6 for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.E5. 

Operating Experience. LRA Section B.2.1.42 summarizes operating experience related to the 

Fuse Holders program. The applicant stated that in April 2004, a LGS Unit 2 drywell cooler 

drain flow high alarm was received several times. Drywell leakage was confirmed to remain 
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within normal technical specification limits. Investigation identified a defective fuse holder clip. 

The fuse holder clip was not providing enough force to make good contact with the fuse. The 

fuse holder clip was repaired, a post-maintenance test was completed with satisfactory results, 

and the intermittent alarm ceased. 

The applicant also stated that in March 2005, main control room indication for a LGS Unit 2 

high-pressure coolant injection (HPCI) suppression pool suction valve was lost. 

Troubleshooting determined that the lost indication may have been because of a fuse failure. 

The inspection identified a failed fuse block. The lug to leaf joint rivet of the fuse block was 

deformed. The fuse block was replaced and the component was satisfactorily tested. 

The applicant further stated that in October 2009, a LGS Unit 1 reactor enclosure ventilation 

exhaust radiation monitor alarmed downscale, which resulted in partial containment isolation. 

After immediate procedural actions, an investigation determined that downscale indication was 

the result of a broken fuse holder, specifically the Bakelite insulating material. The holder had 

fractured releasing tension on the fuse, thus preventing electrical contact. The fuse holder, 

insulating, and metallic parts did not exhibit any discoloration or signs of heating. Subsequent 

analysis of the fuse holder attributed the failure to tool marks found adjacent to the 

circumferential fracture. Long-term spring force against the fuse and exercising the fuse holder 

resulted in failure. The investigation concluded that this damage occurred during initial 

installation or at the manufacturer’s facility. The extent of condition evaluations found another 

damaged (i.e., chipped) fuse holder that has been scheduled for replacement. 

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 found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

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 the program, when 

implemented, can adequately manage the effects of aging on SSCs within the scope of the 

program. 

UFSAR Supplement. LRA Section A.2.1.42 provides the UFSAR supplement for the Fuse 

Holders 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 UFSAR supplement contains a commitment (Commitment No. 42) to 

implement the new Fuse Holders program before entering the period of extended operation for 

managing aging of 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 Fuse Holder 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).

3.0.3.1.24 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements

Summary of Technical Information in the Application. LRA Section B.2.1.43 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 

applicant stated that the program will implement one-time testing of a representative sample of 

non-EQ electrical cable connections to ensure that either increased resistance of connection 

does not occur or that the existing preventive maintenance program is effective such that a 

periodic inspection program is not required. The new Electrical Cable Connections Not Subject 

to 10 CFR 50.49 Environmental Qualification Requirements program will be implemented 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 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.E6. 

Based on its audit of the Electrical Cable Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements program, the staff finds that program elements 1-6

for which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.E6. 

 

Operating Experience. LRA Section B.2.1.43 summarizes operating experience related to the 

Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements program. The applicant stated that in May 2009, elevated temperatures were 

found during routine thermography on the incoming “B” phase wire to a LGS Unit 1 SLC tank 

heating element breaker. Troubleshooting identified that the terminal block screw was stripped. 

The screw was replaced and subsequent thermography confirmed a reduction in temperature, 

yet the connection required additional action since the delta between “B” phase connection 

temperature and “A” or “C” phase connection temperatures exceeded condition monitoring 

thresholds. Increased frequency thermography is being performed to monitor the connection 

until incoming leads are repaired or replaced. Repair and replacement work is planned and 

scheduled. 

The applicant also stated that in September 2009, elevated temperatures were found during 

routine thermography on the incoming “A” and “B” phase wires to a LGS Unit 2 drywell area unit 

cooler breaker. Similarly, in January 2010, elevated temperatures were found during routine 

thermography on the incoming “A” phase wire to another LGS Unit 2 drywell area unit cooler 

breaker. Also, in February 2010, elevated temperatures were found during routine 

thermography on the incoming “B” phase wire to a LGS Unit 1 RHR pump room cooler breaker. 
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During investigation of the connections, leads were tightened. Post-maintenance thermography 

connection temperatures were acceptable; no further action was warranted. 

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 found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

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 the program, when 

implemented, can adequately manage the effects of aging on SSCs within the scope of the 

program. 

UFSAR Supplement. LRA Section A.2.1.43 provides the UFSAR supplement for the Electrical 

Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements

program. The staff reviewed the 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 UFSAR contains a commitment (Commitment No. 43) to implement the new Electrical 

Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements 

program before entering the period of extended operation for managing 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 audit and review of the 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).

3.0.3.1.25 Environmental Qualification (EQ) of Electric Components

Summary of Technical Information in the Application. LRA Section B.3.1.2 describes the 

existing Environmental Qualification (EQ) of Electric Components program as consistent with 

GALL Report AMP X.E1, “Environmental Qualification (EQ) of Electric Components.” The 

applicant stated that the program establishes, demonstrates, and documents the level of 

qualification, qualified configurations, maintenance, surveillance, and component replacements 

necessary to meet 10 CFR 50.49. The applicant also stated that the program includes electric 
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equipment important to safety that is subject to adverse environment caused by heat, radiation, 

oxygen, moisture, or voltage.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding elements of GALL Report AMP X.E1. 

Based on its audit, the staff finds that program elements 1-6 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.3.1.2 summarizes operating experience related to the

Environmental Qualification (EQ) of Electric Components program. The applicant stated that in 

August 2005, during increased frequency stroking of LGS Unit 2 CS pump unit cooler valves, 

the applicant identified that a valve would not open fully. To maintain area temperatures 

assumed in EQ analyses, the applicant placed a redundant cooler into service to maintain EQ

temperatures for the associated CS pump. Corrective actions subsequently returned the cooler 

valve 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.

During its review, the staff found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program that demonstrates it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.3.1.2 provides the UFSAR supplement for the 

Environmental Qualification (EQ) of Electric 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 Section 4.4.3.2. 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 Environmental Qualification (EQ) 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).
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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:

 • BWR CRD Return Line Nozzle (B.2.1.6)

 • BWR Vessel Internals (B.2.1.9)

 • Bolting Integrity (B.2.1.11)

 • Open-Cycle Cooling Water System (B.2.1.12)

 • Closed Treated Water Systems (B.2.1.13)

 • Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems (B.2.1.14)

 • Fire Protection (B.2.1.17)

 • Fire Water System (B.2.1.18)

 • Aboveground Metallic Tanks (B.2.1.19)

 • Fuel Oil Chemistry (B.2.1.20)

 • Monitoring of Neutron-Absorbing Materials Other than Boraflex (B.2.1.28)

 • Buried and Underground Piping and Tanks (B.2.1.29)

 • ASME Code Section XI, Subsection IWE (B.2.1.30)

 • ASME Code Section XI, Subsection IWL (B.2.1.31)

 • ASME Code Section XI, Subsection IWF (B.2.1.32)

 • Masonry Walls (B.2.1.34)

 • Structures Monitoring (B.2.1.35)

 • RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants”

(B.2.1.36)

 • Protective Coating Monitoring and Maintenance Program (B.2.1.37)

 • Fatigue Monitoring (B.3.1.1)

For AMPs that the applicant claimed are consistent with the GALL Report, with 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 enhancements to determine if 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.

3.0.3.2.1 BWR Control Rod Drive Return Line Nozzle

Summary of Technical Information in the Application. LRA Section B.2.1.6 describes the 

existing BWR CRD Return Line Nozzle program as consistent, with an enhancement, with 

GALL Report AMP XI.M6, “BWR Control Rod Drive Return Line Nozzle.” 
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The LRA states that the AMP addresses the control rod drive return line (CRDRL) nozzle 

exposed to reactor coolant to manage the effects of cracking. The LRA also states that the 

AMP proposes to manage this aging effect through ISI examinations, which include volumetric 

ultrasonic test examination of the CRDRL nozzles. 

The applicant stated that modifications were implemented on LGS Units 1 and 2 based on

recommendations in NUREG-0619, “BWR Feedwater Nozzle and Control Rod Drive Return 

Line Nozzle Cracking,” to mitigate cracking because of thermal fatigue, in which the CRDRL 

nozzle was capped and the CRD return line to the reactor vessel was removed as part of the 

original plant design. Therefore, augmented inspections recommended by NUREG-0619 are 

not applicable. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M6.

The staff reviewed NUREG-0991, “Safety-Report Related to the Operation of Limerick 

Generating Station, Units 1 and 2,” and confirmed that the modifications to the CRDRL nozzle 

were reviewed and approved by the staff during initial licensing, which is consistent with the 

recommendations of NUREG-0619. By letter dated September 2, 1982, Philadelphia Electric 

Company submitted a description for the implementation of NUREG-0619 for LGS Units 1 and 2 

that included the elimination of the return line and RPV nozzle from the design of the CRD

system. 

In addition, in response to modifications to the control rod system described in NUREG-0619, 

Philadelphia Electric Company stated, in the aforementioned letter, that equalizing valves are 

included between the cooling water header and the normal drive movement header, the normal 

drive movement exhaust water header is a stainless steel line and, as such, flush ports are not 

required, and the flow stabilizer loop is stainless steel, which is routed directly into the cooling 

water header. As described in Section 4.6 of NUREG-0991, “Safety Evaluation Report related 

to the operation of Limerick Generating Station Units 1 and 2,” the applicant’s configuration of 

the CRD system meets the guidelines in NUREG-0619.

The staff noted that the recommendations of GALL Report AMP XI.M6 for inspection of the 

CRDRL nozzle-to-cap weld are provided in ASME Code, Section XI, Table IWB-2500-1. 

However, LRA Section B.2.1.6 states that the CRDRL nozzle-to-cap weld examinations are 

performed at a frequency specified in its BWR Stress Corrosion Cracking program that 

implements commitments from GL 88-01 and BWRVIP-75-A. 

In the final safety evaluation of BWRVIP-75, dated May 14, 2002, the staff concluded that the 

revised BWRVIP-75 guidance is acceptable for applicant referencing as the technical basis for 

relief from, or as an alternative to, the ASME Code Section XI and 10 CFR 50.55a 

requirements, in order to use the sample schedules and frequencies specified in the revised 

BWRVIP-75 report that are less than those that ASME Code, Section XI, requires. 

The staff finds it acceptable that the applicant credits its BWR Stress Corrosion Cracking 

program and BWRVIP-75-A to manage cracking of the CRD nozzle-to-cap weld because the 

applicant is required to apply for relief from the ASME Code Section XI and 10 CFR 50.55a in 

accordance with 10 CFR 50.55a(a)(3). The staff has approved the technical basis in 
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BWRVIP-75-A and the use of the sample schedules and frequencies specified in this report,

which are less than those that the ASME Code requires. During its audit, the staff confirmed 

that unless the applicant receives relief in accordance with 10 CFR 50.55a(a)(3), the inspections 

of the CRD inner radius, nozzle-to-vessel weld and nozzle-to-cap weld will be performed in 

accordance with ASME Code, Section XI, Table IWB-2500-1, consistent with GALL Report 

AMP XI.M6. 

The staff also reviewed the portions of the “detection of aging effects” program element 

associated with the enhancement to determine if the program will be adequate to manage the 

aging effects for which it is credited. The staff’s evaluation of this enhancement follows.

Enhancement. LRA Section B.2.1.6 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant states that the program will specify an 

extended volumetric inspection of the nozzle-to-cap weld to ensure that the inspection includes 

base metal to a distance of one pipe wall thickness or 0.5 inches, whichever is greater, on both 

sides of the weld, before the period of extended operation. 

The “detection of aging effects” program element of GALL Report AMP XI.M6 states that the

inspection is to include base metal to a distance of one pipe wall thickness or 0.5 inches, 

whichever is greater, on both sides of the weld.

The staff reviewed Section 8.2 of NUREG-0619 and noted that the plant-specific requirement for 

an extended volumetric inspection that includes the base metal to a distance of one pipe wall 

thickness or 0.5 inches, whichever is greater, on both sides of the weld, is only applicable to 

those licensees that have cut and capped the CRDRL nozzle with rerouting of the CRDRL. As 

described above, and in NUREG-0991, the applicant cut and capped the CRDRL nozzle and did 

not reroute the CRDRL; therefore, this requirement was not applicable to the applicant for its 

CLB. The staff noted that the inspections specified in ASME Code, Section XI, 

Table IWB-2500-1, are required by the applicant for the CLB for the CRDRL nozzle and 

associated welds.

The staff reviewed this enhancement against the corresponding program element in GALL 

Report AMP XI.M6 and finds it acceptable because when it is implemented, the applicant will be 

performing its volumetric inspection of the nozzle-to-cap weld consistent with the 

recommendations of GALL Report AMP XI.M6 and NUREG-0619. This will include base metal 

to a distance of one pipe wall thickness or 0.5 inches, whichever is greater, on both sides of the 

weld. In addition, when the applicant’s program is enhanced before the period of extended 

operation, the inspections of the nozzle-to-cap weld will be beyond the recommendations

specified in NUREG-0619 for licensees that cut and capped the CRDRL nozzle without 

rerouting the CRDRL.

Based on its audit of the BWR CRD Return Line Nozzle program, the staff finds that program 

elements 1-6 for which the applicant claimed consistency with the GALL Report are consistent 

with the corresponding program elements of GALL Report AMP XI.M6. In addition, the staff 

reviewed the enhancement associated with the “detection of aging effects” program element 

and finds that when implemented it will make the AMP adequate to manage the applicable 

aging effects.

Operating Experience. LRA Section B.2.1.6 summarizes operating experience related to the 

BWR CRD Return Line Nozzle program. The staff noted that a crack was identified in the LGS 
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Unit 1 recirculation inlet nozzle-to-safe end weld in the Alloy 182 to Alloy 82 weld interface in 

the 1988 refueling outage. The applicant identified that the LGS Unit 1 CRDRL nozzle also has 

Alloy 182 to Alloy 82 weld interface between the nozzle and the cap; therefore, it performed 

MSIP on the nozzle-to-cap weld on the LGS Unit 1 CRDRL nozzle in 1994. In addition, since 

LGS Unit 2 was not in operation at the time, the CRDRL nozzle was modified to eliminate the 

Alloy 182 to Alloy 82 weld interfaces in contact with the reactor coolant by adding an Alloy 82 

overlay over the Alloy 182 to Alloy 82 weld between the nozzle and cap. The staff noted that 

this resulted in the Alloy 182 to Alloy 82 dissimilar weld not being in contact with reactor coolant, 

thereby minimizing the probability of cracking in the nozzle-to-cap weld.

During its audit, the staff reviewed the applicant’s results for LGS Unit 1 from 1992, 1998,

and 2008, and for LGS, Unit 2 from 1995 and 2005. The staff confirmed that the inspections 

were performed in accordance with ASME Code Section XI, Table IWB-2500-1, and that there 

were no recordable indications for the CRD inner radius, nozzle-to-vessel weld, and 

nozzle-to-cap weld.

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.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.6 provides the UFSAR supplement for the BWR CRD

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 UFSAR supplement contains a commitment (Commitment No. 6) to 

enhance the existing BWR CRD Return Line Nozzle program to specify an extended volumetric 

inspection of the nozzle-to-cap weld to ensure that the inspection includes base metal to a 

distance of one pipe wall thickness or 0.5 inches, whichever is greater, on both sides of the weld 

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 BWR CRD Return Line Nozzle program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. Also, the staff reviewed the enhancement and confirmed 

that its implementation will make the AMP adequate to manage the applicable aging effects and 

that the UFSAR contained Commitment No. 6 to implement the enhancement before the period 

of extended operation. 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 
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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).

3.0.3.2.2 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 applicant stated that this program includes 

inspection, flaw evaluation, and repair guidelines consistent with the guidelines addressed in 

relevant BWRVIP reports. The applicant further stated that water chemistry guidelines per the 

Water Chemistry program, B.2.1.2, will help to ensure the integrity of the RVIs components. 

The BWR Vessel Internals program is an existing program that is consistent with AMP XI.M9, 

“BWR Vessel Internals,” as specified in the GALL Report. No exceptions are taken by the 

applicant; there are three enhancements. The first two enhancements affect the program 

scope, in which the applicant states that it will perform assessments of CASS components for 

susceptibility to thermal and neutron embrittlement. The third enhancement is related to the 

parameters monitored and detection of the aging effect in which the applicant specifies the 

inspection methods and schedule for those CASS components identified in the first two 

enhancements.

The applicant provided information on plant operating experience in which it stated that 

inspections were performed on core shroud, core plate, shroud support, low-pressure coolant 

injection (LPCI) coupling, CS, jet pumps, top guide, CRD housings, lower plenum, steam dryer, 

and access hole covers. The applicant further stated that it evaluated the indications found so

far in these reactor vessel internal components and accepted them based on the applicable 

BWRVIP inspection guidelines. The applicant reiterated that it complied with the inspections 

and flaw evaluation guidelines specified in the applicable BWRVIP reports. Further, it would 

continue to implement these guidelines to ensure the structural integrity and functionality of 

these components during the extended period of operation. 

In the applicant’s February 15, 2012, response to RAI BWRVIP-1, the applicant added 

Appendix C, which lists the following BWRVIP reports that would be implemented by the 

applicant’s AMP and have action items for license renewal:

 • BWRVIP-18, “BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines 

(Revision 1)”

 • BWRVIP-25, “BWR Core Plate Inspection and Flaw Evaluation Guidelines”

 • BWRVIP-26-A, “BWR Top Guide 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 2)”

 • BWRVIP-42-A, “BWR LPCI Coupling Inspection and Flaw Evaluation Guidelines”

 • BWRVIP-47-A, “BWR Lower Plenum Inspection and Flaw Evaluation Guidelines”
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 • BWRVIP-48-A, “BWR Vessel ID Attachment Weld Inspection and Flaw Evaluation 

Guidelines”

 • BWRVIP-49-A, “BWR Instrument Penetration Inspection and Flaw Evaluation Guidelines”

 • BWRVIP-74-A, “BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines

for License Renewal”

 • BWRVIP-76-A, “BWR Core Shroud Inspection and Flaw Evaluation Guidelines”

In Appendix C, the applicant included three license renewal action items applicable to all 

BWRVIP reports and several other license renewal action items applicable to specific BWRVIP 

reports. In addition, Appendix C addresses the applicant’s response to the license renewal 

action items. The staff included the license renewal action items, the applicant’s response, and 

its evaluation in the staff evaluation section for this AMP.

Staff Evaluation. During the audit, the staff reviewed the LRA Section B.2.1.9 and compared 

program elements 1-6 of the applicant’s program to the corresponding program elements of 

GALL Report AMP XI.M9. The applicant routinely inspected the reactor vessel internal 

components per the applicable BWRVIP reports, and repaired or evaluated the indications per 

the BWRVIP reports or ASME Code, Section XI requirements. The staff noted that the

applicant’s program relies on monitoring and control of reactor water chemistry based on the 

guidance of BWRVIP-190 report (EPRI-1016579). Furthermore, the applicant has noted (AMR 

item 3.1.1-99) that there are no martensitic stainless steels, such as 17-4, 15-5, or 410, included 

in the reactor vessel internal components. 

During the audit, the staff also reviewed the portions of the “scope of program” and “parameters 

monitored or inspected” program elements associated with enhancements to determine if 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 states an enhancement to the “scope of program”

element. In this enhancement, the applicant will evaluate CASS materials used for the reactor 

vessel internal components to assess the loss of fracture toughness for the material because of

thermal 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 have reviewed the certified material test record (CMRT) for each CASS 

component. If the applicant cannot demonstrate the component’s lack of susceptibility to 

thermal embrittlement or if the CMRT is not available, the component will be considered 

susceptible to thermal embrittlement.

Enhancement 2. LRA Section B.2.1.9 states an enhancement to the “scope of program”

element. In this enhancement, the applicant will evaluate CASS materials used for the reactor 

internal components to assess the loss of fracture toughness for the material because of

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 have reviewed each CASS component and the neutron exposure of the 

component for the period of extended operation. 

Enhancement 3. LRA Section B.2.1.9 states an enhancement to the “parameters monitored or 

inspected” program element. In this enhancement, the applicant stated that either before
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entering the period of extended operation or within 5 years of entering the period of extended 

operation, the applicant will have inspected all reactor vessel internal components susceptible to 

either thermal or 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 ensure that all susceptible CASS components will be inspected for 

evidence of any subcritical cracking that could cause failure because of the loss of the material’s 

fracture toughness caused by thermal or neutron embrittlement.

License Renewal Action Items Addressed in Appendix C. The LRA references several 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 safety evaluations (SEs) on the reports included a number of AAIs that were to be 

addressed as part of the basis 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.

The applicant provided the following responses to three AAIs listed in the staff’s SEs for all of 

the BWRVIP reports listed in response to RAI BWRVIP-1.

(1) LGS’s AMPs for the reactor vessel internal components are bounded by the 

aforementioned BWRVIP reports.

(2) The UFSAR supplement addresses a summary of the programs and activities specified 

in the applicable BWRVIP reports.

(3) LGS states that no technical specification changes have been identified as a result of 

implementing the AMP for the reactor vessel internal components.

The staff reviewed the applicant’s disposition for these three AAIs and concludes that the 

applicant complied with the intent of the license renewal action items the staff specified in its 

SEs for the applicable BWRVIP reports. 

In addition to the three AAIs common to each BWRVIP report listed in the applicant’s RAI 

response, the applicant provided responses to the following BWRVIP AAIs:

 • BWRVIP-18, AAI No. 4

 • BWRVIP-25, AAI Nos. 4 and 5

 • BWRVIP-26-A, AAI No. 4

 • BWRVIP-42-A, AAI Nos. 4 and 5

 • BWRVIP-47-A, AAI No. 4

 • BWRVIP-74-A, AAI Nos. 4 through 14

 • BWRVIP-76-A, AAI Nos. 4 through 8

Several of the aforementioned AAI relate to TLAAs and are discussed in SER Section 4.1.2.1.2. 

These AAI are:

 • BWRVIP-18, AAI No. 4
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 • BWRVIP-25, AAI No. 4

 • BWRVIP-26-A, AAI No. 4

 • BWRVIP-42-A, AAI No. 4

 • BWRVIP-47-A, AAI No. 4

 • BWRVIP-74-A, AAI Nos. 8 through 13

The following is the staff’s evaluation of the remainder of the BWRVIP related AAIs for license 

renewal.

BWRVIP-25, AAI No. 5 states that “until such time as an expanded technical basis for not 

inspecting the rim hold-down bolts is approved by the staff, applicants referencing the 

BWRVIP-25 report for license renewal should continue to perform inspection of the rim 

hold-down bolts.” 

The applicant’s’ response to BWRVIP-25, AAI No. 5, states that inspection of the core plate rim 

hold-down bolts will be in compliance with BWRVIP guidance before and through the period of 

extended operation. The staff reviewed the applicant’s response and found it acceptable

because the applicant agrees to inspect the core plate rim hold down bolts in accordance with

BWRVIP guidance before and through the period of extended operation. 

BWRVIP-42-A, AAI No. 5, states that “the BWRVIP committed to address development of the 

technology to inspect inaccessible welds and to have the individual LR [license renewal] 

applicant notify the NRC of actions planned. Applicant’s referencing BWRVIP-42 report for 

license renewal should identify the action as open and to be addressed once the BWRVIP’s 

response to this issue has been reviewed and accepted by the staff.” 

The applicant’s response to BWRVIP-42-A, AAI No. 5, states that inspection of the LPCI 

coupling is performed in accordance with BWRVIP guidelines and that there are no inaccessible 

welds associated with the LPCI couplings. The staff reviewed the applicant’s response and 

found it acceptable because the applicant states that there are no inaccessible welds 

associated with the LPCI couplings. 

The license renewal action items specified in the staff’s SE for the BWRVIP-74-A report, dated 

October 18, 2001, address the aging effects on the reactor vessel components. This report also 

provides requirements to effectively manage the aging effects during the extended period of 

operation. The BWRVIP-74-A report addresses the license renewal action items associated 

with TLAAs for the extended period of operation. The following paragraphs address the TLAAs 

and the AMP related to reactor vessel components specified in the BWRVIP-74-A report, the 

applicant’s responses to these license renewal action items, and the corresponding staff’s 

evaluation of each item. 

BWRVIP-74-A, AAI No. 4, states that an AMP should be identified for the vessel flange leak 

detector (VFLD) nozzle and piping. Cracking of the nozzle is managed by the ASME Code 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, and Water Chemistry 

programs. The applicant stated that it would manage cracking in the piping with the One-Time 

Inspection of ASME Code Class 1, Small-Bore Piping, Water Chemistry, and ASME Code 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD programs. The staff finds the 

applicant’s AMP acceptable for the VFLD nozzle and piping because the combination of 
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One-Time Inspection of ASME Code Class 1, Small-Bore Piping and ASME Code Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD programs will adequately identify the 

aging degradation in a timely manner and controlling water chemistry will enable the applicant to 

effectively manage the occurrence of any cracking or loss of material in VFLD nozzle and 

piping.

BWRVIP-74-A, AAI No. 5, states that the applicant should describe how each plant-specific 

AMP addresses the 10 elements listed in GALL Report AMP XI.M9. The applicant’s response 

stated that there are no plant-specific AMPs credited for managing aging of RPV components 

and that descriptions of the AMPs credited for managing RPV components are described in 

Appendix B of the LRA. The staff reviewed Appendix B and finds the applicant’s response 

acceptable because Appendix B adequately addresses the 10 elements of the GALL Report 

AMP. 

BWRVIP-74-A, AAI No. 6, recommends that the applicant include a water chemistry program in 

its LRA to ensure that it can effectively manage IGSCC in the RCS systems. In its response, 

the applicant stated that it would comply with the BWRVIP-190 report, which superseded the 

BWRVIP-29 report. The staff finds this response acceptable because the applicant’s 

compliance with the requirements of BWRVIP-190 provides adequate mitigation to the 

occurrence of IGSCC.

BWRVIP-74-A, AAI No. 7 recommends that the applicant identify its RPV surveillance program. 

The applicant stated that it has implemented the staff-approved BWRVIP ISP, BWRVIP-86-A, 

“BWR Vessel and Internals Project BWR Integrated Surveillance Program Implementation 

Plan,” for the current license period and BWRVIP-116, “BWR Vessel and Internals Project 

Integrated Surveillance Program” for the period of extended operation. Compliance with the 

staff-approved ISPs enables the applicant to effectively monitor neutron embrittlement of the 

RPV materials; therefore, the staff finds this response acceptable.

BWRVIP-74-A, AAI No. 14, recommends that components that have indications previously 

evaluated analytically, in accordance with Subsection IWB-3600 of the ASME Code, Section XI,

until the end of the 40-year service period, shall be re-evaluated for the 60-year service period 

corresponding to the license renewal term. The applicant stated that a flaw was discovered in 

the LGS Unit 1 RPV nozzle to safe-end weld VRR-IRD-1A-N2H that was evaluated in 

accordance with ASME Code Section XI, Subsection IWB-3600. The UFSAR supplement 

contains a commitment (Commitment No. 47) to re-evaluate this condition before the period of 

extended operation. Furthermore, the applicant states that any subsequent flaw evaluations 

performed on other RPV components will be evaluated for the period of extended operation. 

The staff finds this response acceptable because the effects of aging on the intended function of 

the nozzle to safe-end weld will be adequately managed for the period of extended operation.

BWRVIP-76-A, AAI No. 4, recommends applicants incorporate BWRVIP-14-A, BWRVIP-99-A, 

and BWRVIP-100-A report-specific crack growth rate evaluations and fracture toughness values 

for cracked core shroud welds exposed to neutron fluence values specified in the relevant 

reports. The applicant also should confirm that any emerging inspection guidelines developed 

by the BWRVIP for these welds will be incorporated. The applicant’s response includes the 

specific wording for AAI No. 4 to use current NRC-approved BWRVIP guidance for core shroud 

weld flaw evaluations and to incorporate any new approved guidance as it becomes available. 

Compliance with the staff-approved BWRVIP reports enables the applicant to effectively monitor 
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crack growth in the core shroud welds; therefore, the staff finds the applicant’s response 

acceptable.

BWRVIP-76-A, No. AAI 5 states that license renewal applicants that have core shrouds with tie 

rod repairs shall make a statement in its program associated with reactor vessel internal 

components that they have evaluated the implications of the Hatch Unit 1 tie rod repair cracking 

on its units and incorporate revised inspection guidelines, if any, developed by the BWRVIP. 

The staff reviewed the applicant’s response to BWRVIP-76-A, AAI No. 5 and finds it acceptable 

because the applicant states that there are no tie rod repairs in the core shrouds for LGS 

Units 1 and 2. 

BWRVIP-76-A, AAI No. 6, recommends that the applicant identify the aging effects for the core 

shrouds and core shroud assembly components if a repair design modification has been 

implemented, and identify the specific AMPs or TLAAs that will be used to manage these effects 

for the period of extended operation. The applicant has responded that the core shrouds at 

LGS Units 1 and 2 are made from stainless steel and nickel alloy that are susceptible to 

cracking, loss of material because of pitting and crevice corrosion, and cumulative fatigue 

damage. No core shroud repairs have been done as stated in the response to AAI No. 5. The 

BWR Vessel Internals and Water Chemistry AMPs will be used to manage loss of material 

because of pitting and crevice corrosion during the period of extended operation. The staff has 

reviewed the applicant’s AMR for item 3.1.1-43 and finds the applicant’s aging management 

plan acceptable because it follows the guidelines recommended by the BWRVIP, which are 

often more stringent than those inspections specified by ASME Code Section XI, and include 

specific flaw evaluation and repair recommendations to facilitate post-inspection review; and the 

applicant’s use of the Water Chemistry program creates an environment not conducive for loss 

of material to occur and is consistent with the recommendations of the GALL Report. LRA 

Section 4.3.4 discusses the applicant’s TLAA for cumulative fatigue damage. The staff 

evaluated the TLAA associated with the core shroud cumulative fatigue damage for LGS Units 1 

and 2 in SER Section 4.3.4.

BWRVIP-76-A, AAI No. 7 recommends that the applicant identify any core shroud or core 

shroud repair assembly components manufactured from materials other than stainless steel or 

nickel alloy and any aging effects that will require management for the period of extended 

operation. The applicant has responded that all of the materials in the core shroud and core 

shroud repair assembly components are made from stainless steel or nickel alloy. Therefore, 

no additional aging effects need to be addressed. The staff reviewed the applicant’s response 

to AAI No. 7 in BWRVIP-76-A and finds it acceptable because the applicant states that there are 

no other materials included in the core shroud and core shroud repair assembly components at 

LGS Units 1 and 2.

BWRVIP-76-A, AAI No. 8 recommends that the applicant reference the staff-approved topical 

reports, BWRVIP-99 and BWRVIP-100-A, in its BWR Vessels Internals program. The applicant 

responded that the BWR Vessels Internals program at LGS Units 1 and 2 use BWRVIP-14-A 

and BWRVIP-99-A for crack growth rates and BWRVIP-100-A for fracture toughness values. 

The staff reviewed the applicant’s response to AAI No. 7 in BWRVIP-76-A and finds it 

acceptable because the applicant states that its AMPs implement the BWRVIP-76-A 

requirements.

Based on its audit of the BWR Vessel Internals program, the staff finds that program elements 

1-6 for which the applicant claimed consistency with the GALL Report are consistent with the 
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corresponding program elements of GALL Report AMP XI.M9. In addition, the staff reviewed 

the enhancements associated with the “scope of program” and “parameters monitored or 

inspected” program elements and finds that when implemented the enhancements will make the 

AMP adequate to manage the applicable aging effects.

Operating Experience. The staff reviewed the applicant’s “operating experience” program 

element discussions in the BWR Vessel Internals program and in the license renewal basis 

document for this program. The staff noted that the applicant has identified relevant 

plant-specific operating experience in the “operating experience” program element discussion 

for the BWR Vessels Internals program. Flaw indications have been found in the core shroud 

welds, CS spargers, steam dryer, and some of the jet pump assembly components (i.e., jet 

pump yoke to riser pipe weld, hold-down beam, and set screw tack welds). Wear on the slip 

joint clamp and set screw gaps was documented through video of the visual inspections. The 

staff also observed that the applicant has dispositioned the core shroud welds, steam dryer, and 

CS sparger weld flaw indications as acceptable (i.e., “as-is”) for further service without the need 

for repair or replacement of the components at this time. Auxiliary wedges and slip joint clamps 

were installed to stabilize the location against future crack growth and replace the function of the 

set screw. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.1.2.9 provides the UFSAR supplement summary 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 UFSAR supplement also contains a commitment (Commitment 

No. 9) to enhance the existing BWR Vessel Internals program to: (1) evaluate CASS materials 

used for the reactor vessel internal components to assess the loss of fracture toughness for the 

material because of thermal embrittlement, (2) evaluate CASS materials used for the reactor 

internal components to assess the loss of fracture toughness for the material because of 

neutron embrittlement, and (3) inspect all reactor vessel internal components susceptible to 

either thermal or neutron embrittlement either before entering the period of extended operation 

or within 5 years of entering 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 BWR Vessel Internals program, the staff 

determines that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that 

their implementation will make the AMP adequate to manage the applicable aging effects and 

that the UFSAR contained Commitment No. 9 to implement the enhancements before the 

period of extended operation. 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 
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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).

3.0.3.2.3 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 program includes management of loss 

of material and loss of preload for pressure-retaining bolted joints by performing visual 

inspections for leakage. The LRA also states that the program includes preventive measures to 

ensure only approved lubricants and sealants and proper torque are applied. The program 

incorporates NRC and industry recommendations delineated in NUREG-1339, “Resolution of 

Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants,” EPRI 

TR-104213, “Bolted Joint Maintenance and Applications Guide,” and EPRI NP-5769, 

“Degradation and Failure of Bolting in Nuclear Power Plants.”

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M18. For the “preventive actions”

and “parameters monitored or inspected” program elements, the staff determined the need for 

additional information, which resulted in the issuance of RAIs, as discussed below.

GALL Report AMP XI.M18 recommends that the program include periodic inspections of closure 

bolting for loss of material, loss of preload, and cracking, as well as preventive measures to 

minimize loss of preload and cracking. The “preventive actions” program element of GALL 

Report AMP XI.M18 recommends that the preventive measures to minimize cracking include 

not using lubricants that contain MoS2 and not using highstrength bolting materials. LRA 

Section B.2.1.11 states that high-strength bolts are not used on pressure-retaining bolted joints 

within the scope of the program and that station procedures ensure that lubricants containing 

MoS2 are not used. However, the program does not state that it manages cracking and does 

not include inspections for cracking. By letter dated January 17, 2012, the staff issued 

RAI B.2.1.11-1 requesting the applicant to clarify if cracking is an aging effect being managed 

by the Bolting Integrity program and either revise the LRA description of the program and the 

UFSAR supplement to include management of cracking or justify the exception to the GALL 

Report AMP.

In its response, dated February 15, 2012, the applicant stated that cracking is an aging effect 

managed by the Bolting Integrity program. The applicant revised the LRA to state that the 

program manages cracking and that safety-related pressure-retaining bolting that is not high 

strength is visually inspected for leakage, loss of material, cracking, and loss of preload at least 

once per refueling cycle. The applicant also stated that high-strength bolting, if used, will be 

monitored for cracking. The applicant further stated that other pressure-retaining bolting is 

inspected for leakage that could result from cracking. The staff finds the applicant’s response 

acceptable because the program has been revised to include periodic inspections of 

pressure-retaining bolting for cracking, consistent with the GALL Report recommendations.

The “parameters monitored or inspected” program element of GALL Report AMP XI.M18, states 

that bolting for safety-related pressure-retaining components should be inspected for leakage as 

well as loss of material, cracking, and loss of preload. LRA Section B.2.1.11 states that the 
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program will manage loss of material and loss of preload using visual inspections for 

pressure-retaining bolted joint leakage. The LRA does not state that inspections will be 

performed for other indications of loss of material (such as corrosion or rust), cracking, or loss of 

preload (such as loose or missing bolts). By letter dated January 17, 2012, the staff issued 

RAI B.2.1.11-2 requesting the applicant to clarify if the inspections performed by the Bolting 

Integrity program include inspections for other indications of loss of material, cracking, and loss 

of preload and either revise the LRA description of the program and the UFSAR supplement to 

include this information or justify the exception to the GALL Report AMP.

In its response, dated February 15, 2012, the applicant stated that safety-related 

pressure-retaining bolting is visually inspected for leakage, loss of material, cracking, and loss 

of preload at least once per refueling cycle. The applicant also stated that other 

pressure-retaining bolting is inspected for leakage. The staff finds the applicant’s response 

acceptable because the program has been revised to include periodic inspections of 

safety-related pressure-retaining bolting for loss of material, cracking, and loss of preload, 

consistent with the GALL Report recommendations.

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 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.2.1.11 states an enhancement to the “preventive actions,”

“detection of aging effects,” and “corrective actions” program elements. In this enhancement, 

the LRA states that guidance will be provided to ensure proper specification of bolting material, 

lubricants and sealants, storage, and installation torque or tension to prevent or mitigate 

degradation or failure of closure bolting. GALL Report AMP XI.M18 states that selection of 

bolting materials, lubricants, and sealants should be in accordance with EPRI NP-5769 and 

NUREG-1339, and that maintenance practices should include application of proper preload 

based on EPRI documents, manufacturer recommendations, or engineering evaluations. 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, it will make the program 

consistent with the recommendations in the GALL Report AMP by ensuring that proper 

specifications are used.

Enhancement 2. LRA Section B.2.1.11 states an enhancement to the “preventive actions”

program element. In this enhancement, the applicant stated that it will prohibit the use of 

lubricants containing MoS2 for closure bolting. GALL Report AMP XI.M18 states that lubricants 

containing MoS2 have been shown to contribute to SCC and should not be used. 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, it will make the program 

consistent with the recommendations in the GALL Report AMP.

Enhancement 3. LRA Section B.2.1.11 states an enhancement to the “preventive actions,”

“parameters monitored or inspected,” and “detection of aging effects” program elements. In this 

enhancement, the applicant stated that it will minimize the use of high-strength closure bolting, 

and, if used, it will be monitored for cracking. GALL Report AMP XI.M18 states that bolting 

material should be limited to an actual measured yield strength of 1,034 MPa (150 ksi) and 

high-strength closure bolting (with yield strength greater than 1,034 MPa or 150 ksi) should be 

monitored for cracking if used. The staff reviewed this enhancement against the corresponding 
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program elements in GALL Report AMP XI.M18 and finds it acceptable because when it is 

implemented, it will make the program consistent with the recommendations in the GALL Report 

AMP.

Enhancement 4. By letter dated March 13, 2012, the applicant amended LRA Section B.2.1.11 

to add 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 of submerged bolting for the RHR system, CS system, HPCI system, and RCIC

system suction strainers in the suppression pool for loss of material and loss of preload during 

each ISI inspection interval. GALL Report AMP XI.M18 states that the program manages aging 

of closure bolting for pressure-retaining components within the scope of license renewal for 

aging effects, including loss of material and loss of preload. 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 visual inspections for loss of material 

and loss of preload will make the program consistent with the recommendations in the GALL 

Report AMP.

Based on its audit and review of the applicant’s responses to RAIs B.2.1.11-1 and B.2.1.11-2, 

the staff finds that the program elements 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 one operating experience example, the LRA states that an 

inspection identified a loose bolt on the EDG oil cooler discharge flange. An operability 

evaluation was performed and the loose bolt was subsequently re-tightened as required by 

design. In another operating experience example, the LRA states that one displaced nut and 

one loose nut were identified during disassembly of the reactor feed pump suction flange. The 

loose nuts were attributed to incorrect use of a torque wrench during a previous outage. A 

maintenance history review identified that another flange was disassembled during the previous 

outage. As a result, that flange was inspected to ensure proper torque was applied and it was 

found to be in acceptable condition.

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 found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.
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UFSAR Supplement. LRA Section A.2.1.11 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 UFSAR contains a commitment (Commitment No. 11), as amended by letter,

dated March 13, 2012, to enhance the program before the period of extended operation to 

provide guidance to ensure proper specification of bolting material, lubricants and sealants, 

storage, installation torque or tension; to prohibit the use of lubricants containing MoS2; and to

minimize the use of high-strength closure bolting, and, if used, monitor the high-strength bolting 

for cracking and perform visual inspection of bolting for the RHR, CS system, HPCI system, and 

RCIC system suppression pool suction strainers for loss of material and loss of preload during 

each ISI inspection interval. The staff finds the information in the UFSAR supplement, as 

amended by letter, dated March 13, 2012, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the Bolting Integrity program, the staff 

determines that the program elements for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M18. Also, the staff reviewed the enhancements and confirmed that their 

implementation will make the AMP adequate to manage the applicable aging effects and that 

the UFSAR supplement contained Commitment No. 11 to implement the enhancements before

the period of extended operation. 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).

3.0.3.2.4 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.” The LRA states that the 

program is consistent with the LGS commitments for GL 89-13, “Service Water Problems 

Affecting Safety-Related Components,” and manages piping components and heat exchangers 

exposed to raw water for loss of material, reduction of heat transfer, and loss of elastomeric 

properties through tests, visual inspections, nondestructive examinations (NDEs), and cleaning 

activities. The LRA also states that the program includes chemical and biocide injections and 

performs periodic inspections for the presence of mollusks and biofouling. The LRA further 

states that heat transfer capabilities are confirmed through periodic heat transfer testing, or 

inspection and cleaning of heat exchangers, and that polymeric materials included in this 

program are examined consistent with those described in the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M20. The staff also reviewed the 

portions of the “preventive actions,” “parameters monitored or inspected,” and “detection of 

aging effects” program elements associated with the enhancements to determine if the program 

will be adequate to manage the aging effects for which it is credited. The staff’s evaluation of 

these enhancements follows.
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Enhancement 1. LRA Section B.2.1.12 states an enhancement to the “parameters monitored or 

inspected” and the “detection of aging effects” program elements. In this enhancement, the 

applicant stated that inspections of the internal surfaces of buried safety-related SW piping will 

be performed when it is accessible during maintenance and repair activities. It was not clear to 

the staff how opportunistic inspections of the buried safety-related service water piping will be 

capable of assessing its condition before loss of intended function occurs. By letter dated 

January 17, 2012, the staff issued RAI B.2.1.12-1 requesting, in part, the applicant to provide 

the technical bases to justify how opportunistic inspection will be capable of assessing the 

condition of buried safety-related SW piping before the loss of intended function.

In its response dated February 15, 2012, the applicant stated that the internal surface of the 

buried SW piping is subject to similar process conditions as the RHRSW piping in the pipe 

tunnel, and inspection results for piping in the pipe tunnel will be applied to the buried piping. 

The applicant also stated that replacement of degraded RHRSW piping in the pipe tunnel is 

planned between 2012 and 2015, and the removed piping will be extensively examined, 

including 100 percent visual examination and ultrasonic examination at locations determined by 

the visual inspections. The response further stated that during the pipe replacement, the buried 

piping will be drained and accessible for inspection and that this opportunistic inspection of the 

buried pipe, coupled with the detailed inspection of the similar pipe removed from the pipe 

tunnel, will provide information needed to assess the potential degradation of the buried piping. 

The applicant committed (Commitment No. 12) to inspect safety-related SW system piping at a 

minimum of 10 locations each refueling outage interval, which will result in 50 inspections in

10 years. 

The staff finds the applicant’s response acceptable because: the opportunistic inspection of the 

buried piping was clarified as at least occurring during the replacement of the RHRSW piping in 

the pipe tunnel between 2012 and 2015; the detailed inspections of the piping removed during 

the replacement will provide supplemental information to assess the condition of the buried 

piping; degradation of the piping in aboveground portions of the system will be consistent with 

the buried piping given similar operating conditions (see discussion of applicant’s response in 

Enhancement 5); and the 50 inspections that will occur in each 10-year interval of the period of 

extended operation will provide sufficient timely data to allow the applicant to understand the 

condition of the internal surfaces of the buried piping. The staff’s concern described in 

RAI B.2.1.12-1, which addressed Enhancement 1, is resolved. Other aspects of RAI B.2.1.12-1 

are addressed below under “Operating Experience” and “UFSAR Supplement.” 

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP XI.M20 and finds it acceptable because when it is implemented, it will manage 

buried safety-related SW piping, such that loss of material will be detected before loss of 

intended function. The staff noted that in its response to RAI B.2.1.12-3 dated June 22, 2012, 

discussed below in “UFSAR Supplement” the applicant revised LRA Sections A.2.1.12 and 

B.2.1.12 to perform ten volumetric inspections in the safety-related portions of the SW system 

every 2 years to provide a sufficient understanding of the buried SW piping conditions. This 

does not change the finding for the closure of the concerns related to RAI B.2.1.12-1 because 

the same number of inspections will be conducted every 10-year period.

Enhancement 2. LRA Section B.2.1.12 states an enhancement to the “parameters monitored or 

inspected” and the “detection of aging effects” program elements. In this enhancement, the 

applicant stated that periodic inspections of nonsafety-related SW piping for loss of material will 
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be performed at a frequency in accordance with GL 89-13. The staff noted that GL 89-13 does 

not specify inspection frequencies for loss of material and the applicant’s responses to that GL

did not provide specific inspection frequencies for loss of material. By letter dated 

January 17, 2012, the staff issued RAI B.2.1.12-2 requesting the applicant to describe the

number, frequency, and locations of inspections for nonsafety-related SW system. 

In its response dated February 15, 2012, the applicant revised LRA Sections A.2.1.12, B.2.1.12,

and Appendix A.5 to state that the nonsafety-related SW system will be inspected at a minimum 

of five locations on each unit once every refueling cycle. In addition, the applicant stated that 

the specific locations for these inspections are determined based on susceptibility to aging 

effects to ensure that loss of material will be detected before loss of intended function. The staff 

finds the response acceptable because the applicant clarified the number, frequency, and 

locations of the inspections associated with this enhancement and revised the corresponding 

sections of the LRA. The staff’s concern described in RAI B.2.1.12-2 is resolved. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.M20 and finds it acceptable because when it is implemented, this program will manage 

nonsafety-related SW piping, such that loss of material will be detected before loss of intended 

function.

Enhancement 3. As amended by letter dated February 15, 2012, LRA Section B.2.1.12 states 

an enhancement to the “preventive actions” program element. In this enhancement, the 

applicant stated that it will replace the supply and return piping for the CS pump compartment 

unit coolers with stainless steel piping before the period of extended operation. The staff 

reviewed this enhancement against the corresponding program element in GALL Report 

AMP XI.M20 and finds it acceptable because when it is implemented, it will reduce the 

susceptibility to material loss caused by corrosion.

Enhancement 4. As amended by letter dated February 15, 2012, LRA Section B.2.1.12 states 

an enhancement to the “preventive actions” program element. In this enhancement, the 

applicant stated that it will replace degraded RHRSW piping in the pipe tunnel before the period 

of extended operation. The staff reviewed this enhancement against the corresponding 

program element in GALL Report AMP XI.M20 and finds it acceptable because when it is 

implemented, it will reduce the susceptibility to material loss caused by corrosion.

Enhancement 5. As amended by letter dated June 22, 2012, LRA Section B.2.1.12 states an 

enhancement to the “parameters monitored or inspected” and the “detection of aging effects” 

program elements. In this enhancement, the applicant stated that it will perform periodic 

inspections for loss of material in the safety-related SW system at a minimum of ten locations 

every 2 years. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.M20 and finds it acceptable because when it is implemented,

it will provide sufficient timely data to allow the applicant to understand the condition of the 

internal surfaces of the buried piping in the SW system.

Based on its audit of the Open-Cycle Cooling Water System program, and review of the 

applicant’s responses to RAI B.2.1.12-1 and RAI B.2.1.12-2, the staff finds the program 

elements 1-6 for which the applicant claimed consistency with the GALL Report are consistent 

with the corresponding program elements of GALL Report AMP XI.M20. The staff also 

reviewed the enhancements associated with the “parameters monitored or inspected” and the 

“detection of aging effects” 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.2.1.12 summarizes operating experience related to the 

Open-Cycle Cooling Water System program. The LRA discussed the identification of three 

localized, thinned areas in the 30-inch cross-tie piping of the RHRSW system, which were found 

during the augmented inspections to address another flaw in the same system. The LRA stated 

that an evaluation of the thinned areas determined these locations met the criteria for 

operability, that re-inspections of these areas were performed on a 30-day interval until repairs 

could be made, and that additional locations were selected for augmented wall thickness 

measurements. The LRA also discussed a recent inspection of the spray pond and cooling 

towers, which, for the first time, identified a live clam in a sludge sample from the spray pond. 

The LRA stated that LGS applied a clam control chemical treatment to the spray pond and 

notified personnel involved in SW system heat exchanger inspections of this occurrence. The 

LRA stated that the above examples provided objective evidence that the Open-Cycle Cooling 

Water System program will be effective in ensuring that the intended functions are maintained 

consistent with the CLB 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 identified operating experience for which it 

determined the need for additional clarification.

As noted in the LRA’s operating experience discussion for this program, multiple leaks have 

occurred in the ESW piping over the years. Documentation that the staff reviewed during the 

audit indicated that the historical corrosion issues in small and medium diameter piping have 

more recently become evident in the large diameter piping of the ESW and RHRSW systems. 

Based on the applicant’s evaluations, although the current chemical treatment appears to be 

appropriate, no chemical treatment is capable of reaching the active corrosion cells under the 

deposits of corrosion products, silt, and tubercles. As such, the existing carbon steel piping will 

continue to degrade. However, the LRA did not provide information about corrective actions 

taken to prevent recurrence of the identified problem. By letter dated January 17, 2012, the 

staff issued RAI B.2.1.12-1 requesting, in part, that the applicant provide information about 

corrective actions being performed to identify loss of material before through-wall leakage 

occurs. Furthermore, if these corrective actions include plans for pipe replacement, the 

applicant was requested to provide those aspects that can be credited in license renewal to 

alleviate ongoing degradation. In addition, the RAI requested the applicant to provide 

summaries of structural integrity analyses for previous degradation, which demonstrate that 

multiple adjacent corrosion sites with a cumulative adverse impact will not occur during the 

period of extended operation.

In its response dated February 15, 2012, the applicant stated the following:

 • Its GL 89-13 inspections include nine representative locations that use ultrasonic testing at 

inspection frequencies ranging from 1.5 years to 8 years. 

 • It has performed more than 250 ultrasonic test inspections in the past 5 years based on 

visual inspection results, operating experience, guided wave inspections, and augmented 

inspections required by application of ASME Code Case N-513. 
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 • It currently performs additional ultrasonic test inspections at 37 locations at frequencies 

ranging from 6 months to 15 years.

 • It has implemented material improvements in the related systems that include replacement 

of more than 2,000 feet of carbon steel piping with stainless steel in systems for 

components, including the EDG heat exchanges, the HPCI room cooler, the RHR pump 

compartment unit coolers, the RHR pump motor oil coolers, and certain CS pump 

compartment unit coolers. 

 • It plans to complete the replacement, by 2015, of additional carbon steel piping with 

stainless steel in CS pump compartment unit coolers and the RHRSW piping located in the 

pipe tunnel.

 • The structural integrity analyses for previously identified degradation have used the 

evaluation requirements of ASME Code Case N-513 and where pipe inspections identify 

multiple corrosion sites, they are evaluated using the criteria of ASME Code, Section XI, 

Article IWA-3000, to determine if they may be evaluated as separate flaws. The associated 

piping inspections consist of full circumferential ultrasonic thickness scans at least 3 inches 

on either side of the location of interest and the entire boundary of any thinned area is 

recorded even if it extends beyond the original examination area. The structural integrity 

evaluations include hoop, axial, vacuum and buckling wall thickness, and operability 

evaluations consider loss of flow, spray on adjacent components, flooding, and potential for 

flaw propagation.

In addition, the applicant revised LRA Sections A.2.1.12, B.2.1.12, and Appendix A.5 to state 

that the enhancement to the Open-Cycle Cooling Water System program includes replacement 

of the supply and return piping for the CS pump compartment unit coolers and the degraded 

RHRSW piping in the pipe tunnel. The staff finds the applicant’s response acceptable because 

the extent of corrective actions taken and the planned enhancements before the period of 

extended operation will ensure that the system’s functions will be maintained during the period 

of extended operation. In addition, the structural integrity analyses used the evaluation criteria 

and considered multiple adjacent corrosion sites in accordance with the ASME Code

requirements. The staff’s concern described in RAI B.2.1.12-1 is resolved.

Based on its audit, its review of the application, and its review of the applicant’s responses to 

RAI B.2.1.12-1, the staff finds that the applicant has appropriately evaluated plant-specific and

industry operating experience. Operating experience related to the applicant’s program 

demonstrates that it can adequately manage the effects of aging on SSCs within the scope of 

the program, and that implementation of the program has resulted in the applicant taking 

corrective actions.

UFSAR Supplement. LRA Section A.2.1.12, as modified in response to RAI B.2.1.12-1 and 

B.2.1.12-2, 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; however, in its 

response to RAI B.2.1.12-2, the applicant revised the UFSAR supplement and Commitment 

No. 12 to perform five inspections per unit per refueling outage interval in the nonsafety-related 

portions of the SW system. As documented above in the staff evaluation of Enhancement 1, the 

staff believes that these inspections, in conjunction with opportunistic inspections, are 

necessary to ensure that the buried portions of the SW system will meet its intended function(s) 

during the period of extended operation. However, the UFSAR supplement, as amended, does 
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not establish this link. By letter dated June 21, 2012, the staff issued RAI B.2.1.12-3 requesting 

that the applicant revise the UFSAR supplement to make clear that the nonsafety-related 

inspections of the SW system are required to ensure the buried SW piping will meet its CLB 

function(s) during the period of extended operation. 

In its response dated June 22, 2012, the applicant stated it will conduct ten inspections of 

safety-related nonburied piping every 2 years in locations with service conditions that are 

representative of the buried piping (e.g., flow, temperature) in order to provide a sufficient 

understanding of the buried SW piping conditions. The applicant revised LRA Sections A.2.1.12 

and B.2.1.12 to reflect the quantity, periodicity, location criteria, and purpose of these 

inspections as they related to the condition of buried piping.

The staff finds the applicant’s response acceptable because the 50 inspections that will occur in 

each 10-year interval of the period of extended operation will provide sufficient, timely data to 

allow the applicant to understand the condition of the internal surfaces of the buried piping and 

the applicant has revised the UFSAR supplement such that the licensing basis will reflect the 

quantity, periodicity, location criteria, and purpose of these inspections as they relate to the 

condition of buried piping.

The staff also noted that the UFSAR supplement contained a commitment (Commitment No. 12)

to enhance its Open-Cycle Cooling Water System program to perform internal inspections of 

buried safety-related SW piping when it is made accessible for maintenance, perform periodic 

inspections for loss of material in the nonsafety-related SW system at a minimum of five 

locations on each unit once every refueling cycle, replace the supply and return piping for the 

CS pump compartment unit coolers, replace the degraded RHRSW piping in the pipe tunnel 

before the period of extended operation, and perform periodic inspections for loss of material in 

the safety-related SW system at a minimum of ten locations every 2 years.

The staff finds that the information in the UFSAR supplement, as amended by letters dated 

February 15, 2012 and June 22, 2012, is an adequate summary of the program

Conclusion. On the basis of its audit and review of the Open-Cycle Cooling Water System 

program the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements 

and confirmed that their implementation will make the AMP adequate to manage the applicable 

aging effects and that the UFSAR supplement contained Commitment No. 12 to implement the 

enhancements before the period of extended operation. 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).

3.0.3.2.5 Closed Treated Water Systems

Summary of Technical Information in the Application. LRA Section B.2.1.13 describes the 

existing Closed Treated Water Systems program as consistent, with an enhancement, with 

GALL Report AMP XI.M21A, “Closed Treated Water Systems.” The LRA states that the AMP 

manages loss of material and reduction of heat transfer in piping, piping components, piping 

elements, tanks, and heat exchangers exposed to a closed treated water environment. The 
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LRA also states that the program includes nitrite-based water treatment to modify the chemical 

composition of the water such that the effects of corrosion are minimized and chemical testing 

of the water to ensure that the water chemistry remains within acceptable guidelines. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M21A. 

For the “scope of program,” “preventive actions,” “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 an RAI, as discussed below.

The “scope of program,” “preventive actions,” “parameters monitored or inspected,” and 

“detection of aging effects” program elements in GALL Report AMP XI.M21A recommend that 

cracking caused by SCC to be managed by maintenance of water chemistry and periodic 

inspections. However, during its audit, the staff found that the Closed Treated Water Systems 

program does not manage cracking caused by SCC. By letter dated January 17, 2012, the staff 

issued RAI B.2.1.13-1 requesting the applicant to justify why cracking caused by SCC is not an 

AERM and to clarify whether the temperature of the closed cycle cooling water environment is 

above or below the SCC threshold of 60° C (140 °F).

In its response dated February 15, 2012, the applicant stated that SCC is not applicable 

because there are no stainless steel components in these systems exposed to a closed cycle 

cooling water environment that is greater than 60° C (140 °F). The applicant revised LRA 

Table 3.0-1 to clarify that the GALL Report environment of “closed-cycle cooling water greater 

than 60°C (140°F)” is not used. 

The staff finds the applicant’s response acceptable because it confirmed that the closed cycle 

cooling water environment is below the SCC temperature threshold defined in the GALL Report; 

therefore, SCC is not an AERM. The staff’s concern described in RAI B.2.1.13-1 is resolved. 

The staff also reviewed the portions of the “parameters monitored or inspected” and “detection 

of aging effects” program elements associated with an enhancement to determine if 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.2.1.13 states an enhancement to the “parameters monitored or 

inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that a representative sample of piping and components will be selected based 

on likelihood of corrosion and inspected at an interval not to exceed once in 10 years during the 

period of extended operation. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.M21A and finds it acceptable because when it is 

implemented, it will be capable of ensuring the effectiveness of the water treatment and testing 

activities by detecting the presence or extent of corrosion before loss of intended functions.

Enhancement 2. In response to RAI B.2.1.13-2.1, which addressed plant-specific operating 

experience, the applicant provided 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 condition monitoring for loss of material because of

cavitation erosion will be performed in the reactor enclosure cooling water piping to the RWCU 
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nonregenerative heat exchanger, with an initial inspection frequency of 4 years and future 

frequency adjustments based on trend data. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M21A and finds it acceptable 

because when it is implemented,, it will be capable of managing loss of material before loss of 

intended function. Additional discussion about the identification and resolution of this issue is 

given below in “Operating Experience.”

Based on its audit, and review of the applicant’s responses to RAIs B.2.1.13-1 and B.2.1.13-2.1, 

of the Closed Treated Water System program, the staff finds that program elements 1-6 for 

which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.M21A. In addition, 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.2.1.13-1 summarizes operating experience related to the 

Closed Treated Water Systems program. The applicant had no operating experience related to 

corrosion or cracking of components in the closed treated water systems. Examples of 

operating experience related to the maintenance of water chemistry are given below. In each 

case, the experience was related to the diagnosis of potentially adverse trends, rather than the 

water chemistry diverging from acceptable limits. 

In January 2009, an increasing trend in the number of chemical additions required to maintain 

the LGS Unit 1 turbine enclosure cooling water system was noted. Decreasing levels of nitrite 

and tolyltriazole (TTA) were determined to be consistent with a leak in the system and 

troubleshooting of the leak was turned over to the system manager. In November 2007, nitrite 

and TTA levels were determined to be near the low end of the desired concentration range in 

the control enclosure chilled water system. The applicant had a concern that additions to raise 

the levels of the chemical components may unacceptably raise the potential of hydrogen (pH). 

Chemical addition strategies to raise the nitrite and TTA concentrations without exceeding pH 

goals were evaluated, which led to an issue report to document the condition and request a plan 

of action. 

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 and resulted in the issuance of an RAI, as discussed below.

The operating experience discussion in LRA Section B.2.1.22, “One-Time Inspection,” states 

that ultrasonic test examinations in 2007 confirmed ongoing loss of material from erosion 

because of cavitation in the supply piping of the reactor enclosure cooling water system to the 

RWCU nonregenerative heat exchanger. The LRA stated that periodic inspections were 

implemented to monitor the progression of this loss of material. The staff noted that LRA 

Table 3.3.2-2, “Closed Cooling Water System,” manages loss of material because of general, 

pitting, galvanic, or crevice corrosion through the control of water chemistry in the Closed 
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Treated Water Systems program, but there were no AMR items that managed loss of material 

from erosion caused by cavitation. By letter dated January 17, 2012, the staff issued 

RAI B.2.1.13-2 requesting the applicant to provide a description of the AMP it proposes to use 

to manage the loss of material caused by cavitation erosion, to provide the apparent cause of 

this degradation mechanism and a summary of the extent of condition establishing that this 

mechanism is not applicable to other components, and to explain why this degradation 

mechanism was not identified in the LRA. 

In its response dated February 15, 2012, the applicant stated that this degradation mechanism 

will be managed by the Closed Treated Water Systems program, which is described in LRA 

Section B.2.1.13 and includes an enhancement for periodic condition monitoring using NDEs at 

an interval not to exceed 10 years. The applicant stated that it had established a recurring task 

to trend the erosion rate with an initial monitoring frequency of 4 years, and that the frequency 

would be adjusted once a trend has been established, but in no case would the inspection 

interval exceed 10 years during the period of extended operation. The applicant revised LRA 

Table 3.3.2-2, “Closed Cooling Water System,” to include an item that cites a plant-specific 

note, stating that the Closed Treated Water Systems program has been enhanced to include 

periodic NDE to manage this degradation mechanism. The response also stated that the 

degradation occurs in an elbow located downstream of a normally throttled valve, that an extent 

of condition review did not identify other instances of cavitation erosion for any components

within the scope of license renewal, and that this degradation mechanism was not included in 

the LRA because it was not considered an applicable aging effect for the period of extended 

operation.

In its review of the applicant’s response, the staff noted that the existing enhancement included 

with this AMP stated that it included condition and performance monitoring “to verify the 

effectiveness of the water chemistry control at mitigating aging effects.” The staff did not 

consider the existing enhancement as an adequate way to manage this degradation since water 

chemistry control will not address loss of material caused by cavitation erosion and the 

enhancement did not describe the 4-year inspection frequency or the adjustment to the 

frequency as discussed in the applicant’s response. By letter dated April 5, 2012, the staff 

issued followup RAI B.2.1.13-2.1, requesting the applicant provide information for 

enhancements to the appropriate program elements, and to discuss any monitoring activities 

such as temperatures or flow rates, which may need to be trended to establish the cavitation 

erosion rate.

In its response dated April 13, 2012, the applicant clarified that the associated valve was 

replaced during maintenance activities in 2007, and that no further noise or vibration had been 

observed, which indicated that cavitation erosion was no longer occurring. The applicant also 

stated, however, that the condition monitoring activities discussed in its previous RAI response 

would remain in place to verify that the loss of material has been arrested, and the applicant 

provided an enhancement to the program with a corresponding revision to Commitment No. 13 

to ensure implementation of these confirmation activities. The staff finds the applicant’s 

response acceptable because plant-specific operating experience has resulted in appropriate 

program enhancements, and the ongoing monitoring activities to manage loss of material 

downstream of the valve ensure that aging effects are detected before there is a loss of 

component intended function(s). The staff’s concerns described in RAIs B.2.1.13-2 

and B.2.1.13-2.1 are resolved.
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Based on its audit, review of the application, and review of the applicant’s responses to 

RAIs B.2.1.13-2 and B.2.1.13-2.1, the staff finds that the applicant has appropriately evaluated 

plant-specific and industry operating experience. Operating experience related to the 

applicant’s program demonstrates that it can adequately manage the effects of aging on SSCs 

within the scope of the program, and that implementation of the program has resulted in the 

applicant taking corrective actions. 

UFSAR Supplement. LRA Section A.2.1.13, as amended in response to RAI B.2.1.13-2.1, 

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 the UFSAR supplement contained a commitment (Commitment No. 13, 

as modified in response to RAI B.2.1.13-2.1) to enhance the Closed Treated Water Systems 

program to include the inspection of a representative sample of piping and components at an 

interval not to exceed once in 10 years during the period of extended operation, and to perform 

condition monitoring inspections for loss of material in the reactor enclosure cooling water 

system at an initial frequency of 4 years.

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

April 13, 2012, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the Closed Treated Water Systems 

program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements 

and confirmed that their implementation will make the AMP adequate to manage the applicable 

aging effects and that the UFSAR supplement contained Commitment No. 13 to implement the 

enhancements before the period of extended operation. 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).

3.0.3.2.6 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 enhancements, with GALL Report AMP XI.M23, 

“Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems.”

The LRA states that the program manages loss of material for the bridge, bridge rails, bolting, 

and trolley structural components and loss of preload for the bolted connections exposed to 

indoor air or treated water. The program implements the guidance provided in NUREG-0612, 

“Control of Heavy Loads at Nuclear Power Plants.” The LRA also states that the program 

includes periodic inspections that are consistent with the recommendations in the ASME B30 

series of standards.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 
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corresponding program elements of GALL Report AMP XI.M23. The staff also reviewed the 

portions of the “scope of program,” “parameters monitored or inspected,” “detection of aging 

effects,” “acceptance criteria,” 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. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B.2.1.14 states an enhancement to the “scope of program” and 

“detection of aging effects” program elements. In this enhancement, the LRA states that annual 

periodic inspections will be performed as defined in the ASME B30 series of standards. The 

LRA also states that annual periodic inspections for handling systems that are infrequently in

service may be deferred until just before use. GALL Report AMP XI.M23 recommends that 

crane rails and structural components be visually inspected for loss of material caused by

corrosion and wear and that bolted connections be inspected for loss of preload at a frequency 

in accordance with the appropriate ASME B30 series standard. GALL Report AMP XI.M23 

states that infrequently used systems, such as containment polar cranes, may be inspected 

once every refueling outage just before use. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M23 and finds it acceptable because 

when it is implemented, it will incorporate the annual periodic inspection criteria from the 

ASME B30 series standards to make the program consistent with the inspection criteria and 

frequencies recommended in the GALL Report AMP. 

Enhancement 2. LRA Section B.2.1.14 states an enhancement to the “scope of program,”

“parameters monitored or inspected,” and “detection of aging effects” program elements. In this 

enhancement, the LRA states that inspections will be performed for loss of material caused by

corrosion for structural components and bolting; loss of material caused by wear and corrosion 

for rails; and loss of preload for bolted connections. GALL Report AMP XI.M23 recommends 

that the bridge, bridge rails, and trolley structural components be visually inspected for loss of 

material caused by corrosion; rails to be visually inspected for loss of material caused by wear; 

and bolted connections to be inspected for signs of loss of preload. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.M23 and 

finds it acceptable because when it is implemented, it will make the program consistent with the 

GALL Report AMP. 

Enhancement 3. LRA Section B.2.1.14 states an enhancement to the “acceptance criteria”

program element. In this enhancement, the LRA states that loss of material caused by wear, 

loss of material caused by corrosion, and loss of preload will be evaluated in accordance with 

the appropriate ASME B30 series standard. GALL Report AMP XI.M23 recommends that any 

indication of loss of material or loss of preload be evaluated in accordance with the applicable 

ASME B30 series standard. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.M23 and finds it acceptable because when it is 

implemented, it will incorporate the evaluation criteria from the ASME B30 series standard to 

make the program consistent with the GALL Report AMP.

Enhancement 4. LRA Section B.2.1.14 states an enhancement to the “corrective actions”

program element. In this enhancement, the LRA states that repairs to cranes, hoists, and 

equipment handling systems will be performed in accordance with the appropriate ASME B30 

series standard. GALL Report AMP XI.M23 recommends that repairs be performed in 

accordance with the appropriate ASME B30 series standard. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.M23 and 
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finds it acceptable because when it is implemented, it will make the program consistent with the 

GALL Report AMP.

Based on its audit, and review of the Inspection of Overhead Heavy Load and Light Load 

(Related to Refueling) Handling Systems program, the staff finds that program elements 1-6 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,” “detection of aging effects,” “acceptance criteria,” 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.2.1.14 summarizes operating experience related to the 

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems 

program. In one operating experience example, the LRA states that wear was identified on the 

refueling platform trolley rail, which caused minor binding of the trolley during movement. The 

wear and binding was attributed to the trolley not being mounted in a plumb condition. The LRA 

also states that corrective actions were taken to repair trolley alignment and periodically clean 

and lubricate the trolley rails. During the audit, the staff reviewed this operating experience 

example and noted that wear readings have been steady since trolley alignment was repaired. 

In another operating experience example, the LRA states that inspection of the reactor 

enclosure overhead crane identified a potentially cracked bolt on the main hoist hook block. 

Corrective action was taken to further inspect the bolt. The further inspection identified that only 

the coating was degraded. As a result, the hook block was repainted.

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 found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

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 UFSAR supplement contained a commitment (Commitment No. 14) to enhance the program 

before the period of extended operation to perform periodic annual inspections as defined in 

ASME B30 series standards except for infrequently used equipment, which will be inspected 

just before use; inspect structural components and bolting for loss of material caused by

corrosion, rails for loss of material caused by wear, and bolting for loss of preload; evaluate loss 

of material or loss of preload in accordance with ASME B30 series standards; and perform 
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repairs in accordance with ASME B30 series standards. 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 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. Also, the staff reviewed the enhancements and confirmed that their implementation 

will make the AMP adequate to manage the applicable aging effects and that the UFSAR 

supplement contained Commitment No. 14 to implement the enhancements before the period of 

extended operation. 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).

3.0.3.2.7 Fire Protection

Summary of Technical Information in the Application. LRA Section B.2.1.17 describes the 

existing Fire Protection program as consistent, with enhancements, with GALL Report 

AMP XI.M26, “Fire Protection.” The LRA states that the program includes visual inspections of 

fire barrier walls, ceilings, floors, fire dampers, and penetration seals; and visual inspections and 

functional testing of fire doors and the halon and carbon dioxide systems. The LRA also states 

that the inspections and functional tests are performed in accordance with guidance in the 

applicable National Fire Protection Association (NFPA) codes and standards.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M26. For the “scope of program” 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 “scope of program” program element of GALL Report AMP XI.M26 states that the program 

includes visual inspections of fire barrier penetration seals, walls, ceilings, floors, doors, and 

other fire-resistant materials that perform a fire barrier function. The LGS Units 1 and 2 UFSAR 

states that gypsum fire barrier walls, fiberglass sleeving fire barriers, and refractory material 

raceway fire stops covered with silicone rubber are used at the plant as fire barriers. However, 

the LRA does not include any aging management results for components constructed of these 

materials. By letter dated January 17, 2012, the staff issued RAI B.2.1.17-1 requesting the 

applicant to explain how the gypsum, fiberglass sleeving, and refractory material fire barriers 

discussed in the UFSAR are being managed for aging. 

In its response, dated February 15, 2012, the applicant stated that gypsum, ceramic fiber, and 

refractory covered with silicone rubber materials are used as fire barriers at the site and were 

inadvertently omitted from the LRA. The applicant also stated that both the ceramic fiber and 

refractory materials are alumina silica products. The applicant revised LRA Table 3.3.2-9 to 

include AMR items for the gypsum and alumina silica fire barriers. The applicant further stated 

that the fiberglass sleeving is used as a fire barrier when RG 1.75 separation recommendations 

cannot be met. Fiberglass sleeving is not used as a fire barrier at the site and does not perform 

a license renewal intended function. The staff finds the applicant’s response acceptable 

because the alumina silica and gypsum fire barriers have been added to the LRA to be 
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managed for aging and the fiberglass sleeving does not require aging management because it 

has no license renewal intended function. Evaluation of aging management for the gypsum and 

alumina silica fire barriers is discussed in SER Section 3.3.2.3.9.

The “detection of aging effects” program element of GALL Report AMP XI.M26 recommends 

visual inspections be performed by fire protection qualified personnel of not less than 10 percent 

of each type of penetration seal during walkdowns, and that the scope of the inspections be 

expanded if any sign of seal degradation is detected. LRA Section B.2.1.17 states that not less 

than 10 percent of each type of penetration seal is inspected at least once per refueling cycle, 

except for internal conduit seals, which are not accessible for visual inspection. By letter dated 

January 17, 2012, the staff issued RAI B.2.1.17-2 requesting the applicant to explain how 

internal conduit seals that are not accessible for visual inspection are being managed for aging.

In its response, dated February 15, 2012, the applicant stated that the internal conduit seals are 

not exposed to high temperatures or relative motion and, therefore, are not subject to 

hardening, loss of strength, or loss of material. The applicant also stated that conduits that 

extend less than 5 feet on either side of the fire barrier are sealed with at least 9 inches of 

silicone foam and conduits that extend more than 5 feet from the fire barrier are sealed with at 

least 2 inches of silicone foam on both sides of the barrier. Therefore, the length of the seal 

makes it unlikely that degradation would provide a leak pathway. The applicant further stated 

that its NRC-approved fire protection program specifically excludes internal conduit seals from 

visual inspection. The staff noted that internal conduit seals are designed to prevent the 

passage of smoke and hot gases through the conduit using noncombustible material seals, 

whereas penetration seals seal the conduit to the fire barrier at the penetration and must have a 

fire resistance rating equal to that of the fire barrier. The staff also noted that the inaccessibility 

and thickness of internal conduit seals protects them from potential aging effects. The staff 

finds the applicant’s response acceptable because inaccessible internal conduit seals have no 

aging effects that could affect their intended function to prevent passage of smoke and hot 

gasses.

The “detection of aging effects” program element of GALL Report AMP XI.M26 states that visual 

inspections are performed by fire protection qualified personnel of fire barrier penetration seals, 

walls, ceilings, floors, doors, and other fire barrier materials. LRA Section B.2.1.17 states that 

the personnel performing inspections are qualified and trained to perform the inspection 

activities. However, the staff noted that the personnel responsible for performing fire barrier 

inspections are maintenance qualified personnel; not fire protection qualified personnel. By 

letter dated January 17, 2012, the staff issued RAI B.2.1.17-3 requesting the applicant to

describe the training and qualifications of the personnel responsible for performing fire barrier 

inspections.

In its response, dated February 15, 2012, the applicant stated fire barrier inspection parameters 

and acceptance criteria are identified in plant procedures and are consistent with Fire Protection 

program requirements. Any inspections that do not meet the established acceptance criteria 

are reviewed and evaluated by the fire protection program engineer, who is qualified under the 

Fire Protection program. The applicant also stated that inspections typically are performed by 

personnel who are qualified by training and demonstration of installation and repair of fire 

barriers, the purpose of fire barriers, fire barrier types, and materials of construction, and who 

inspect both new and repaired fire barriers. It was not clear to the staff how the applicant 

ensures that only personnel who are trained and qualified to identify fire barrier deficiencies are 

assigned to perform fire barrier inspections given that the personnel are only typically qualified. 
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By letter dated March 22, 2012, the staff issued followup RAI B.2.1.17-3.1 requesting the 

applicant to explain the minimum qualifications required for the personnel performing fire barrier 

inspections, not the typical qualifications, and how the applicant ensures that only personnel 

trained and qualified to identify fire barrier deficiencies are assigned to perform fire barrier 

inspections. 

In its response, dated March 30, 2012, the applicant stated that inspections are performed by 

maintenance and security personnel in accordance with site procedures consistent with the Fire 

Protection program requirements. Maintenance personnel who perform fire barrier inspections 

have at least 3 years of experience and are trained in accordance with the industry standards 

described in ACAD 92-008, “Guidelines for Training and Qualification of Maintenance 

Personnel,” which includes training in plant fire systems, fire barriers, the CAP, and the use of 

plant procedures. The applicant also stated that security personnel perform inspections of fire 

barriers that also serve as security barriers. Security personnel who perform fire barrier 

inspections are trained by observation of inspections performed by a trained security officer, 

performance of an inspection while being observed by a trained security officer, and 

demonstration and completion of inspection procedure requirements. The applicant further 

stated that personnel verify they are qualified before performing fire barrier inspections and 

supervisors also verify the individuals assigned to perform the inspections are qualified. The 

applicant also stated that the inspections are performed in accordance with the fire protection 

barrier inspection parameters and acceptance criteria implemented by the Fire Protection 

program requirements. The staff finds the applicant’s response acceptable because the 

maintenance and security personnel who perform fire barrier inspections have been qualified by 

training and experience to perform the required inspections and the applicant verifies that the 

personnel performing the inspections are qualified before performing the inspections; and any 

inspection results that do not meet the established acceptance criteria implemented in 

accordance with the Fire Protection program requirements are reviewed and evaluated by the 

fire protection program engineer. The staff’s concerns described in RAIs B.2.1.17-3 

and B.2.1.17-3.1 are resolved.

The staff also reviewed the portions of the “parameters monitored or inspected,” “detection of 

aging effects,” “monitoring and trending,” “acceptance criteria” 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.2.1.17 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria”

program elements. In this enhancement, the LRA states that additional inspection guidance will 

be provided to identify degradation of fire barrier walls, ceilings, and floors for aging effects such 

as cracking, spalling, and loss of material. GALL Report AMP XI.M26 recommends visual 

inspections of fire barrier walls, ceilings, and floors be performed to identify cracking, spalling, 

and 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 make the program consistent with the recommendations in the GALL Report AMP.

Enhancement 2. LRA Section B.2.1.17 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria”

program elements. In this enhancement, the applicant stated that additional inspection 

guidance will be provided for identification of excessive loss of material from the external 

surfaces of the halon and carbon dioxide systems. GALL Report AMP XI.M26 recommends that 
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periodic visual inspections of the halon and carbon dioxide systems be performed to identify any 

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 make the program consistent with the recommendations in the GALL Report AMP.

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, and B.2.1.17-3.1, the staff finds that the program elements 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,”

“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.2.1.17 summarizes operating experience related to the 

Fire Protection program. In one operating experience example, the LRA states that a gouge 

was identified in a foam fire barrier penetration seal during walkdown by the fire protection 

program engineer. As a result of the finding, additional inspections were performed that 

identified damage to another foam fire barrier penetration seal. The seals were declared 

inoperable pending engineering evaluation and corrective actions were taken to repair the seals. 

In another operating experience example, the LRA states that two tears were identified in the 

fabric covering a fire barrier. The tears were documented in the CAP and the applicant

determined that the tears did not compromise the ability of the underlying fire barrier to perform 

its 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. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.17 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 UFSAR supplement contained a commitment (Commitment No. 17) to 

enhance the program before the period of extended operation to provide additional inspection 

guidance to identify degradation of fire barrier walls, ceilings, and floors for aging effects such 

as cracking, spalling, and loss of material; and to identify excessive loss of material caused by

corrosion on the external surfaces of the halon and carbon dioxide systems. 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 Fire Protection program, the staff 

determines that the program elements for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M26. Also, the staff reviewed the enhancements and confirmed that their 

implementation will make the AMP adequate to manage the applicable aging effects and that 

the UFSAR supplement contained Commitment No. 17 to implement the enhancements before

the period of extended operation. 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).

3.0.3.2.8 Fire Water System 

Summary of Technical Information in the Application. LRA Section B.2.1.18 describes the 

existing Fire Water System program as consistent, with enhancements, with GALL Report 

AMP XI.M27, “Fire Water System.” The LRA states that the program manages aging for the 

water-based fire protection system components exposed to outdoor air and raw water using 

periodic inspections, preventive measures, monitoring, and performance testing. The LRA also 

states that system functional tests, flow tests, flushes, and inspections are performed in 

accordance with applicable NFPA codes and standards and that the program includes fire 

system main header flow tests, sprinkler system inspections, visual yard hydrant inspections, 

hydrant flow tests, and volumetric inspections to ensure that aging effects are managed. The 

LRA further states that selected portions of the aboveground piping exposed to water will be 

inspected using volumetric examination to ensure aging effects are being managed and that 

wall thickness is within acceptable limits.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M27. The staff also reviewed the 

portions of the “preventive actions,” “parameters monitored or inspected,” “detection of aging 

effects,” “monitoring and trending,” and “acceptance criteria” 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.2.1.18 states an enhancement to the “parameters monitored or 

inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that sprinkler heads will be replaced or tested using the guidance in NFPA 25, 

“Standard for the Inspection, Testing, and Maintenance of Water-Based Fire Protection 

Systems,” 2002 Edition, Section 5.3.1.1.1, by the 50-year inservice date and every 10 years 

thereafter. GALL Report AMP XI.M27 recommends that a sample of sprinkler heads that have 

been in place for 50 years be tested using the guidance in NFPA 25, 2002 Edition, 

Section 5.3.1.1.1. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.M27 and finds it acceptable because when it is implemented,

it will make the program consistent with the recommendations in the GALL Report AMP.

Enhancement 2. LRA Section B.2.1.18 states an enhancement to the “preventive actions,”

“parameters monitored or inspected,” “detection of aging effects,” “monitoring and trending,” and 

“acceptance criteria” program elements. In this enhancement, the applicant stated that selected 
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portions of the aboveground water-based fire protection system piping will be inspected using 

nonintrusive volumetric examinations before the period of extended operation and every

10 years thereafter. GALL Report AMP XI.M27 recommends that water-based fire protection 

system piping be flow tested in accordance with NFPA 25 or wall thickness evaluations be 

performed to ensure aging effects are managed and that wall thickness is within acceptable 

limits. The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.M27 and finds it acceptable because when it is implemented, it will make 

the program consistent with the recommendations in the GALL Report AMP.

Based on its audit and review of the Fire Water System program, the staff finds that program 

elements 1-6 for which the applicant claimed consistency with the GALL Report are consistent 

with the corresponding program elements of GALL Report AMP XI.M27. In addition, the staff 

reviewed the enhancements associated with the “preventive actions,” “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.2.1.18 summarizes operating experience related to the 

Fire Water System program. In one operating experience example, the LRA states that 

inspection of a pre-action system’s sprinkler heads identified over-spray on the sprinkler heads 

that could have prevented activation of the sprinkler heads. The affected sprinkler heads were 

replaced and the work order associated with application of the spray-on coating was revised to 

ensure that the areas not being coated are protected. In another operating experience 

example, the LRA states that a fire hydrant flow test identified a post-indicator valve that was 

not fully closing; therefore, causing a downstream hydrant to remain filled with water. The 

leaking valve was replaced before the potential for freezing could occur in the downstream 

hydrant. 

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 found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.18 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. The staff 

also noted that the UFSAR supplement contained a commitment (Commitment No. 18) to 

enhance the Fire Water System program to replace sprinkler heads that have been inservice for 

50 years or to perform testing in accordance with NFPA 25 and to inspect selected portions of 

the water-based fire protection system piping located aboveground using nonintrusive 
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examinations before the period of extended operation and every 10 years thereafter. 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 Fire Water System program, the staff 

determines that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that 

their implementation will make the AMP adequate to manage the applicable aging effects and 

that the UFSAR supplement contained Commitment No. 18 to implement the enhancement 

before the period of extended operation. 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).

3.0.3.2.9 Aboveground Metallic Tanks

Summary of Technical Information in the Application. LRA Section B.2.1.19 describes the 

existing Aboveground Metallic Tanks program as consistent, with enhancements with GALL 

Report AMPXI.M.29, “Aboveground Metallic Tanks.” The LRA states that the AMP addresses 

metallic tanks exposed to outdoor air and soil environments to manage the effects of loss of 

material. The LRA also states that the AMP proposes to manage this aging effect through 

periodic visual inspections, tank bottom UT inspections, and the application of paint as a 

preventive action.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M29.

For the “preventive actions” 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 “preventive actions” program element in GALL Report AMP XI.M29 recommends 

installation of sealant or caulking at the tank to foundation interface to minimize the amount of 

water and moisture penetrating the interface, which could lead to corrosion of the tank bottom. 

However, during its audit, the staff found that the Aboveground Metallic Tanks program states 

that there is no caulking or sealant at the base of the backup water storage tank. By letter dated 

January 17, 2012, the staff issued RAI B.2.1.19-1 requesting the applicant to state the basis for 

concluding that there is a reasonable assurance that the backup water storage tank will be 

capable of performing its CLB function(s) in the absence of sealant or caulking at the tank’s 

base.

In its response, dated February 15, 2012, the applicant stated that (a) the bottom of the backup 

water storage tank is coated with bitumastic asphalt coating, (b) to demonstrate that loss of 

material does not occur on the bottom of the backup water storage tank, a minimum of two tank 

bottom ultrasonic inspections will be performed, (c) the first inspection will be conducted within 

5 years before entering the period of extended operation with a followon inspection 5 years

later, and then, recurring inspections on 5-year intervals if necessary, (d) the inspection scope 
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will include measurements around the circumference, on each plate, and at any locations with 

damaged internal coatings, (e) if after two inspections, no loss of material is detected on the 

bottom of the tank, future inspections will occur whenever the tank is drained, and (f) the 

UFSAR supplement, LRA Section A.2.1.19 and Enhancement No. 1 in LRA Section B.2.1.19 

were revised to reflect the inspection plan as stated above in (b), (c), and (e).

The staff finds the applicant’s response acceptable because (a) the bottom of the backup water 

storage tank is coated, which can result in reduced corrosion, (b) a minimum of two tank bottom 

volumetric inspections will be conducted, (c) the inspection locations cover a sufficient range of 

locations on the tank bottom, (d) conducting the first two inspections in the 5-year period before

and at the start of the period of extended operation provides adequate time for corrosion to have 

occurred and been detected if the coatings and sand bed had not been effective, and 

(e) inspections will continue on a 5-year interval if loss of material on the bottom of the tank is 

detected. The staff’s concern described in RAI B.2.1.19-1 is resolved.

The “detection of aging effects” program element in GALL Report AMP XI.M29 recommends 

that the external surface of the tank be visually inspected at each outage to confirm that the 

paint is intact. However, during its audit, the staff found that the Aboveground Metallic Tanks 

program states that to provide for visual inspection of the external surface of the backup water 

storage tank on a 2-year frequency, insulation will be removed on a sampling basis. By letter 

dated January 17, 2012, the staff issued RAI B.2.1.19-2 requesting the applicant to state how 

much insulation will be removed from the backup water storage tank during its 2-year frequency 

external surface inspections and state the basis for why the amount of insulation to be removed 

is sufficient to detect potential tank exterior degradation before it affects the ability of the tank to 

perform its CLB function(s).

In its response, dated February 15, 2012, the applicant stated that the tank is coated with an 

organic zinc-rich primer covered by enamel and insulated by a spray-on polyurethane foam type 

insulation with a fiberglass fabric outer layer. The inspection before entering the period of 

extended operation will consist of removing approximately 1 square foot of insulation in 

25 locations and conducting a visual examination. The inspection locations will consist of areas 

where the insulation is intact and areas where the insulation shows visible signs of degradation. 

A minimum of 10 locations will be selected near the base of the tank where moisture intrusion is 

most likely to occur. If these inspections demonstrate that the insulation system is effective in 

preventing moisture from contacting the tank’s surface, the subsequent inspections, conducted 

on a 2-year frequency will consist of a minimum of four locations. The applicant also revised 

LRA Sections A.2.1.19 and B.2.1.19, and Commitment No. 19 to reflect the minimum number of 

inspections. 

The staff finds the applicant’s response and Enhancement 2 acceptable because (a) the tank is 

coated and, therefore, the proposed visual inspections are consistent with GALL Report 

AMP XI.M.29 once the insulation has been removed, (b) the areas that the applicant is selecting 

for inspection include degraded insulation locations and at least 10 locations near the bottom of 

the tank, both which represent the most likely areas for water intrusion that could result in 

degradation, (c) given the age of the tank, 25 inspection locations is sufficient to detect if 

degradation is occurring, (d) removing 1 square foot of insulation provides adequate area for a 

visual inspection, (e) inspections will be conducted on a 2-year frequency, and (f) the number of 

inspection locations will only be reduced below 25 to 4 if the initial inspection demonstrates that 

the insulation is effective as a moisture barrier. The staff’s concern described in RAI B.2.1.19-2 

is resolved.
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The staff also reviewed the portions of the “scope of program,” “preventive actions,” “detection 

of aging effects,” “monitoring and trending,” 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.2.1.19 states an enhancement to the “scope of program,”

“detection of aging effects,” “monitoring and trending,” and “acceptance criteria” program 

elements. In this enhancement, as amended by its response to RAI B.2.1.19-1, the applicant 

stated that it will conduct UT measurements of the bottom of the backup water storage tank 

once within 5 years before the period of extended operation followed by a followup inspection 

within 5 years. If loss of material is detected, inspections will continue on a 5-year interval. If no 

loss of material is detected, inspections will be conducted whenever the tank is drained. The 

staff reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.M29 and noted that the “detection of aging effects” program element recommends that 

the inspection of the tank should occur within 5 years of entering the period of extended 

operation. The staff finds this enhancement acceptable because during the audit, the staff 

confirmed that this tank had been installed early during the construction period and thus it has 

sufficient service time that conducting a UT exam 5 years before the period of extended 

operation would not prevent the program from being able to detect potential plant-specific 

degradation.

Enhancement 2. LRA Section B.2.1.19 states an enhancement to the “scope of program,”

“preventive actions,” “detection of aging effects,” “monitoring and trending,” and “acceptance 

criteria” program elements. In this enhancement, as amended by its response to 

RAI B.2.1.19-2, the applicant stated that on a sampling basis, every 2 years it will remove 

insulation from the tank to permit a visual inspection of the tank’s surface. The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP XI.M29 

and its evaluation is documented above in RAI B.2.1.19-2.

Based on its audit and review of the applicant’s responses to RAIs B.2.1.19-1 and B.2.1.19-2, 

the staff finds that the program elements for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report

AMP XI.M29. In addition, the staff reviewed the enhancements associated with the “scope of 

program,” “preventive actions,” “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.2.1.19 summarizes operating experience related to the 

Aboveground Metallic Tanks program. The applicant stated that a June 2000 underwater 

inspection of the tank’s internal surfaces conducted by a diver determined that the internal 

coatings were in excellent condition. The applicant also stated that a September 2007 visual 

inspection was conducted on the internal surfaces of the tank when it was drained. No 

deterioration of the tank’s surface coatings was identified.

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 found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.19 provides the UFSAR supplement for the 

Aboveground Metallic Tanks 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 UFSAR supplement contained a commitment

(Commitment No. 19) to enhance the program to (a) conduct UT measurements of the backup 

water storage tank’s bottom within 5 years before entering the period of extended operation and 

5 years thereafter, unless no loss of material on the tank bottom is found during these first two 

inspections whereupon followon inspections will occur whenever the tank is drained, and (b) on 

a sampling basis, every 2 years remove insulation from the tank to permit a visual inspection of 

the tank’s surface. 

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 Aboveground Metallic Tanks program, 

the staff determines that the program elements for which the applicant claimed consistency with 

the GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M29. Also, the staff reviewed the enhancements and confirmed that their 

implementation will make the AMP adequate to manage the applicable aging effects and that 

the UFSAR supplement contained Commitment No. 19 to implement the enhancements before

the period of extended operation. 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).

3.0.3.2.10 Fuel Oil Chemistry

Summary of Technical Information in the Application. LRA Section B.2.1.20 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 program manages loss of material 

in piping, piping elements, piping components, and tanks in a fuel oil environment. The 

applicant also stated that the fuel oil tanks within scope are maintained by monitoring and 

controlling fuel oil contaminants in accordance with the technical specifications, technical 

requirements, and American Society for Testing and Materials (ASTM) guidelines. It was 

indicated that fuel oil sampling and analysis is performed in accordance with approved 
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procedures for new fuel oil and stored fuel oil. Furthermore, it was stated that fuel oil tanks are 

periodically drained of accumulated water and sediment, cleaned, and internally inspected.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M30.

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.M30 states that 

periodic multilevel sampling provides assurance that fuel oil contaminants are below 

unacceptable levels. If tank design features do not allow for multilevel sampling, a sampling 

methodology that includes a representative sample from the lowest point in the tank may be 

used. However, during its audit, the staff found that the Fuel Oil Chemistry program states that 

the samples for analysis are taken by running the fuel oil transfer pumps, which take suction 11 

inches from the bottom of the emergency diesel generator diesel oil storage tanks, to transfer 

fuel oil to a sample collection point in the emergency diesel generator day tank room, which may 

not provide a representative sample. By letter dated January 17, 2012, the staff issued RAI 

B.2.1.20-1 requesting that the applicant explain how the current LGS sample collection 

methodology assures that fuel oil contaminants are below unacceptable levels, as is 

recommended in GALL Report AMP XI.M30.

In its response dated February 15, 2012, the applicant stated that the fuel oil transfer pump is a 

sump pump that takes suction 11 inches from the bottom of the emergency diesel generator oil 

storage tank. It was stated that there are no design features on the tanks such as process 

piping or drains that would allow for sampling at a lower tank elevation. The applicant stated 

that the GALL Report AMP XI.M30 recommends ASTM standard D 4057-95, “Manual Sampling 

of Petroleum and Petroleum Products” for sampling methods. The applicant stated that this 

standard discusses various levels of sampling methodologies, which would constitute a 

multilevel sample. In reviewing this standard, the applicant stated that the LGS sample method 

is more conservative than the multilevel sample methods described in ASTM D 4057-95, 

because the LGS method takes samples at heights that are equivalent or at lower levels of the 

tank than the levels called out in the standard. In addition, the LGS sample method does not 

take composite samples of the tank, which are called out in the ASTM standard, but rather, the 

samples are solely taken from 11 inches from the bottom of the tank where contaminants tend 

to collect and settle.

The staff finds the applicant’s response acceptable because this method of sampling takes 

samples from a suction that is 11 inches from the bottom of the emergency diesel generator 

diesel oil storage tanks, where contaminants, water, and sediments, tend to settle. In addition, 

taking bottoms samples as opposed to composite tank samples is consistent with the GALL 

Report, because contaminants, water, and sediments may be detected. As such, the staff finds 

that the sampling used by the Fuel Oil Chemistry program is equivalent or more conservative 

than the sampling method recommended by GALL Report AMP XI.M30. The staff’s concern 

described in RAI B.2.1.20-1 is resolved.

The staff also reviewed the portions of the “preventative actions,” “parameters monitored or 

inspected,” “detection of aging effects,” and “monitoring and trending” program elements 
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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.2.1.20 states an enhancement to the “preventative actions”

program element. In this enhancement, the applicant stated that water will be periodically 

drained from the fire pump engine diesel oil day tank and the fire pump diesel engine fuel tank. 

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 

program consistent with the recommendations in GALL Report AMP XI.M30.

Enhancement 2. LRA Section B.2.1.20 states an enhancement to the “preventative actions”

and “detection of aging effects” program elements. In this enhancement, the applicant stated 

that internal inspections will be performed for the fire pump engine diesel oil day tank, the fire 

pump diesel engine fuel tank, and the diesel generator day tanks 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 applicant also stated that each diesel fuel tank will 

be drained, cleaned, and the internal surfaces either volumetrically or visually inspected. It was 

indicated that if evidence of degradation is observed during visual inspections, the diesel fuel 

tanks will require followup volumetric inspection. 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 program consistent with the recommendations 

in GALL Report AMP XI.M30.

Enhancement 3. LRA Section B.2.1.20 states 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 periodic analysis will be performed for total particulate 

concentration and microbiological organisms for the fire pump engine diesel oil day tank and the 

fire pump diesel engine fuel tank. 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 program consistent with the recommendations in GALL 

Report AMP XI.M30.

Enhancement 4. LRA Section B.2.1.20 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” and “monitoring and trending” program elements. In this 

enhancement, the applicant stated periodic analysis will be performed for water and sediment 

and microbiological organisms for the diesel generator diesel oil storage tanks. 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 program 

consistent with the recommendations in GALL Report AMP XI.M30.

Enhancement 5. LRA Section B.2.1.20 states 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 periodic analysis will be performed for water and 

sediment, total particulate concentration, and microbiological organisms for the diesel generator 

day tanks. 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 program consistent with the recommendations in GALL Report AMP XI.M30.

Enhancement 6. LRA Section B.2.1.20 states an enhancement to the “parameters monitored or 

inspected” program element. In this enhancement, the applicant stated that an analysis will be 
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performed of new fuel oil for water and sediment content, total particulate concentration and the 

levels of microbiological organisms for the fire pump engine diesel oil day tank and the fire 

pump diesel engine fuel tank. 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 program consistent with the recommendations in GALL Report 

AMP XI.M30.

Enhancement 7. LRA Section B.2.1.20 states an enhancement to the “parameters monitored or 

inspected” program element. In this enhancement, the applicant stated that an analysis will be 

performed on new fuel oil for total particulate concentration and the levels of microbiological 

organisms for the diesel generator diesel oil storage tanks. 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 program consistent with the 

recommendations in GALL Report AMP XI.M30.

Based on its audit, the staff finds that program elements 1-6 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.2.1.20 summarizes operating experience related to the 

Fuel Oil Chemistry program. 

The applicant stated that in April 2008, the D12 diesel generator diesel oil storage tank 1B-T527 

was drained, cleaned, and inspected. It was stated that the activities included an inspection of 

coatings by a certified coatings inspector and a tank internal inspection by a certified 

Pennsylvania tank inspector. It was reported that the internal condition of the tank was 

acceptable. Furthermore, it was indicated that the inspection revealed no evidence of 

degradation.

In May 2008, it was reported that the D24 diesel generator diesel oil storage tank 

2D-T527 was drained, cleaned, and inspected. It was stated that the activities included 

an inspection of coatings by a certified Pennsylvania tank inspector. It was reported that 

the internal condition of the tank was acceptable. Furthermore, it was indicated that the 

coating inspection revealed a chip in the coating at the base of the tank. This condition 

was entered into the CAP, evaluated by engineering, and found to be acceptable without 

repair. The applicant stated that tracking and trending of the rusting around the chip 

area was recommended.

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.
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During its review, the staff found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience, operating experience 

related to the applicant’s program that demonstrates it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. 

UFSAR Supplement. LRA Section A.2.1.20 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 UFSAR supplement contained a commitment (Commitment No. 20) to 

implement the seven 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.

Conclusion. On the basis of its audit and review of the Fuel Oil Chemistry program, the staff 

determines that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that 

their implementation will make the AMP adequate to manage the applicable aging effects and 

the UFSAR supplement contained Commitment No. 20 to implement the enhancements before

the period of extended operation. 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).

3.0.3.2.11 Monitoring of Neutron-Absorbing Materials Other than Boraflex

Summary of Technical Information in the Application. LRA Section B.2.1.28 describes the

existing Monitoring of Neutron-Absorbing Materials Other than Boraflex program as consistent, 

with enhancement, with GALL Report AMP XI.M40, “Monitoring of Neutron-Absorbing Materials 

Other than Boraflex.” The applicant stated that this program periodically analyzes test coupons 

of the Boral material in the LGS Units 1 and 2 spent fuel racks to determine if the 

neutron-absorbing capability of the material has degraded. It was stated that the program 

ensures that a 5 percent subcriticality margin is maintained in the spent fuel pool. 

The applicant stated that this program monitors the physical condition of the Boral material in 

the spent fuel racks by analysis of test coupons for physical attributes, neutron attenuation 

testing, dimensional checks, and weight and density characteristics. It was reported that the 

primary measurements for characterizing the performance of the Boral are the coupon thickness 

measurements and neutron attenuation tests. The applicant stated that the acceptance criteria 

are for neutron attenuation results to show that a decrease of no more than 5 percent of 

Boron-10 content has occurred, and the dimensional measurements show that an increase in 

thickness at any point does not exceed 10 percent of the initial thickness at that point.
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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 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M40.

For the “parameters monitored or inspected,” “detection of aging effects,” and “monitoring and 

trending” program elements, the staff determined the need for additional information, which 

resulted in the issuance of RAI B.2.1.28-1, as discussed below.

The program elements in GALL Report AMP XI.M40 state that for neutron absorber materials, 

gamma irradiation or long-term exposure to the wet pool environment may cause loss of 

material and changes in dimension (such as gap formation, formation of blisters, pits, and 

bulges) that could result in loss of neutron-absorbing capability of the material. However, during 

its audit, the staff found that the applicant’s Boral coupon trees in the Units 1 and 2 spent fuel 

pools (SFPs) are located in a “representative” location rather than a “bounding” location. That 

is, the coupon tree location is expected to receive a uniform gamma flux representative of 

typical rack exposure. The program is not clear on whether the coupon exposure to the 

environment is bounding for the Boral material in all racks. By letter dated January 30, 2012, 

the staff issued RAIs B.2.1.28-1 requesting the applicant to discuss how the coupon exposure 

(i.e., coupon tree location) will provide reasonable assurance that Boral degradation is identified 

before potential loss of neutron-absorbing capability of the material.

In its response letter, dated February 28, 2012, the applicant stated that in order for the coupons 

to obtain environmental conditions bounding of all Boral spent fuel pool racks, it proposes to 

resume an accelerated exposure configuration for the Boral coupons (i.e., surround the coupons 

by freshly discharged fuel assemblies) at each of the next five refueling cycles, beginning with 

the refueling outage in 2014 and 2013 for LGS Units 1 and 2, respectively.

The staff reviewed this response and determined the need for more information. The coupons 

in the LGS Units 1 and 2 spent fuel pools may not have experienced long exposure to high 

radiation fluence from freshly discharged fuel compared to the most limiting storage cell, making 

the exposure time potentially nonconservative or not bounding of all the LGS Unit 1 and 2 Boral 

spent fuel pool racks; therefore, they may not provide acceptable testing data for monitoring 

loss of material and degradation of the neutron-absorbing material capacity. By letter dated 

April 13, 2012, the staff issued followup RAI B.2.1.28-2 requesting the applicant to provide 

justification on how resuming a five cycle radiation exposure period will place the coupons in a 

bounding condition for all Boral spent fuel pool racks for the LGS Units 1 and 2 for the period of 

extended operation. 

In its response letter, dated April 27, 2012, the applicant stated that plant documentation on fuel 

pool inventory was reviewed, and it was determined that the actual number of cycles that the 

coupons were completely surrounded by freshly discharged fuel for LGS Unit 2 is five (first five 

cycles following rack installation), and for LGS Unit 1 is two (first two cycles following rack 

installation). The applicant then stated that surrounding the test coupons by eight freshly 

discharged fuel bundles for five future cycles (ending 2024 and 2023 for LGS Units 1 and 2, 

respectively) will ensure that the test coupons will be leading indicators for other individual fuel 

storage cells.

The applicant stated that an analysis was performed on the spent fuel pool inventory relative to 

the test coupons to predict when the exposure of the coupons to freshly discharged fuel would 

be equal to the exposure of the limiting storage cells to freshly discharged fuel. It was 
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concluded that the coupons in the SFP will be exposed to the same number of freshly 

discharged fuel assemblies as the theoretical worst case cell in 2020 for LGS Unit 1 and 2021 

for LGS Unit 2.

The staff reviewed this response and determined the need for more information. Although the 

applicant provided a path forward for coupon exposure such that the coupons would be the 

leading indicator for other individual fuel storage cells for LGS Units 1 and 2, it did not provide 

the relative cumulative dose of the coupons compared to the most limiting storage cell. By letter 

dated May 18, 2012, the staff issued RAI B.2.1.28-3 requesting the applicant to discuss the 

relative cumulative dose for the coupons compared to the most limiting storage cell at the end of 

the proposed five cycles of exposure to freshly discharged fuel. Also, it was requested that the 

applicant discuss the impact of an accelerated exposure to freshly discharged fuel versus a 

long-term exposure to representative conditions. 

In its response letter dated May 31, 2012, the applicant stated that the coupons will have been 

exposed to a greater number of freshly discharged fuel assemblies than the worst case fuel 

storage cell after the next five cycles of exposure, before the period of extended operation. The 

applicant further stated that documented industry research does not differentiate between 

accelerated and long term exposure effects. The applicant stated that there are no documented 

analyses that indicate gamma heating or other effects from radiation exposure are the likely 

cause of degradation of Boral. Moreover, the applicant stated that the most recent documented 

analyses of operating experience relating to degradation of Boral attribute the most likely 

causes of the degradation to manufacturing practices. The applicant cited industry research 

that states that although degradation of Boral can lead to minor corrosion and blistering, leading 

to reduced clearance between assemblies, it has no effect on the intended function of neutron 

absorption. The applicant stated that the coupon testing proposed for LGS is consistent with 

the GALL Report and will monitor the condition of the Boral spent fuel storage cell during the 

period of extended operation for the following reasons:

 • The coupons will be bounding of the most limiting fuel storage cell location relative to 

radiation exposure.

 • The coupons are exposed to the same environment conditions as the Boral panels in the 

fuel storage cells, relative to being submerged in water within a fuel storage cell. Since the 

water within the pool is continually circulated, the temperature of the water at the coupons is 

similar to the temperature of the Boral panels in the fuel storage cells.

 • The next coupon test will be performed after the exposure to radiation to the coupons is 

known to be bounding of the most limiting fuel storage cell and before the start of the period 

of extended operation.

 • Coupon testing will continue to be performed at a frequency not to exceed 10 years during 

the period of extended operation as recommended by GALL Report AMP XI.M40.

 • Coupon testing includes analyses for physical attributes, dimensional checks and neutron 

attenuation that are designed to identify loss of material, loss of neutron absorption ability, 

and the types of degradation observed at other plants, as described above.

Although the data cited by the applicant indicates that Boral defects are likely a result of the 

manufacturing process, the staff maintains that all neutron absorbing materials should be 

monitored for degradation of their neutron attenuation capability. While the industry research on 
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Boral may strengthen the argument that the material is robust, the staff’s evaluation is based on 

the adequacy and representative nature of the applicant’s coupon surveillance program.

The staff finds the applicant’s response acceptable because performing neutron attenuation 

testing is an acceptable means to evaluate neutron attenuation. The staff finds the evaluation of 

the coupon’s physical attributes and dimensional measurements acceptable because these 

attributes and measurements allow the material condition to be determined. In addition, the 

applicant has demonstrated that the coupons will be exposed to similar environmental 

conditions as the Boral in the fuel storage cells. Moreover, the coupons will be surrounded by 

eight freshly discharged fuel bundles for five future cycles (ending 2024 and 2023 for LGS Units 

1 and 2, respectively) making the coupons leading indicators for potential degradation of the 

Boral in the fuel storage cells. The testing frequency was reviewed and was determined to be 

consistent with the recommendations of the GALL Report. The staff finds acceptable that the 

applicant evaluates operating experience of Boral neutron absorber material in other similarly 

operated nuclear plants to inform the LGS program. The staff’s concern described in RAI 

B.2.1.28-3 is resolved

The staff also reviewed the portions of the “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. The staff’s evaluation of the 

enhancements follows. 

Enhancement 1. LRA Section B.2.1.28 states an enhancement to the “detection of aging 

effects” program. In this enhancement, the applicant stated that testing and analysis of Boral 

coupons will be performed on a 10-year frequency, beginning no earlier than 2020 for Unit 1

and 2021 for Unit 2. The staff reviewed this enhancement against the corresponding program 

element in GALL Report AMP XI.M40 and finds it acceptable because when it is implemented, it 

will make the program consistent with the recommendations in GALL Report AMP XI.M40.

Enhancement 2. LRA Section B.2.1.28 states an enhancement to the “corrective actions”

program element. In this enhancement, the applicant stated that corrective actions will be 

initiated if coupon test result data indicates that acceptance criteria will be exceeded before the 

next scheduled test coupon analysis. The staff reviewed this enhancement against the 

corresponding program element in GALL Report AMP XI.M40 and finds it acceptable because 

when it is implemented, it will make the program consistent with the recommendations of GALL 

Report AMP XI.M40.

Enhancement 3. LRA Section B.2.1.28 states an enhancement to the “monitoring and trending” 

program element. In this enhancement, the applicant stated that LGS will resume the 

accelerated exposure configuration for the Boral coupons (surrounded by freshly discharged 

fuel assemblies) at each of five additional refueling cycles, beginning with the next refueling for 

each unit (2013 for Unit 2, 2014 for Unit 1). The staff reviewed this enhancement against the 

corresponding program element in GALL Report AMP XI.M40 and finds it acceptable because 

when it is implemented, it will make the program consistent with the recommendations of GALL 

Report AMP XI.M40.

Enhancement 4. LRA Section B.2.1.28 states an enhancement to the “monitoring and trending” 

program element. In this enhancement, the applicant stated that LGS will maintain the coupon 

exposure such that it is bounding for the Boral 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 
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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 element in 

GALL Report AMP XI.M40 and finds it acceptable because when it is implemented, it will make 

the program consistent with the recommendations of GALL Report AMP XI.M40.

Based on its audit, and review of the applicant’s responses to RAIs B.2.1.28-1, B.2.1.28-2, 

and B.2.1.28-3, the staff finds that the program elements 1-6 for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.M40. In addition, the staff reviewed the enhancements associated with 

the “detection of aging effects,” “monitoring and trending,” 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.2.1.28 summarizes operating experience related to the 

Monitoring of Neutron-Absorbing Materials Other than Boraflex program. 

The applicant stated that an analysis of a test coupon removed from the LGS, Unit 2 SFP

in 2001 included an evaluation of physical attributes, neutron attenuation testing, dimensional 

checks, and weight and density characteristics of the coupon. It was indicated that after 7 years

of service, the Boral absorbers in the storage racks had retained their dimensional and 

neutron-absorption properties and were capable of continuing to perform their intended function 

of controlling reactivity. Similar results were reported in 1999 and 1997. 

The applicant stated that Information Notice 2009-26, “Degradation of Neutron-Absorbing 

Materials in the Spent Fuel Pool,” was addressed through the CAP. As a result, it was stated 

that the current optional spent fuel pool test coupon analysis program will be implemented for 

both units.

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 found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.28 provides the UFSAR supplement for the Monitoring 

of Neutron-Absorbing Materials Other than Boraflex program. In its response letter dated April 

27, 2012, the applicant provided revisions to the UFSAR supplement and commitment. The 

staff reviewed this UFSAR supplement description of the program and noted that it is consistent 
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with the recommended description in SRP-LR Table 3.0-1. The staff also noted that the UFSAR 

supplement contains a commitment (Commitment No. 28) to enhance the program by;

(1) Performing test coupon analysis on a 10-year frequency, beginning no earlier than 2020 

for Unit 1 and 2021 for Unit 2.

(2) Initiating corrective actions if coupon test result data indicates that acceptance criteria 

will be exceeded before the next scheduled test coupon analysis.

(3) Resuming the accelerated exposure configuration for the Boral coupons (surrounded by 

freshly discharged fuel assemblies) at each of five additional refueling cycles, beginning 

with the next refueling for each unit (2013 for Unit 2, 2014 for Unit 1).

(4) Maintaining the coupon exposure such that it is bounding for the Boral 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 applicant stated that the enhancements will be implemented 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 Monitoring of Neutron-Absorbing 

Materials Other than Boraflex program, the staff determines that the program elements for 

which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.M40. Also, the staff reviewed the 

enhancements and confirmed that their implementation will make the AMP adequate to manage 

the applicable aging effects and that the UFSAR contained Commitment No. 28 to implement 

the enhancements before the period of extended operation. 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).

3.0.3.2.12 Buried and Underground Piping and Tanks

Summary of Technical Information in the Application. LRA Section B.2.1.29 describes the 

existing Buried and Underground Piping and Tanks program as consistent, with enhancements,

with GALL Report AMP XI.M41 “Buried and Underground Piping and Tanks.” The LRA states 

that the AMP addresses the external surfaces of metallic buried and underground piping and 

tanks exposed to soil and the outdoor air environments to manage the effects of loss of 

material. The LRA also states that the AMP proposes to manage this aging effect through 

electrochemical verification of cathodic protection, nondestructive evaluation of pipe wall 

thickness of underground piping, and visual inspections of the pipe during opportunistic 

excavations; and external coatings, cathodic protection, and the quality of backfill used. This 

program augments other programs that manage the aging of internal surfaces of buried and 

underground piping and tanks.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.M41.
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For the “preventive actions,” “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 “preventive action” program element in GALL Report AMP XI.M41 recommends that buried 

steel piping be coated and cathodically protected. However, during its audit, the staff found that 

the Buried and Underground Piping and Tanks program states that the plant drainage system 

piping is neither coated nor cathodically protected, and the circulating water system piping is not 

coated. By letter dated January 17, 2012, the staff issued RAI B.2.1.29-1 requesting the 

applicant to state the basis for how the aging of buried components in the plant drainage and 

circulating water systems will be adequately managed such that their intended functions will be 

maintained consistent with the CLB despite a lack of cathodic protection and coatings for the 

plant drainage system and lack of coating for the circulating water system.

In its response, dated February 15, 2012, the applicant stated that based on further review, the 

plant drainage system is coated with a somastic coating, the circulating water system is coated 

with coal tar epoxy, both coatings are recommended by NACE SP0169-2007, and the plant

drainage piping is not cathodically protected because it is constructed from cast iron, a 

corrosion-resistant material.

The staff finds the applicant’s response acceptable because both piping systems are coated 

with coatings recommended by NACE SP0169-2007 as recommended by GALL Report 

AMP XI.M41. While the staff does not agree with the applicant’s stated basis for not installing 

cathodic protection (i.e., cast iron is a corrosion-resistant material), buried cast iron piping will 

not experience sufficient corrosion to result in a loss of piping function because cast iron 

components are designed with a thicker wall that allows much longer buried service. The staff’s 

concern described in RAI B.2.1.29-1 is resolved.

The “detection of aging effects” program element in GALL Report AMP XI.M41 recommends 

that if adverse indications are detected, inspection sample sizes within the affected piping 

categories are doubled, and if adverse indications are found in the expanded sample, the 

inspection sample size is again doubled, with the doubling of the inspection sample size 

continuing as necessary. However, during its audit, the staff found that the Buried and 

Underground Piping and Tanks program states that adverse conditions detected during 

inspections will be evaluated and the potential inspection expansion will be determined in 

accordance with the CAP. By letter dated January 17, 2012, the staff issued RAI B.2.1.29-2 

requesting the applicant to state the basis for how the CAP inspection expansion size will be 

consistent with GALL Report AMP XI.M41, or to state why the corrective action inspection 

expansion size will be sufficient to detect degradation before it causes an in-scope component 

to not be capable of meeting its CLB function(s).

In its response dated February 15, 2012, the applicant stated that:

The LGS Buried and Underground Piping and Tanks aging management 

program enhancement is revised to include criteria such that if adverse 

indications are detected during inspection of in-scope buried piping, inspection 

sample sizes within the affected piping categories are doubled. If adverse 

indications are found in the expanded sample, the inspection sample size is 

again doubled. This doubling of the inspection sample size continues as dictated 

by the corrective action program. This criterion is in accordance with GALL 

Report AMP XI.M41, “Buried and Underground Piping and Tanks.”
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It was not clear to the staff what was intended by the wording associated with the CAP. GALL 

Report AMP XI.M41, Section 4.f.iv. states, “[i]f adverse indications are detected, inspection 

sample sizes within the affected piping categories are doubled. If adverse indications are found 

in the expanded sample, the inspection sample size is again doubled. This doubling of the 

inspection sample size continues as necessary.” It was not clear if the applicant’s CAP would 

require doubling of the inspection sample size until a subsequent set of inspections detected no 

adverse conditions. The staff’s concern described in RAI B.2.1.29-2 was not resolved.

By letter dated March 22, 2012, the staff issued followup RAI B.2.1.29-2.1 requesting the 

applicant to clarify what it means by “[t]his doubling of the inspection sample size continues as 

dictated by the corrective action program,” because it does not appear to be consistent with 

GALL Report AMP XI.M41.

In its response, dated March 30, 2012, the applicant amended the last sentence of the 

enhancement to state, “[t]his doubling of the inspection sample size continues as necessary.” 

The applicant revised LRA Sections A.2.1.29 and B.2.1.29 accordingly.

The staff finds the applicant’s response acceptable because the enhancement is now consistent 

with the wording in AMP XI.M41, Section 4.f.iv. The staff’s concern described in RAI B.2.1.29.1 

is resolved.

The “acceptance criteria” program element in GALL Report AMP XI.M41 recommends that 

cathodic protection system soil to pipe potential acceptance criteria be consistent with NACE 

SP0169-2007. NACE SP0169-2007, Section 7.1.2.7, states that excessive levels of cathodic 

protection can cause external coating disbondment. However, during its audit, the staff found 

that the applicant’s “Cathodic Protection Design Basis Document” states that the cathodic 

protection system is required to maintain an energized voltage of not less than 

850 millivolts (mV) negative potential with respect to a copper-copper sulfate reference 

electrode. By letter dated January 17, 2012, the staff issued RAI B.2.1.29-3 requesting the 

applicant to state an upper limit acceptance criterion for pipe to soil potential measurements, 

and to state the basis for using the stated value.

In its response, dated February 15, 2012, the applicant stated that the program has been 

amended to require that if during cathodic protection surveys a negative polarized potential 

exceeds -1100 mV relative to a copper/copper sulfate electrode, an issue report will be 

documented in the CAP. The applicant also stated that the -1100 mV value is consistent with 

Peabody’s Control of Pipeline Corrosion, Second Edition 2001, NACE. In addition, the applicant 

revised LRA Sections A.2.1.29 and B.2.1.29 to reflect the additional acceptance criteria.

The staff finds the applicant’s response acceptable because the applicant has added an 

acceptance criterion that will ensure that excessive levels of cathodic protection will be 

addressed through the CAP, and the criterion, -1100 mV, is consistent with NACE SP0169-2007 

and industry guidelines for cathodic protection. The staff’s concern described in RAI B.2.1.29-3 

is resolved.

The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria”

program elements associated with enhancements 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 these 

enhancements follows.

Enhancement 1. LRA Section B.2.1.29, as amended by the applicant’s response to 

RAIs B.2.1.29-2 and B.2.1.29-2.1, states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that, “[i]f adverse indications are 

detected, inspection sample sizes within the affected piping categories are doubled. If adverse 

indications are found in the expanded sample, the inspection sample size is again doubled. This 

doubling of the inspection sample size continues as necessary.” The staff reviewed this 

enhancement as amended by the responses to RAI B.2.1.29-2, provided by letter dated 

February 15, 2012, and RAI B.2.1.29-2.1, provided by letter dated March 22, 2012, against the 

corresponding program elements in GALL Report AMP XI.M41 and finds it acceptable because 

when it is implemented, it will be consistent with the wording in AMP XI.M41, section 4.f.iv.

Enhancement 2. LRA Section B.2.1.29 states an enhancement to the “preventive actions,”

“parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria”

program elements. In this enhancement, the applicant stated that it will coat the underground 

EDG system fuel oil piping before the period of extended operation in accordance with NACE 

standards. The staff reviewed this enhancement against the corresponding program elements 

in GALL Report AMP XI.M41 and finds it acceptable because when it is implemented, it will be 

consistent with Table 2b, Preventive Actions for Underground Piping and Tanks, which 

recommends that underground piping be coated in accordance with NACE standards.

Enhancement 3. LRA Section B.2.1.29 states 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 direct visual inspections and volumetric 

inspections of the underground EDG system fuel oil piping and components during each 

10-year period beginning 10 years before entry into the period of extended operation. Before

the period of extended operation, all in-scope EDG system fuel oil piping and components 

located in underground vaults will undergo a 100 percent visual inspection. Volumetric 

inspections also will be performed. After entering the period of extended operation, 2 percent of 

the linear length of EDG system fuel oil piping and components within the scope of license 

renewal and located in underground vaults will undergo direct visual inspections and volumetric 

inspections every 10 years. Inspection locations after entering the period of extended operation 

will be selected based on susceptibility to degradation and consequences of failure. Visual 

inspections will be performed by a NACE qualified inspector. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.M41 and 

finds it acceptable because when it is implemented, it will be consistent with the visual 

inspection of external and volumetric inspection of internal surfaces recommendations of 

AMP XI.M41.

Enhancement 4. LRA Section B.2.1.29 states 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 two sets of volumetric inspections of the safety-related SW

system underground piping and components during each 10-year period beginning 10 years 

before entry into the period of extended operation. Each set of volumetric inspections will 

assess either the entire length of a run or a minimum of 10 feet of the linear length of the piping 

and components within the scope of license renewal. Inspection locations will be selected 

based on susceptibility to degradation and consequences of failure. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.M41 and 
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finds it acceptable because when it is implemented, it will be consistent with the visual 

inspection of external and volumetric inspection of internal surfaces recommendations of GALL 

Report AMP XI.M41.

Enhancement 5. LRA Section B.2.1.29 states an enhancement to the “parameters monitored or 

inspected,” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that visual inspections of safety-related SW piping will be performed by a 

NACE-qualified inspector. During the audit, the staff reviewed “before” pictures of this piping 

showing external surface degradation and “after” pictures with the external corrosion removed 

and coatings applied. The applicant stated that it was in the process of completing inspections 

and coating all of this piping. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.M41 and finds it acceptable because when it is 

implemented, as recommended by AMP XI.M41, it will ensure that potential coating degradation 

will be evaluated by an individual qualified to conduct the inspections.

Enhancement 6. LRA Section B.2.1.29 states an enhancement to the “preventive actions,”

“detection of aging effects,” “monitoring and trending,” and “acceptance criteria” program 

elements. In this enhancement, the applicant stated that it will perform trending of cathodic 

protection testing results to identify changes in the effectiveness of the system and to ensure 

that the rectifiers required to protect piping within the scope of license renewal are reliable 

90 percent of the time. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.M41 and finds it acceptable because when it is 

implemented, it can ensure that cathodic protection is available for the recommended amount of 

time and the system is providing an adequate level of protection.

Enhancement 7. LRA Section B.2.1.29, as amended by the response to RAI B.2.1.29-3, states 

an enhancement to the “preventive actions,” “detection of aging effects,” “monitoring and 

trending,” and “acceptance criteria” program elements. In this enhancement, the applicant 

stated that it will modify the yearly cathodic protection survey acceptance criterion to meet 

NACE standards. As stated above in the staff evaluation portion of this SER, RAI B.2.1.29-3 

was issued requesting the applicant to state an upper limit acceptance criterion for pipe to soil 

potential measurements, and state the basis for using the stated value. The staff evaluated the 

applicant’s response to RAI B.2.1.29-3 and the amended Enhancement No. 7 against the 

corresponding program elements in GALL Report AMP XI.M41 and finds it acceptable because 

when it is implemented, it will be consistent with NACE SP0169-2007 which is recommended by 

GALL Report AMP XI.M41 and industry guidelines for cathodic protection.

Based on its audit, and review of the applicant’s responses to RAIs B.2.1.29-1, B.2.1.29-2, 

B.2.1.29-3, and B.2.1.29-2.1, the staff finds that the program elements for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M41. In addition, the staff reviewed the enhancements 

associated with the “preventive actions,” “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.2.1.29 summarizes operating experience related to the 

Buried and Underground Piping and Tanks program. The applicant stated that in October 2010, 

an opportunistic inspection of fire protection and domestic water piping showed that there was 

no degradation of the coatings and wrappings on the piping and components. The applicant 
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also stated that in May 2008, inspections of all underground safety-related SW piping showed 

surface corrosion and some pitting. As a result, volumetric examinations were conducted, some 

repairs and replacements were completed, all piping was recoated, and future inspection 

activities were scheduled for inspecting all piping in all underground valve pits within the scope 

of license renewal on a 2-year frequency.

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 found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions.

UFSAR Supplement. LRA Section A.2.1.29 provides the UFSAR supplement for the Buried and 

Underground Piping and Tanks 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 UFSAR supplement contained a commitment (Commitment No. 29) 

to implement the enhancements, as described in the LRA, 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 Buried and Underground Piping and 

Tanks program, the staff determines that the program elements for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.M41. Also, the staff reviewed the enhancements and confirmed that their 

implementation will make the AMP adequate to manage the applicable aging effects and that 

the UFSAR supplement contained Commitment No. 29 to implement the enhancements before

the period of extended operation. 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).

3.0.3.2.13 ASME Code Section XI, Subsection IWE 

Summary of Technical Information in the Application. LRA Section B.2.1.30 describes the 

existing ASME Code Section XI, Subsection IWE program as consistent, with enhancements, 

with GALL Report AMP XI.S1, “ASME Code Section XI, Subsection IWE.” The LRA states that 

the AMP addresses the inspection of primary containment components exposed to uncontrolled 

indoor air and treated water environments to manage the effects of age-related degradation 

because of loss of material caused by corrosion, loss of preload in the bolts, and loss of 

leak-tightness. The LRA also states that the AMP proposes to manage this aging effect through 
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periodic visual inspections. When visual examination results require an evaluation or the 

component is repaired and is found to be acceptable for continued service, the areas containing 

such flaws, degradation, or repair are reexamined during the next ASME Code Section XI, 

Subsection IWE inspection period.

The primary containment components inspected in accordance with this AMP are the Class MC 

pressure-retaining components and their integral attachments, including wetted surfaces of 

submerged areas of the pressure suppression chamber and vent system, diaphragm slab 

carbon steel liner, downcomers and bracing, containment hatches and airlocks, drywell head, 

penetration sleeves, pressure retaining bolting, and other 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 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.S1. For the “scope of program,” 

“monitoring and trending,” and “acceptance criteria” program elements, the staff determined the 

need for additional information, which resulted in the issuance of RAIs about the following 

subjects:

 • Liner Plate Recoating Criteria

 • Liner Plate Corrosion Degradation Acceptance and Augmented Inspection Criteria

 • Liner Plate General and Pitting Corrosion Rate

 • Downcomers Corrosion

 • Suppression Pool Columns Corrosion

The details of the RAIs and the applicant’s responses to these RAIs are documented in the 

following:

(1) the NRC’s letter to the applicant, dated January 30, 2012 (Adams Accession 

No. ML11364A099)

(2) Exelon’s letter to the NRC, dated February 28, 2012 (Adams Accession 

No. ML12059A345)

(3) the NRC’s letter to the applicant, dated April 16, 2012 (Adams Accession 

No. ML12082A155)

(4) Exelon’s letter to the NRC, dated April 27, 2012 (Adams Accession No. ML12121A009)

(5) Exelon’s letter to the NRC, dated September 12, 2012 (Adams Accession 

No. ML12256A929)

(6) The NRC’s letter to the applicant, dated October 19, 2012 (Adams Accession 

No. ML12290A853)

(7) Exelon’s letter to the NRC dated October 25, 2012 (Adams Accession 

No. ML12299A393)
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In response to staff’s RAIs, the applicant revised its ASME Code Section XI, Subsection IWE 

aging management program to manage aging of the suppression pool liner and coating system. 

Specifically, the applicant enhanced the program to provide an expedited schedule for locally 

recoating the suppression pool liner plate in areas affected by corrosion to impede further 

corrosion, added criteria for augmented examination of the liner plate and recoating of 

downcomers, and committed to perform ultrasonic thickness examination to complement liner 

plate thickness measured using depth gauges. The applicant also revised Commitment No. 30 

to include all these changes. The staff found the revised AMP and Commitment No. 30 

acceptable. The details of the staff’s evaluation to determine acceptability of the revised AMP 

and Commitment No. 30 is described below.

Liner Plate Corrosion Rate and Recoat Acceptance Criteria. During the audit, the staff noted 

that general corrosion and pitting (local general corrosion) was recorded on the floor and walls 

of the 1/4 inch (250 mils) thick carbon steel liner plate in the LGS Unit 1 suppression pool. Most 

of the pits were less than 50 mils deep, and there were hundreds of pits that were less than 

30 mils. One of the pits was 122 mils deep, while some others were about 70 mils deep. Many 

plates had general corrosion; the level of corrosion ranged between 72 percent of the surface 

for one floor plate to zero percent for some wall plates.

The applicant had previously reviewed the liner plate design, performed calculations to 

disposition the suppression pool carbon steel liner plate corrosion degradation, and concluded 

the following: 

 • For pitting corrosion, the area shall be recoated when the metal loss is 1/8 inch (125 mils 

lost and 125 mils remain).

 • For pitting corrosion, the area shall be repaired (metal repair) when the metal loss is 

3/16 inch (187.5 mils lost and 62.5 mils remain).

 • For general corrosion, the area shall be repaired (metal repair) when metal loss is 1/8 inch 

(125 mils lost and 125 mils remain).

As part of a separate licensing action, the staff has previously reviewed the above noted criteria 

and found it acceptable as documented in a letter dated February 20, 2008 (ADAMS Accession 

No. ML080310769). As long as these criteria are met, the liner plate will perform its function. 

The staff used this approved criteria in its determination whether the actions proposed by the 

applicant were sufficient to manage the aging effect of loss of material.

To manage degradation and corrosion of the liner plate during the period of extended operation, 

the applicant committed (Commitment No. 30) to enhance the existing ASME Code Section XI, 

Subsection IWE program, submitted as a part of the LRA in June 2011, to:

Manage the suppression pool liner and coating system to:

(1) Remove any accumulated sludge in the suppression pool every refueling outage.

(2) Perform an ASME IWE examination of the submerged portion of the suppression pool

each ISI period.
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(3) Use the results of the ASME IWE examination to implement a coating maintenance plan 

to:

‒ Perform local recoating of areas with general corrosion that exhibit greater than 25 

mils plate thickness loss.

‒ Perform spot recoating of pitting greater than 50 mils deep.

‒ Recoat plates with greater than 25 percent coating depletion.

The coating maintenance plan will be initiated in the 2012 refueling outage for Unit 1, and 

the 2013 refueling outage for Unit 2, and implemented such that the areas exceeding the 

above criteria are recoated before the period of extended operation. The coating 

maintenance plan will continue through the period of extended operation to ensure the 

coating protects the liner to avoid significant material loss.

The staff reviewed Commitment No. 30 and noted that the applicant plans to recoat the locally 

corroded areas of the carbon steel liner plate to prevent further corrosion and loss of thickness. 

However, the staff was concerned about the delay between identifying a location that met the 

criteria for recoating and the completion of the recoating of the suppression pool carbon steel 

liner plate until the period of extended operation in selected areas where general corrosion is 

already more than 25 mils and pitting corrosion more than 50 mils. Therefore, the staff 

requested the applicant to address the acceptability of delaying recoating the liner plate by 

12 years for Unit 1 and 17 years for Unit 2, in areas that have already exceeded the recoating 

criteria described in Commitment No. 30. Pitting (local corrosion) corrosion rates are much 

higher than general corrosion rates and may lead to penetration and leakage of the liner if the 

recoating of the corrosion affected areas is not completed until 2024 for Unit 1 and 2029 for 

Unit 2. 

In its last response on this subject, the applicant revised Commitment No. 30 to:

Manage the suppression pool liner and coating system to:

(1) Remove any accumulated sludge in the suppression pool every refueling outage.

(2) Perform an ASME IWE examination of the submerged portion of the suppression pool 

each ISI period.

(3) Use the results of the ASME IWE examination to implement a coating maintenance plan 

to perform the following before the period of extended operation:

‒ Local areas (less than 2.5 inches in diameter) of general corrosion that are greater 

than 50 mils plate thickness loss will be recoated in the outage they are identified. 

This plate thickness loss criterion for local areas will also be used to determine when 

the submerged portions of the liner require augmented inspection in accordance with 

ASME Code Section XI, Subsection IWE, Category E-C.

‒ Areas of general corrosion greater than 25 mils average plate thickness loss will be 

recoated based on ranking of affected surface area, high to low. This plate thickness 

loss criterion for areas of general corrosion will also be used to determine when the 

submerged portions of the liner require augmented inspection in accordance with 

ASME Code Section XI, Subsection IWE, Category E-C.
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‒ For plates with greater than 25 percent coating depletion, the affected area will be 

recoated based on ranking of affected surface area depleted and metal thickness 

loss.

(4) Use the results of the ASME IWE examination to implement a coating maintenance plan 

to perform the following during the period of extended operation:

‒ Local areas (less than 2.5 inches in diameter) of general corrosion that are greater 

than 50 mils plate thickness loss will be recoated in the outage they are identified. 

This plate thickness loss criterion for local areas will also be used to determine when 

the submerged portions of the liner require augmented inspection in accordance with 

ASME Code Section XI, Subsection IWE, Category E-C.

‒ Areas of general corrosion greater than 25 mils average plate thickness loss will be 

recoated in the outage they are identified. This plate thickness loss criterion for 

areas of general corrosion will also be used to determine when the submerged 

portions of the liner require augmented inspection in accordance with ASME Code 

Section XI, Subsection IWE, Category E-C.

‒ For plates with greater than 25 percent coating depletion, the affected area will be 

recoated no later than the next scheduled inspection.

The coating maintenance plan will be initiated in the 2012 refueling outage for Unit 1 and the 

2013 refueling outage for Unit 2. The coating maintenance plan will continue through the 

period of extended operation to ensure the coating protects the liner to avoid significant 

material loss.

The staff reviewed the revised Commitment No. 30, as noted above, and found it acceptable 

because:

(1) The applicant plans to recoat all local areas (less than 2.5 inches in diameter) of 

corrosion (pitting corrosion) that are greater than 50 mils plate thickness in the outage 

they are identified. The coating maintenance plan will be initiated in 2012 for Unit 1, and 

2013 for Unit 2.

(2) The applicant has committed to perform an ASME IWE examination of the submerged 

portion of the suppression pool during each ISI period or at a maximum interval of 

4 years (two refueling outages).

(3) The maximum 4-year inspection interval is sufficiently short to identify local (pitting) 

corrosion before challenging the structural integrity and leak tightness of the liner, as 

described in the following:

Any local areas (less than 2.5 inches in diameter) of corrosion that are less than 

50 mils plate thickness loss, and thus would not be recoated, can have an 

additional loss of thickness of 137.5 mils before the 187.5 mil pitting threshold is 

reached. The staff previously approved calculations that demonstrated that this 

level of pitting corrosion is acceptable. If the 187.5 mils threshold is reached or 

exceeded, the local area would be repaired.

To sustain an additional metal loss of 137.5 mils over a 4-year inspection 

interval, the local (pitting) corrosion has to exceed a rate of 34 mils per year. The 

staff noted that, in the controlled suppression pool water environment, pitting of 

carbon steel would likely be expected to occur only beneath deposits where a 
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differential aeration cell is formed and local areas of aggressive water chemistry 

could be created. In water environments more aggressive than that of the 

suppression pool, under-deposit corrosion rates up to approximately 0.3 mm/year 

(12 mils/year) have been observed (Uhlig’s Corrosion Handbook, Second 

Edition, pg. 541, 566). According to the applicant, the maximum individual spot 

corrosion rate measured since 1995 for Unit 2, and 1996 for Unit 1, is 2.1 mils 

per year. 

The staff considers it reasonable to assume a maximum local (pitting) corrosion 

rate of 12 mils per year until additional data and trends are established based on 

future IWE inspections of the Unit 1 and Unit 2 suppression pools. This is nearly 

one-third of the allowable rate of 34 mils per year. In addition, the applicant is 

committed to recoat local areas with metal loss of more than 50 mils identified 

during any IWE inspection immediately during the same outage to prevent further 

degradation and corrosion. Recoating of the local areas of corrosion in the 

outage they are identified will prevent further degradation and loss of thickness. 

Therefore, IWE inspection of areas of local (pitting) corrosion at a maximum 

interval of 4 years is acceptable. 

(4) The maximum 4-year inspection interval is sufficiently short to identify general corrosion 

before challenging the structural integrity and leak tightness of the liner, as described in 

the following:

The applicant is committed to recoat areas of the liner plate with general 

corrosion that exhibit more than 25 mils average plate thickness loss based on 

ranking of affected surface area, high to low before the period of extended 

operation. After the period of extended operation, these areas will be recoated in 

the outage they are identified. According to the IWE inspections performed until 

2010, the greatest loss of material caused by general corrosion for Unit 1 and 

Unit 2 liner plates is 35 mils total. The applicant has also collected data for 

general corrosion of the LGS suppression pool liner plates since 1995 that 

indicate a general corrosion rate of 2 mils per year. Therefore, even if the 

general corrosion is allowed to continue until 2029 in Unit 2 and the affected 

areas of the liner are not recoated, the total loss in thickness will be 73 (35+2*19 

years) mils. The applicant has performed calculations that were previously 

approved by the staff, and have concluded that areas with general corrosion in 

the liner plate up to 125 mils are acceptable without repair. Therefore, even in 

the worst case that the applicant does not recoat the areas of general corrosion 

until the period of extended operation of Unit 2 in 2029, the structural integrity of 

the suppression pool liner plate will be maintained. After the period of extended 

operation, any plate with general corrosion will be recoated in the outage it is 

identified. The total loss in thickness caused by general corrosion between the 

IWE inspections (maximum duration 4 years) is not expected to be more than 8 

mils.

(5) The applicant committed to recoat areas of liner plates with greater than 25 percent 

coating depletion based on ranking of affected surface area depleted and metal 

thickness loss before the period of extended operation. After the start of the period of 

extended operation, areas with greater than 25 percent coating depletion will be 

recoated no later than the next scheduled inspection. The staff finds this acceptable 
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because recoating will be performed proactively on areas of the liner that have less than 

25 mil loss in thickness or 10 percent of liner plate thickness. The structural integrity or 

leak tightness of the suppression pool is a function of liner plate thickness and is not 

challenged by loss of coating or loss in thickness of 25 mils or less.

Liner Plate Corrosion Degradation and Coating Inspection. The staff was concerned about the 

quality and methods used for the underwater visual inspection performed by the applicant for 

the suppression pool liner plate. The applicant provided the following information about this 

issue in its September 12, 2012, letter:

(1) The contractor used for underwater inspections maintains a Quality Assurance Program 

that is reviewed and approved by the applicant and meets the requirements of 10 CFR 

50, Appendix B. The personnel performing the visual examination of the liner plate and 

coating are qualified and certified in accordance with the requirements of ANSI N45.2.6 

and ASTM D4537.

(2) A visual VT-3 examination is performed to determine the general condition of the 

coating. Any corrosion observed is considered as indicative of loss of coating. For local 

areas, the inspector identifies the size of area containing the indications, the size of 

indications, and the quantity of indications within the area. This data is documented and 

coating loss is identified as percentage of the total area examined. For larger areas, 

characterization of the area is performed consistent with the methods described in 

ASTM D610/SSPC VIS-2. 

(3) During the VT-3 examination, the inspectors also identify areas with or approaching 

substantial corrosion. The applicant has defined substantial corrosion as general 

corrosion greater than 25 mils average loss of thickness, or local areas of general 

corrosion greater than 50 mils loss. The inspectors use a go/no-go gauge as necessary 

to report a bounding condition. Augmented visual VT-1 examination of the areas 

identified with substantial corrosion is performed. This is accomplished by use of 

calibrated depth dial gauge to determine the loss in thickness.

(4) To demonstrate that loss of thickness of the liner plate measured by calibrated depth 

gauge underwater is appropriate, the applicant performed ultrasonic measurements in 

2012 on four Unit 1 plates in areas of general corrosion. The results of UT examination 

were compared with those obtained from visual examination using a calibrated depth 

gauge. It was found that the calibrated depth gauge method recorded comparatively 

greater loss in thickness and provided conservative results. 

In its letter dated October 25, 2012, the applicant also revised the AMP and Commitment No. 30 

to state that the ASME Code Section XI, Subsection IWE aging management program will be 

enhanced prior to the PEO to perform ultrasonic thickness measurements on four areas of 

submerged suppression pool liner affected by general corrosion. The ultrasonic thickness 

measurement requirements will be implemented before receipt of the renewed licenses.

 

The staff finds the detailed information provided by the applicant concerning the quality and 

methods acceptable because:

(1) The suppression pool liner plate inspection is performed by qualified personnel who are 

approved by the applicant and meet the requirements of 10 CFR 50, Appendix B. The 

personnel performing the inspection underwater are trained and qualified in accordance 
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with the requirements of ANSI N45.2.6 as required by ASME Code Section XI, 

Subsection IWA, Article IWA-2300 and 10 CFR 50.55a.

(2) As required by IWE-3511, the applicant has defined acceptance criteria for augmented 

visual examination as areas of general corrosion greater than 25 mils average loss of 

thickness, or local areas of general corrosion greater than 50 mils loss. This is based on 

calculations performed by the applicant that demonstrate that the corrosion rate is such 

that it will not jeopardize the intended function of the liner plate and will remain leak tight 

until the next inspection period. If corrosion exceeds the augmented inspection criteria, 

the applicant will recoat the liner appropriately as discussed earlier in this section to 

maintain the liner leak tight. 

(3) The applicant will perform detailed visual VT-1 examination of the areas requiring 

augmented inspection as required by IWE-2500. In addition, the applicant will perform 

UT thickness measurements on four areas of the suppression pool liner that are affected 

by general corrosion to correlate with visual VT-1 examination results and provide 

confidence in the VT-1 examination thickness measurements using a calibrated depth 

gauge. 

Downcomers Corrosion. During the audit, the staff reviewed a CAP-generated assignment 

report that indicated that there was corrosion of the suppression pool downcomers. Therefore, 

the staff requested through three rounds of separate RAIs that the applicant provide additional 

information concerning the extent of corrosion, acceptance criteria used for evaluating the 

corrosion, and technical basis for the acceptance criteria for the downcomers. In response to 

the staff’s RAIs, the applicant stated that the acceptance criterion used for the initial visual 

examination of the downcomers in the 1R13 outage, as reported in the assignment report, is 

less than or equal to 60 mils. The technical basis of this owner-established criterion is the 

design analyses for the downcomers in four original design basis calculations. These analyses 

conclude that surface defects of less than or equal to 62.5 mils are acceptable to meet design 

requirements. The corrosion found on the downcomers during 1R13 (2010) outage affected 

less than 13 percent of the cumulative surface area examined. Loss of metal in the exposed 

substrate was generally less than 15 mils.

In its letter dated October 25, 2012, the applicant also revised the AMP and Commitment No. 30 

to use the results of the ASME IWE inspection of the submerged portions of the suppression 

pool downcomers to perform the following:

 • Local areas (less than or equal to 5.5 inches in any direction) that have 40 mils or more 

metal thickness loss will be recoated. This downcomer metal thickness loss criteria for local 

areas will also be used to determine when the submerged portions of the downcomers 

require augmented inspection in accordance with ASME Code Section XI, Subsection IWE, 

Category E-C.

 • Areas of general corrosion (greater than 5.5 inches in any direction) that have 30 mils or 

more metal thickness loss will be recoated. This downcomer metal thickness loss criteria for 

areas of general corrosion will also be used to determine when the submerged portions of 

the downcomers require augmented inspection in accordance with ASME Code Section XI, 

Subsection IWE, Category E-C. The downcomer recoat and augmented inspection criteria 

will be implemented before receipt of the renewed licenses.
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The staff finds the applicant’s response concerning owner-established criteria for the recoating 

of downcomers acceptable because it is based on original design calculations and supplemental 

analysis. The structural integrity of the downcomers (375 mils in nominal wall thickness) will not 

be compromised by loss of material caused by local corrosion of up to 40 mils and loss of 

material caused by general corrosion of 30 mils. The original design was based on a loss of up 

to 62.5 mils in the thickness of the downcomers caused by surface defects. In addition, the 

applicant will have to recoat downcomers with local areas (less than or equal to 5.5 inches in 

any direction) that have 40 mils or more metal thickness loss or areas of general corrosion 

(greater than 5.5 inches in any direction) that have loss of material of 30 mils or more. The 

recoating will be done during the refueling outage in which it is discovered because ASME 

Section XI, Subsection IWE, Article IWE-3112(b) requires that a component whose examination 

detects flaws or areas of degradation that do not meet the owner’s defined acceptance criteria 

shall be corrected prior to placement of the component in service.

Suppression Pool Columns Corrosion. During the audit, the staff reviewed a CAP-generated 

assignment report that indicated corrosion of the suppression pool columns and requested the 

applicant to provide additional information. The applicant stated in response to two rounds of 

RAIs that minimal general corrosion and spot corrosion (affecting less than 1.5 percent of the 

cumulative surface area inspected) was identified on the 12 columns (42-inch diameter hollow 

steel pipe columns) examined in Unit 1. General loss of material was reported at less than 

20 mils, and no localized corrosion exceeding 60 mils was identified. The applicant has used a 

loss of 62.5 mils as the acceptance criteria for loss of thickness of suppression pool columns 

caused by corrosion because original construction specification permitted surface defects of 

less than or equal to 62.5 mils. The applicant also stated that the small areas of minimal 

general corrosion identified on the 1.25-inch wall thickness of the hollow steel pipe columns do 

not affect load-bearing capacity or visibly reduce the cross-sectional area, and are, therefore,

acceptable. The applicant further stated that the examination frequency for the suppression 

pool columns is each inspection interval (120 months) which is in accordance with ASME Code 

Section XI, Subsection IWF, Table IWF-2500-1 for item F1.40. 

The staff finds the applicant’s response to the RAIs concerning the current condition of the 

suppression pool support columns acceptable because general corrosion loss of 20 mils is 

equivalent to less than 2 percent of the 1.25-inch thick columns, and will not affect the 

load-carrying capacity of the columns. ASME Code, Section XI, Subsection IWF states that 

components are acceptable for continued service if the roughness or general corrosion does not 

reduce the load-bearing capacity of the support and general conditions are acceptable by the 

material, design, or construction specification. In addition, localized corrosion not exceeding 

60 mils is acceptable because the original construction specification permitted surface defects 

of less than 62.5 mils.

In its response, dated April 27, 2012, the applicant stated that the examination frequency for the 

suppression pool columns is each inspection interval (120 months), which is in accordance with 

ASME Code Section XI, Subsection IWF, Table IWF-2500-1 for item F1.40. The staff finds this 

acceptable because the suppression pool support columns will be examined at the frequency 

specified in the ASME Code. The applicant is also using the acceptance criteria specified in the 

ASME Code Section XI, Subsection IWF, which states that components are acceptable for 

continued service if the roughness or general corrosion does not reduce the load-bearing 

capacity of the support and general conditions are acceptable by the material, design, or 

construction specification. 
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Enhancements. The staff also reviewed the portion of the “preventive actions,” and “detection 

of aging effects,” 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, as amended by letters dated September 12, 2012, and 

October 25, 2012, states an enhancement to the “detection of aging effects,” program element 

will be implemented before the period of extended operation to manage the suppression pool 

liner and coating system. This will include more frequent inspections and selected recoating of 

the corroded areas of the suppression pool. This will be initiated in the 2012 refueling outage 

for LGS Unit 1 and the 2013 refueling outage for LGS Unit 2. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.S1 and 

found it acceptable. The basis for the staff’s determination is described earlier in this section.

Enhancement 2. LRA Section B.2.1.30, as amended by letter dated October 25, 2012, states 

that an enhancement to the “detection of aging effects,” program element will be implemented 

before receipt of the renewed licenses for recoating and augmented inspection of the 

downcomers. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.S1 and found it acceptable. The basis for the staff’s 

determination is described earlier in this section. 

Enhancement 3. LRA Section B.2.1.30, as amended by letter dated October 25, 2012, states 

that an enhancement to the “detection of aging effects,” program element will be implemented 

before the receipt of the renewed licenses to perform UT thickness measurements on four areas 

of submerged suppression pool liner affected by general corrosion. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.S1 and 

found it acceptable. The basis for the staff’s determination is described earlier in this section. 

Enhancement 4. LRA Section B.2.1.30 states an enhancement to the “preventive actions,” 

program element. In this enhancement, the applicant stated that ASME Code Section XI, 

Subsection IWE program 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.S1 and finds it acceptable because 

when it is implemented, it will make the program consistent with the recommendations in the 

GALL Report by ensuring the proper specifications are used. In addition, as documented in 

SER Section 3.0.3.2.3, the applicant revised the LRA to state that high-strength bolting, if used, 

will be monitored for cracking. The applicant further stated that other pressure-retaining bolting 

is inspected for leakage, which could result from cracking. 

Based on its audit, and review of the applicant’s responses to RAIs B.2.1.30-1, B.2.1.30-1.1, 

B.2.1.30-2, B.2.1.30-2.1, RAI B.2.1.30-2.2, B.2.1.30-3, B.2.1.30.4-1, B.2.1.30.4-1, 

RAI B.2.1.30-6, and RAI B.2.1.30-7, the staff finds that the program elements 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 enhancements 1 

through 4 and finds them acceptable, as discussed earlier in this section. 

Operating Experience. LRA Section B.2.1.30 summarizes operating experience related to the 

ASME Code Section XI, Subsection IWE program. This included focused self-assessment that 

resulted in enhancement of the ASME Code Section XI, Subsection IWE program’s scope, 
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detection of corrosion in the suppression pool liner plates that was evaluated and some areas 

recoated to prevent additional loss of material, and identification and subsequent tightening of 

the loose bolts on the access manway located on the LGS Unit 2 drywell head. The LRA stated 

these examples demonstrate that the ASME Code Section XI, Subsection IWE program has 

been able to identify aging effects and that corrective actions were taken under the program to 

prevent the recurrence of component failures. 

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, the staff reviewed the ASME Code, Section XI, Subsection IWE (Class MC) 

containment visual examination NDE report for different components, including one for the 

drywell closure head. This report had photographs of the different attachments to the drywell 

closure head that show extensive corrosion and pitting. However, the examination report found 

that the condition is acceptable by visual examination. The staff was concerned about this 

assessment and by letter dated January 30, 2012, issued RAI B.2.1.30-5 requesting the 

applicant explain the basis for acceptance of extensive corrosion and pitting on the different 

attachments to the drywell closure head. 

In its response dated February 28, 2012, the applicant stated that the pictures of the LGS Unit 2 

drywell head included with the examination report of this component for the April 2011 outage 

depict surface corrosion on the ends of a steel support angle and channel support for a ladder 

and platform that are attachments to the drywell closure head. No pitting is depicted in the 

photograph and none was noted by the examiner. The implementing procedure acceptance 

criterion for the drywell head states that localized areas of corrosion shall not exceed 

0.050 inches. This surface corrosion was determined to be within the acceptance criterion by 

the examiner as no loss of thickness or pitting was noted. Although the surface corrosion of the 

ladder and platform supports and their attachment points on the drywell head are acceptable, 

this condition had been entered into the CAP for follow up.

The staff finds the applicant’s response acceptable because the applicant provided the basis for 

acceptance of the corrosion on the different attachments. There was no loss of thickness or 

pitting recorded by the examiner, and this condition has been entered into the CAP for followup 

inspection and assessment. The staff’s concern described in RAI B.2.1.30-5 is resolved.

Based on its audit and review of the application, and review of the applicant’s response to RAI 

B.2.1.30-5, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience, operating experience related to the applicant’s program 

demonstrates that it can adequately manage the effects of aging on SSCs within the scope of 

the program, and that implementation of the program has resulted in the applicant taking 

corrective actions.

UFSAR Supplement. LRA Section A.2.1.30, as amended by letter dated October 25, 2012,

provides the UFSAR supplement for the ASME Code Section XI, Subsection IWE AMP. 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 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 ASME Code Section XI, Subsection IWE 

AMP, the staff determines that the program elements for which the applicant claimed 
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consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.S1. In addition, the staff reviewed enhancements 1-4 and Commitment 

No. 30 and determined them to be acceptable, as discussed earlier in this section. The staff 

also reviewed the UFSAR supplement for this AMP and concluded that it provides an adequate 

summary description of the program.

3.0.3.2.14 ASME Code Section XI, Subsection IWL

Summary of Technical Information in the Application. LRA Section B2.1.31 describes the 

existing ASME Code Section XI, Subsection IWL program as consistent, with an enhancement, 

with GALL Report AMP XI.S2, “ASME Code Section XI, Subsection IWL.” The LRA states that 

the ASME Code Section XI, Subsection IWL program is an existing condition monitoring 

program that implements examination requirements of the ASME Code. The inspection 

methods, inspected parameters, and acceptance criteria in this program are in accordance with 

ASME Code, Section XI, Subsection IWL. Periodic general visual examination of the 

containment accessible concrete surfaces to detect deterioration and distress as defined in

American Concrete Institute (ACI) 201.1 and ACI 349.3R-02. The concrete of the primary 

containments are exposed to an indoor air environment sheltered within the reactor enclosure. 

The LRA further states that the current ASME Code, Section XI, Subsection IWL containment 

ISI program complies with ASME Code, Section XI, Subsection IWL, 2001 Edition 

including 2003 Addenda as approved by 10 CFR 50.55a. In accordance with 

10 CFR 50.55a(g)(4)(ii), the ISI program is updated each successive 120-month inspection 

interval to comply with the requirements of the latest edition of the ASME Code, 12 months 

before the start of the inspection interval. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.S2. For the “acceptance criteria” 

program element, the staff determined the need for additional information, which resulted in the 

issuance of RAIs, as discussed below.

The “acceptance criteria” program element in GALL Report AMP XI.S2 recommends using 

ACI 349.3R-02 for identification of concrete degradation. However, during its audit, the staff 

noted that the applicant’s program basis document and implementing procedure exclude the 

first-tier acceptance criteria defined in ACI 349.3R-02 “Evaluation of Existing Nuclear 

Safety-Related Concrete Structures,” for concrete surface examination. By letter dated 

January 30, 2012, the staff issued RAI B.2.1.31-1 requesting the applicant to provide 

justification for excluding the first-tier acceptance criteria for the primary containment concrete 

surface examination as described in ACI 349.3R-02, Chapter 5, “Evaluation Criteria.”

In its response dated February 28, 2012, the applicant stated that it meets the 

recommendations of ACI 349.3R-02, Chapter 5, for use of the second-tier criteria because: 

(a) the 6-foot 2-inch thick conventionally reinforced concrete walls of the primary containment 

constitute massive concrete, (b) the environment within the reactor enclosure is indoor air; 

therefore, the primary containment structures are not exposed to degradation mechanisms, 

which would be applicable to an outdoor air or seacoast environment as described in 

ACI 349.3R-02, and (c) the specified minimum concrete cover is 2 inches, which is in excess of 

the minimum concrete cover specified in ACI 349.3R-02. The applicant stated that all three 

factors in Chapter 5 of ACI 349.3R-02 for excluding the first-tier acceptance criteria are met; 
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therefore, application of the second-tier acceptance criteria is justified for the purpose of 

evaluation of observed conditions of the primary containments.

The staff finds the applicant’s response acceptable because the applicant confirmed that the 

implementation of the first-tier acceptance criteria could be overly conservative for (a) the 

massive concrete structures, (b) structures not exposed to certain degradation mechanisms, or 

(c) structures possessing concrete cover in excess of the minimum requirements of 

ACI 349.3R-02, such as concrete containment structures. Therefore, the staff finds that all 

three factors in Chapter 5 of the ACI 349.3R-02 are met, and use of the second-tier acceptance 

criteria is justified for the primary containments’ concrete. The staff’s concern described in 

RAI B.2.1.31-1 is resolved.

The “acceptance criteria,” program element in GALL Report AMP XI.S2 relies on the 

determination of the “Responsible Engineer” as defined by the ASME Code. However, during 

the audit, the staff noted that the site procedures did not clearly define the qualification 

requirements of the “Responsible Engineer.” By letter dated January 30, 2012, the staff issued 

RAI B2.1.31-2 to confirm whether the “Responsible Engineer” meets the qualification 

requirements of ASME Code, Section XI, Subsection IWL-2300.

In its response dated February 28, 2012, the applicant stated that the procedure defines a 

Responsible Engineer as “[a] Registered Professional Engineer as defined in ASME Code 

Section XI Subsection IWL experienced in evaluating the inservice condition of structural 

concrete. The Responsible Engineer shall have knowledge of the design and construction 

codes and other criteria used in the design and construction of concrete containment structures 

in nuclear power plants.” The applicant further stated that this definition is in accordance with 

the requirements of ASME Code Section XI, Subsection IWL 2320, and the procedure governs 

conduct of all ASME Code Section XI ISI activities, and is an implementing procedure for GALL 

Report AMP XI.S2, ASME Code Section XI, Subsection IWL.

The staff finds the applicant’s response acceptable because the applicant defined the 

Responsible Engineer in the procedure, which is in accordance with the requirements of 

Subsection IWL-2320 of the ASME Code, Section XI. The staff’s concern described in 

RAI B.2.1.31-2 is resolved.

Enhancement. LRA Section B.2.1.31 states an enhancement to the “acceptance criteria”

program element. In this enhancement, the applicant stated that the ASME Code, Section XI, 

Subsection IWL program will be enhanced to include the second-tier acceptance criteria of the 

ACI 349.3R-02. As discussed above, the staff issued RAI B2.1.31-2 requesting the applicant to

provide justification for excluding the first-tier acceptance criteria of the primary containment 

concrete as required in Chapter 5, “Evaluation Criteria” of ACI 349.3R-02. The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP XI.S2, 

and the applicant’s response to RAI B2.1.31-2, and finds it acceptable because when it is 

implemented, it will meet the requirements of ACI 349.3R-02 and, therefore, be consistent with 

GALL Report AMP XI.S2. 

Based on its audit, and review of the applicant’s responses to RAIs B.2.1.31-1 and B.2.1.31-2, 

of the ASME Code Section XI, Subsection IWL program, the staff finds the elements 1-6 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 
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the enhancement associated with the “acceptance criteria” program element and finds that 

when implemented, it 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 Code Section XI, Subsection IWL program. The operating experience summary 

identified a number of areas where minor concrete surface imperfections, including random 

scattered hairline cracking, minor surface voids, popouts, and scaling have been observed 

previously. The conditions were found either to be within acceptance criteria without a need for 

evaluation, or the findings were evaluated by the Responsible Engineer and it was determined 

that the structural integrity of the containments were acceptable. The LRA also states that 

examples of these operating experiences demonstrate that the ASME Code Section XI, 

Subsection IWL program will be effective in ensuring that intended functions will be maintained 

consistent with the CLB for the period of extended operations.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicant reviewed the applicable aging effects and industry and site 

specific operating experience. 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 and resulted in the issuance of an RAI as discussed below.

The staff reviewed an issue report during the audit that identified corrosion and degradation of 

the steel metal deck (Q-deck), abandoned structural steel members attached to the underside of 

the concrete diaphragm slab above the suppression pool. Since the diaphragm slab is a part of 

the containment boundary and is included in the scope of ASME Code Section XI, 

Subsection IWL program, the staff was concerned about the effect of the degraded Q-deck and 

abandoned steel members on the emergency core cooling system (ECCS) through the period of 

extended operation. By letter dated January 30, 2012, the staff issued RAI B.2.1.31-3 

requesting information for the following issues:

(1) Identify the effects of Q-deck degradation on the concrete diaphragm slab, including 

potential degradation of rebar. 

(2) Discuss how the corrosion from the Q-deck and other abandoned steel structures 

attached to the ceiling of the suppression pool would impact the corrosion-product 

inventory in the suppression pool and the operation of the current ECCS suction 

strainers through the period of extended operation.

In its response dated February 12, 2012, the applicant stated that the Q-deck and the 

abandoned steel on the underside of the concrete diaphragm slab are included within the scope 

of license renewal and subject to aging management using the Structures Monitoring program. 

The applicant also stated that it has evaluated the condition of the Q-deck and found that the 

surface corrosion noted was acceptable and does not affect the structural integrity of the 

concrete diaphragm slab. The reinforcing steel embedded in the diaphragm slab is located 

above the Q-deck, and is not in contact with it. In addition, the shear studs embedded in the 

concrete are raised above the Q-deck, such that concrete separates the reinforcing steel from 

the Q-deck. The shear studs embedded in the diaphragm slab are also not attached to the 
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metal decking but rather are attached to the structural steel beams that are within the scope of 

license renewal and subject to the Structures Monitoring program. Therefore, the corrosion 

noted on the metal decking (Q-deck) will have no effect on the concrete diaphragm slab and 

reinforcing steel.

Regarding the concern about the potential impact of corrosion particles from the Q-deck on the 

ECCS suction strainers, the applicant stated that it has previously performed an evaluation that 

concluded that the corrosion from the Q-deck particles is bounded by the corrosion product 

inventory allowance for the ECCS suction strainers. In addition, the suppression pool floor and 

ECCS suction strainers are periodically inspected for sludge and foreign material accumulation. 

LRA Appendix A.5, Commitment No. 30 also requires removal of any accumulated sludge from 

the suppression pool every refueling outage. Therefore, there is no impact on the corrosion 

product inventory allowance and no impact on the operation of the ECCS suction strainers 

through the period of extended operation.

The staff finds the applicant’s response acceptable because the Q-deck is included within the 

scope of license renewal, and aging management is addressed by the Structures Monitoring 

program. The surface corrosion on the Q-deck is acceptable, and has no impact on the 

structural integrity of the concrete diaphragm slab. The reinforcing steel in the diaphragm slab 

are not in contact with the Q-deck, and therefore, is not likely to be degraded or corroded. 

Additional degradation, if any, of the Q-deck and structural steel beams will be managed by the 

Structures Monitoring program during the period of extended operation.

The corrosion from the Q-deck particles is bounded by the corrosion product inventory 

allowance in the design of the ECCS suction strainers. In addition, the existing ASME Code 

Section XI, Subsection IWE program will be enhanced to include removal of any accumulated 

sludge from the suppression pool every refueling outage to ensure that there is no impact on the 

operation of the ECCS suction strainers through the period of extended operation. The staff’s 

concern described in RAI B.2.1.31-3 is resolved.

Based on its audit and review of the application and review of the applicant’s response to 

RAI B.2.1.31-3, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience. Operating experience related to the applicant’s program 

demonstrates that it can adequately manage the effects of aging on SSCs within the scope of 

the program, and that implementation of the program has resulted in the applicant taking 

corrective actions. 

UFSAR Supplement. LRA Section A.2.1.31 provides the UFSAR supplement for the ASME 

Code Section XI, Subsection IWL 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 also noted that the UFSASR contained a 

commitment (Commitment No. 31) to enhance the existing ASME Code Section XI, 

Subsection IWL program to include the second-tier acceptance criteria of ACI 349.3R-02 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 ASME Code Section XI, Subsection IWL 

program, the staff determines that those program elements for which the applicant claimed 
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consistency with the GALL Report are consistent. Also, the staff reviewed the enhancement 

and confirmed that its implementation will make the AMP adequate to manage the applicable 

aging effects and that the UFSAR contained Commitment No 31 to implement the enhancement 

before the period of extended operation. 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 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).

3.0.3.2.15 ASME Code Section XI, Subsection IWF

Summary of Technical Information in the Application. LRA Section B.2.1.32 describes the 

existing ASME Code Section XI, Subsection IWF program as consistent, with an enhancement, 

with GALL Report AMP XI.S3, “ASME Code Section XI, Subsection IWF.” The LRA states that 

the program consists of periodic visual inspections for loss of material and loss of mechanical 

function for ASME Code, Section XI Class 1, 2, 3, and MC piping and component support 

members. The program also includes management of loss of material and loss of preload for 

structural bolting by inspecting for missing, detached, or loosened bolts and nuts. The LRA also 

states that the program includes preventive measures to ensure proper specification of bolting 

material, lubricant, and proper installation torque. The program was developed and 

implemented to comply with ASME Code, Section XI, Subsection IWF, 2001 Edition through the 

2003 Addenda, as approved in 10 CFR 50.55a, and as such, is updated each successive 

120-month inspection interval to comply with the requirements of the latest edition of the ASME 

Code specified twelve months before the start of the inspection interval. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.S3. For the “scope of program” and 

“preventive actions” program elements, the staff determined the need for additional information, 

which resulted in the issuance of RAIs, as discussed below.

The “scope of program” element in GALL Report AMP XI.S3 recommends that metal 

containment (MC) supports be examined as part of the ASME Code Section XI, Subsection IWF 

program. The “scope of program” element of the LRA AMP basis document states that the 

applicant examines MC piping and support members. However, during its audit, the staff found 

that the applicant’s program procedures specifically exempt MC supports from the scope of the 

ASME Code Section XI, Subsection IWF program. By letter dated January 30, 2012, the staff 

issued RAI B.2.1.32-1 requesting the applicant to explain why class MC supports are not 

included in the implementing documents for the ASME Code Section XI, Subsection IWF 

program and how these components will be managed for aging during the period of extended 

operation.

In its response dated February 28, 2012, the applicant stated that its procedures have been 

revised to clarify that ASME Code Class MC supports are visually inspected in accordance with 

the ASME Code Section XI, Subsection IWF program. The staff finds the applicant’s response 

acceptable because the ASME Code Section XI, Subsection IWF program implementing 

procedures have been revised to include visual inspections of Class MC supports in accordance 

with ASME Code Section XI, Subsection IWF and the GALL Report recommendations. The 

staff’s concern described in RAI B.2.1.32-1 is resolved.
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GALL Report AMP XI.S3 recommends that the program include visual inspections of 

high-strength structural bolting (actual measured yield strength greater than or equal to 150 ksi

or 1,034 MPa) for cracking. The “preventive actions” program element in GALL Report 

AMP XI.S3 recommends that for high-strength structural bolting consisting of ASTM A325, 

ASTM F1852, and/or ASTM A490 bolts, the preventive actions for storage, lubricants, and SCC

potential discussed in Section 2 of the Research Council for Structural Connections (RCSC)

publication, “Specification for Structural Joints Using ASTM A325 or A490 Bolts” need to be 

used. However, during its audit, the staff found discrepancies between program elements of the 

ASME Code Section XI, Subsection IWF program basis documents regarding the use of 

high-strength structural bolting. The “preventive actions” element states that structural bolting 

used in ASME Code Section XI, Subsection IWF program supports do not include ASTM A325, 

ASTM F1852, or ASTM A490 bolts. However, the “detection of aging effects” element states 

that while the use of high-strength bolts in supports is not common, A490 bolts are used for 

some larger supports. By letter dated January 30, 2012, the staff issued RAI B.2.1.32-2 

requesting the applicant to state whether high-strength structural bolting is used in any ASME 

Code Section XI, Subsection IWF program supports, and if so, whether the preventive actions 

for storage, lubricants, and SCC potential discussed in Section 2 of RCSC publication,

“Specification for Structural Joints Using ASTM A325 or A490 Bolts” are followed.

In its response dated February 28, 2012, the applicant stated that the structural bolting for 

ASME Code Section XI, Subsection IWF program supports do not include the use of ASTM 

A325, ASTM F1852 or ASTM A490 bolts, and that the “detection of aging effects” element of the 

AMP basis document will be revised to state that the structural bolting for ASME Code 

Section XI, Subsection IWF program supports does not include the use of ASTM A325, ASTM 

F1852, or ASTM A490 bolts. The staff reviewed the applicant’s response, as well as relevant 

portions of the LGS Units 1 and 2 UFSAR. In Table 3.9-6 of the UFSAR, several locations 

either call out SA325 bolts (the ASME equivalent to ASTM A325), or reference ASME Code, 

Division III, Subsection NF, which allows the use of SA325 bolts. It appears to the staff that 

there may be a discrepancy between the information in the UFSAR, and the information 

provided in the response to RAI B.2.1.32-2. Therefore, by letter dated June 5, 2012, the staff 

issued RAI B.2.1.32-2.1 requesting the applicant to verify no ASTM A325, F1852 or A490 bolts 

are within the scope of the ASME Code Section XI, Subsection IWF program. If those bolts are 

within the scope of the program, the applicant was requested to explain how the preventive 

actions discussed in Section 2 of the RCSC “Specification for Structural Joints Using ASTM 

A325 or A490 Bolts,” would be addressed.

By letter dated June 14, 2012, the applicant responded and stated that the bolts identified as 

SA 235 in the UFSAR were incorrectly identified. A walkdown and inspection of the bolts in 

question identified the bolts as ASTM A449. A CAP issue report was initiated to identify and 

resolve the discrepancy. The applicant further stated that for future installations or maintenance 

of supports within the scope of the ASME Code Section XI, Subsection IWF program may use 

material that is equivalent to ASTM A325. Therefore, the storage and handling preventive 

actions recommended in the GALL Report and the RCSC publication will be followed. The 

applicant explained that these recommendations are currently addressed by a commitment in 

the UFSAR supplement (Commitment No. 35), which applies to all carbon steel high-strength 

structural bolting, regardless of the ultimate use of the bolting material (i.e., Structures 

Monitoring program or ASME Code Section XI, Subsection IWF program supports).
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The staff reviewed the applicant’s response and noted that the Structures Monitoring program 

will be enhanced to incorporate the recommendations of the RCSC “Specification for Structural 

Joints Using ASTM A325 or A490 Bolts,” into its guidance for storage and handling of all carbon 

steel high-strength structural bolts. The staff finds the applicant’s response acceptable because 

the aging management for high-strength structural bolting within the scope of license renewal 

will be consistent with the GALL Report recommendations for preventive actions. The staff’s 

concern described in RAI B.2.1.32-2.1 is resolved.

The staff also reviewed the portions of the “preventive actions” 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. LRA Section B.2.1.32 states an enhancement to the “preventive actions”

program element. In this enhancement, the applicant stated that before the period of extended 

operation, the ASME Code Section XI, Subsection IWF program 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. GALL 

Report AMP XI.S3 states that selection of bolting materials, lubricants, and sealants should be 

in accordance with EPRI NP-5769, EPRI TR-104213, and the additional recommendations of 

NUREG-1339 to prevent or mitigate degradation and failure of safety-related bolting. 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 make the program 

consistent with the recommendations in GALL Report AMP by ensuring the proper 

specifications for structural bolting are used.

Based on its audit, and review of the applicant’s responses to RAIs B.2.1.32-1 and B.2.1.32-2 of 

the applicant’s ASME Code Section XI, Subsection IWF program, the staff finds that program 

elements 1-6 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 enhancement associated with the “preventive actions” program element and finds 

that when implemented; it will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.32 summarizes operating experience related to the 

ASME Code Section XI, Subsection IWF 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. In one operating experience 

example, the LRA states that an inspection identified a cold load setting for one support to be 

outside the 10 percent acceptance criterion. The scope of the inspection was expanded and 

four additional supports were also found to be outside of the acceptance criteria. An 

engineering evaluation was performed and it was determined that the supports were acceptable 

in the as-found condition. However, the supports were returned to the correct cold load settings 

and were re-inspected and found satisfactory 2 years later. 

During its audit, the staff noted several cases such as this in which conditions were found during 

ASME Code, Section XI, Subsection IWF examinations that appeared to be degraded, but 

where an engineering evaluation determined that the component was acceptable for continued 
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service (i.e., did not violate the acceptance standards of ASME Code Section XI, Subsection 

IWF-3410) and the applicant chose to rework the component to its as-new condition. The 

ASME Code, Section XI, Subsection IWF program requires the inspection of the same sample 

of the total population of component supports each inspection interval. The staff determined 

that for effective aging management of the entire population, the condition of the component to 

be re-examined during each inspection interval should be representative of the aging of the 

entire population. If ASME Code Section XI, Subsection IWF program supports that are part of 

the inspection sample are reworked to as-new condition, that support is no longer typical of the 

other supports in the population that were not reworked, and in subsequent examinations would 

not represent the age-related degradation of that population. Therefore, by letter dated 

January 30, 2012, the staff issued RAI B.2.1.32-3 requesting the applicant to explain, when 

corrective actions are not required per the ASME Code, Section XI, Subsection IWF acceptance 

criteria, but a support within the inspection sample is found degraded and repaired to as-new 

condition without an expansion or revision of the sample population, how the ASME Code 

Section XI, Subsection IWF program will be effective in managing aging of similar/adjacent 

components in that population that are not included in the ASME Code Section XI, 

Subsection IWF program sample. 

In its response dated February 28, 2012, the applicant stated that when component support 

conditions are found to include minor age-related degradation that does not meet the threshold 

of “unacceptable for continued service” as defined in ASME Code, Section XI, Subsection 

IWF-3400, an evaluation may be performed in accordance with the CAP. The applicant stated 

that it may choose to take actions on the subject component and will evaluate the need to 

substitute the support in subsequent inspections with a component that may be more 

representative of the general population. The applicant further stated that it will incorporate the 

above guidance into the AMP procedure, thus ensuring the ASME Code Section XI, 

Subsection IWF program is effective in managing aging of supports within the scope of the 

program. The staff finds this response acceptable because the applicant’s program will ensure 

that the component supports being examined in the ASME Code Section XI, Subsection IWF 

program inspection sample are representative of the aging of the total population, thus allowing 

the program to adequately manage aging of supports and bolting within the scope of the 

program.

Based on its audit and review of the application, and review of the applicant’s response to 

RAI B.2.1.32-3, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience, operating experience related to the applicant’s program that 

demonstrates it can adequately manage the effects of aging on SSCs within the scope of the 

program, and that implementation of the program has resulted in the applicant taking corrective 

actions. 

UFSAR Supplement. LRA Section A.2.1.32 provides the UFSAR supplement for the ASME 

Code 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 UFSAR supplement contains a commitment

(Commitment No. 32) to enhance the ASME Code Section XI, Subsection IWF program 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 

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 ASME Code Section XI, Subsection IWF 

program, the staff concludes that the program elements for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.S3. Also, the staff reviewed the enhancement and confirmed that its 

implementation will make the AMP adequate to manage the applicable aging effects and that 

the UFSAR supplement contained Commitment No. 32 to implement the enhancement before

the period of extended operation. 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).

3.0.3.2.16 Masonry Walls

Summary of Technical Information in the Application. LRA Section B.2.1.34 describes the 

existing Masonry Walls program as consistent, with enhancements, with GALL Report 

AMP XI.S5, “Masonry Walls.” The LRA states that the AMP is a condition monitoring program 

that provides for visual inspection of masonry walls for loss of material and cracking, and is 

enhanced to inspect for shrinkage or separation and for gaps between the supports and 

masonry walls that could impact the intended function of the walls. The LRA further states that 

the program is administered as part of the Structures Monitoring program, is based on guidance 

provided in NRC Bulletin 80-11 and NRC Information Notice (IN) 87-67, and is implemented 

through station procedures. Environments include uncontrolled indoor air and outdoor air. The 

LRA also states that masonry walls considered fire barriers are managed by the Fire Protection 

program and that steel edge supports and steel bracing were not required or used as part of the 

masonry wall design. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.S5. The staff also reviewed the plant 

conditions to determine whether they are bounded by the conditions for which the GALL Report 

was evaluated.

The staff 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.2.1.34 states an enhancement to the “scope of program,”

program elements. In this enhancement, the applicant stated that the administration building 

warehouse, fuel oil pumphouse, and transformer foundation dike walls and structures that 

include masonry walls, would be added to the program scope. 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, the masonry walls AMP will include all 

masonry walls for structures in scope for license renewal. 

Enhancement 2. LRA Section B.2.1.34 states an enhancement to the “parameters monitored or 

inspected,” and “acceptance criteria” program elements. In this enhancement, the applicant 

stated that it will provide additional guidance for inspection of masonry walls for shrinkage, 
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separation, and for gaps between the supports and walls that could affect the wall’s intended 

function. 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 be 

consistent with industry standard and the GALL report.

Enhancement 3. LRA Section B.2.1.34 states an enhancement to the “detection of aging 

effects” program elements. In this enhancement, the applicant stated that the Masonry Wall 

program will have an inspection frequency of not greater than 5 years. 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, the 5-year inspection frequency will bring 

the program into alignment with the guidance in ACI 349.3R, which is the industry standard.

Enhancement 4. LRA Section B.2.1.34 states an enhancement to the “detection of aging 

effects,” program elements. In this enhancement, the applicant stated that program procedures 

will require that personnel performing inspections and evaluations meet the qualifications 

specified within ACI 349.3R. 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 bring the program into alignment with the guidance in ACI 349.3R, which is 

the industry standard.

Based on its audit of the Masonry Walls program, the staff finds that program elements 1-6 for 

which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.S5. 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, the AMP will be adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.34 summarizes operating experience related to the 

Masonry Walls program. The LRA states that structures monitoring inspections from 2007 

through 2010 included inspections of masonry walls and identified no significant deficiencies. 

There have been a few instances of acceptable hairline surface cracks, but no other 

degradation or significant cracks were noted. The LRA states that cracking caused by impact 

from plant equipment was identified on a masonry wall dike and subsequently repaired. The 

structures monitoring inspections completed in 2006 also did not identify any unacceptable 

cracking or gaps in masonry walls; however, minor surface cracking was noted on masonry 

walls in the LGS Unit 2 turbine enclosure near the feed water heater area. The LRA states that 

the cracking was noted previously and no changes were observed.

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 also performed a walkdown of the turbine enclosure and noted the 

surface cracking referenced in LRA section B.2.1.34. The staff noted that the surface cracking 

is minor and that the applicant is monitoring the cracks for any changes in condition. During its 

review, the staff found no operating experience to indicate that the applicant’s program would 

not be effective in adequately managing aging effects during the period of extended operation.
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Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. 

UFSAR Supplement. LRA Section A.2.1.34 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 UFSAR supplement contained a commitment (Commitment No. 34) 

to enhance the program by (1) adding to its scope the administration building warehouse, fuel 

oil pumphouse, transformer foundation dike walls, (2) providing additional guidance for 

inspection of masonry walls for shrinkage, separation, and for gaps between the supports and 

walls that could impact the wall’s intended function, (3) requiring an inspection frequency of not 

greater than 5 years, and (4) requiring that personnel performing inspections and evaluations 

meet the qualifications specified within ACI 349.3R. These enhancements will be implemented 

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 Masonry Walls program, the staff 

determines that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that 

their implementation will make the AMP adequate to manage the applicable aging effects and 

that the UFSAR supplement contained Commitment No. 34 to implement the enhancements 

before the period of extended operation. 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).

3.0.3.2.17 Structures Monitoring

Summary of Technical Information in the Application. LRA Section B.2.1.35 describes the 

existing Structures Monitoring program as consistent, with enhancements, with GALL Report 

AMP XI.S6, “Structures Monitoring.” The LRA states that the AMP through periodic monitoring 

assesses the condition of structures and structural components, structural bolting, component 

supports, masonry block walls, and elastomers exposed to outdoor air, uncontrolled indoor air, 

treated water, raw water, flowing water, and ground water and soil environments. The LRA 

further states that concrete is inspected for evidence of leaching, loss of material, cracking, and 

a loss of bond; steel components are inspected for loss of material caused by corrosion; 

masonry walls are inspected for cracking and loss of material; elastomers are monitored for 

hardening, shrinkage, and a loss of sealing; and per LRA update dated April 13, 2012, 

fiberglass fabric of the permanent drywell shielding blankets will be monitored for rips and tears. 

The program also provides for periodic testing and assessment of ground water chemistry and 

inspection of accessible below grade concrete structures. Inspections are conducted on a 

frequency not to exceed 5 years, and when warranted more frequently, to maintain structures’ 
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and components’ intended function(s). Unacceptable conditions are corrected in accordance 

with the CAP. 

The LRA also states that the AMP was developed to meet the regulatory requirements of 

10 CFR 50.65, “Maintenance Rule,” as well as the guidance contained in RG 1.160, “Monitoring 

the Effectiveness of Maintenance at Nuclear Power Plants,” and in NUMARC 93-01, “Industry 

Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.” The 

program includes the inspection of masonry walls to be evaluated in accordance with NRC 

IEB 80-11, “Masonry Wall Design” and incorporates guidance of NRC IN 87-67, “Lessons 

Learned from Regional Inspection of Licensee Actions in Response to IE Bulletin 80-11.” The 

LRA further states that the Structures Monitoring program will be enhanced for consistency with 

ACI 349.3R-02. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S6. For the “monitoring and 

trending” program element the staff determined the need for additional information, which 

resulted in the issuance of an RAI, as discussed below.

The “monitoring and trending” program element in GALL Report AMP XI.S6 recommends that 

the existing Structures Monitoring program monitor structures and components in accordance 

with 10 CFR 50.65 and RG 1.160 Revision 2, Regulatory Position 1.5; structures and 

components within the scope of the maintenance rule are to be monitored in accordance with 

10 CFR 50.65(a)(2) if inspection results do not identify significant degradation; and the program 

is to contain provisions for increased inspection frequency and trending for structures and 

components in accordance with 10 CFR 50.65(a)(1). However, during its audit, the staff found 

that although the Structures Monitoring program recommends these actions, it was not clear 

that these statements are consistent because a plant-specific TLAA or inspection/surveillance 

program does not exist to provide assurances that the capability of the prestressed concrete 

girders associated with the SFP will continue to meet their intended function(s) during the period 

of extended operation. By letter dated January 30, 2012, the staff issued RAI B.2.1.35-1 

requesting the applicant to provide a plant-specific TLAA or inspection/surveillance program to 

provide assurances that the capability of the prestressed concrete girders will continue to meet 

their intended function(s) during the period of extended operation.

In its response dated February 28, 2012, the applicant stated that the original design analysis 

for the fuel pool girders evaluated the loss of prestress caused by stress relaxation of the steel 

tendons and caused by creep and shrinkage of the concrete. The applicant also stated that 

since stress relaxation of the steel tendons is based upon a time-limited assumption, this 

analysis has been identified in the “updated” LRA as TLAA 4.6.10, and as such it requires 

evaluation for the period of extended operation. The applicant further stated that theTLAA was 

demonstrated to remain valid in accordance with 10 CFR 54.21(c)(1)(i) because the loss of 

prestress values used in the analysis are valid for over 60 years. In addition, the applicant 

stated that the fuel pool girders are included within the scope of the Structures Monitoring 

program B.2.1.35 and that the girders are visually examined once every 5 years for signs of 

concrete cracking or other degradation. Finally, the applicant stated that this program provides 

additional assurance that the fuel pool girders will continue to perform their intended function(s)

during the period of extended operation.
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The staff reviewed the applicant’s response to RAI B.2.1.35-1 and confirmed that the revised 

LRA addresses the “Fuel Pool Girder Loss of Prestress,” in section 4.6.10, and its UFSAR 

supplement, A.4.6.10, as a TLAA, which is reviewed in SER Section 4.6.10. For the visual 

examination of the prestress girders, the staff reviewed the applicant’s response and confirmed

that the fuel pool girders, as structural components, are included within the scope of the 

program. The staff also noted that girders are visually examined as recommended by ACI 

349.3R-02 once every 5 years for signs of deterioration, rust stains, and concrete cracking. The 

staff also reviewed the LGS Units 1 and 2 UFSAR and noted that the spent fuel pool girders 

have multi-layer protection. On the pool side, a metallic liner that requires compliance with the 

requirements of 10 CFR 50, Appendix B (UFSAR Table 3.2-1, “LGS Design Criteria Summary”), 

keeps the water from direct contact with the concrete structure and its reinforcement. A free 

gravity leakage collection system assures expedient detection of leaks and further inhibits 

corrosion formation on tendons and reinforcement. The pool structure is made from dense 

concrete having compressive strength of 5,000 psi (UFSAR 3.8.6.1.2.2, “Concrete Mix 

Proportions”) which is the desired strength of concrete to minimize crack widths thereby limiting 

water access to the reinforcement per ACI 201, “Guide to Durable Concrete,” referenced by ACI 

318, “Building Code Requirements for Structural Concrete,” which is the code of record used in 

the pool construction (UFSAR 3.8.4.4, “Design and Analysis Procedures”). Cementitious grout 

assures the sealing of the tendons. All of these layers of protection enhance structural durability 

of the girders and have also been recognized to enhance structural performance, as articulated 

in 2002 VSL International report, “Grouting of Post-Tensioning Tendons.” The staff finds the 

applicants response acceptable because the fuel pool girders are within the scope of the 

Structures Monitoring program and visually examined once every 5 years for signs of concrete 

cracking or other degradation, which is consistent with the recommendations in GALL Report 

AMP XI.S6. The staff’s concern described in RAI B.2.1.35-01 is resolved.

 

The staff also reviewed the portions of the “scope of program,” “preventative actions,” 

“parameters monitored or measured,” “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 states an enhancement to the “scope of program” 

program element. In this enhancement, the applicant stated that the following structures will be 

added to the Structures Monitoring program: admin building warehouse, fuel oil pumphouse,

SW pipe tunnel, and yard structures (auxiliary fire water storage tank foundation, backup fire 

pump house and foundation, well pump #3 enclosure and foundation, railroad bridge, manholes 

001 and 002, fuel oil storage tank dike, transformer foundations and dikes). The staff reviewed 

this enhancement against the corresponding program element in GALL Report AMP XI.S6 and 

finds it acceptable because, when it is implemented, it will add structures to the Structures 

Monitoring program that are included in the scope of license renewal.

Enhancement 2. LRA Section B.2.1.35 states an enhancement to the “scope of program” 

program element. In this enhancement, the applicant stated that the following components and 

commodities will be added to the Structures Monitoring program: pipe, electrical, and 

equipment component supports; pipe whip restraints and jet impingement shields; panels, 

racks, and other enclosures; sliding surfaces; sump and pool liners; electrical duct banks; tube 

racks; doors; penetration seals; blowout panels, and per LRA revision dated April 13, 2012, 

permanent drywell shielding and roof scuppers. The staff reviewed this enhancement against 

the corresponding program element in GALL Report AMP XI.S6 and finds it acceptable 
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because, when it is implemented, it will add components and commodities to the Structures 

Monitoring program that are included in the scope of license renewal.

Enhancement 3. LRA Section B.2.1.35 states an enhancement to the “scope of program,”

“parameters monitored or inspected,” and “detection of aging affects” program elements. In this 

enhancement, the applicant stated that the groundwater chemistry will be monitored on a 

frequency not to exceed 5 years for pH, chlorides, and sulfates, and verify that it remains 

nonaggressive, or evaluate results exceeding criteria to assess the 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 be consistent with the recommendations of GALL Report AMP XI.S6, for the 

aging management of below-grade structures and components.

Enhancement 4. LRA Section B.2.1.35 states an enhancement to the “preventative actions” 

program element. In this enhancement, the applicant stated that guidance will be provided 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 storage conditions will be 

revised for high-strength bolts to include recommendations of the RCSC Specification for 

Structural Joints Using High-Strength Bolts, Section 2.0. The staff reviewed this enhancement 

against the corresponding program element in GALL Report AMP XI.S6 and finds it acceptable 

because when implemented, the recommended preventative actions identified in the GALL 

Report AMP will be included consistent with the guidance in NUREG-1339, EPRI NP-5769, 

EPRI NP-5067, and EPRI TR-104213 to ensure structural bolting integrity.

Enhancement 5. LRA Section B.2.1.35 states an enhancement to the “parameters monitored or 

inspected” program element. In this enhancement, the applicant stated that concrete will be 

monitored for areas of abrasion, erosion, and cavitation degradation, drummy areas that exceed 

the cover concrete thickness in depth, popouts and voids, scaling, and passive settlements and 

deflections. The staff reviewed this enhancement against the corresponding program element 

in GALL Report AMP XI.S6 and finds it acceptable because when it is implemented, it will 

include the parameters monitored or inspected identified in industry codes, standards, and 

guidelines (i.e., ACI 349.3R and ANSI/American Society of Civil Engineers (ASCE) 11) as 

recommended in GALL Report AMP XI.S6. Furthermore, this enhancement will provide the 

background to support inspections for loss of material for reinforced concrete exposed to flowing 

water and for inspections of the concrete foundation of accessible and inaccessible areas of the 

cooling tower basin slab. 

Enhancement 6. LRA Section B.2.1.35 states an enhancement to the “detection of aging 

affects” program element. In this enhancement, the applicant stated that inspections of 

structures will be performed at a frequency not to exceed 5 years. The staff reviewed this 

enhancement against the corresponding program element in GALL Report AMP XI.S6 and finds 

it acceptable because when it is implemented, it will monitor all structures at a frequency not to 

exceed 5 years as noted in RG 1.160 (Revision 2), ACI 349.3R, and as recommended in GALL 

Report AMP XI.S6. 

Enhancement 7. LRA Section B.2.1.35 states an enhancement to the “parameters monitored or 

inspected” and “detection of aging affects” program elements. In this enhancement, the 

applicant stated that inspections of the subdrainage sump pit internal concrete will be performed 

on a 5-year frequency as a leading indicator of the condition of the below-grade concrete 

exposed to ground water. The LRA further notes that the “parameters monitored or inspected” 
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program element will be enhanced to require opportunistic inspections of structures in the event 

an excavation is performed that exposes normally inaccessible concrete, and that evaluation of 

the acceptability of inaccessible areas is required when conditions exist in accessible areas that 

could indicate the presence of, or result in, degradation to such inaccessible areas. The staff 

reviewed this enhancement and finds it acceptable because when it is implemented, it will 

monitor the subdrainage sump pit internal concrete at a frequency not to exceed 5 consistent 

with the recommendations in GALL Report AMP XI.S6, and the condition of the subdrainage 

sump pit internal concrete can serve as a guide for the condition of the below-grade concrete 

since it is exposed to similar ground water conditions.

Enhancement 8. LRA Section B.2.1.35 states an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that personnel performing 

inspections and evaluations will meet the qualifications specified in 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 incorporate 

recommendations provided in GALL Report AMP XI.S6.

Enhancement 9. LRA Section B.2.1.35 states an enhancement to the “detection of aging 

effects” and “acceptance criteria” program elements. In this enhancement, the applicant stated 

that elastomeric vibration elements and structural seals will be inspected for cracking, loss of 

material, and hardening; visual inspections of elastomeric vibration elements are to be 

supplemented by manipulation to detect hardening when vibration isolation function is suspect. 

It is further noted in the LRA that the elastomeric vibration isolation elements are acceptable if 

loss of material, cracking, and hardening will not result in loss of sealing or loss of isolation 

function, and there has been no loss of material caused by corrosion or wear. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.S6 and finds them acceptable because when it is implemented, the enhancements will 

incorporate recommendations provided in GALL Report AMP XI.S6.

Enhancement 10. LRA Section B.2.1.35 states an enhancement to the “detection of aging 

effects” and “acceptance criteria” program elements. In this enhancement, the applicant stated 

that sliding surfaces will be monitored to detect significant loss of material caused by wear, 

corrosion, debris, or dirt that could result in lock-up or reduced movement. The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP XI.S6 and 

finds them acceptable because when it is implemented, the enhancements will incorporate 

recommendations provided in GALL Report AMP XI.S6.

Enhancement 11. LRA Section B.2.1.35 states an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that opportunistic 

inspections will be performed of below-grade portions of in-scope structures in the event 

excavation exposes normally inaccessible 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 for opportunistic inspections of 

excavated normally inaccessible below-grade concrete structures and of inaccessible concrete 

if accessible concrete indicates degradation or the potential for degradation in inaccessible 

areas. This enhancement when incorporated will implement recommendations in the GALL 

Report AMP for aging management of below-grade concrete structures and components.

Enhancement 12. LRA Section B.2.1.35 states an enhancement to the “acceptance criteria” 

program element. In this enhancement, the applicant stated that acceptance criteria noted in 
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ACI 349.3R will be included. 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 incorporate recommendations in the GALL Report AMP XI.S6 that 

acceptance criteria be in compliance with those identified in ACI 349.3R. 

Enhancement 13. LRA Section B.2.1.35 states an enhancement to the “acceptance criteria” 

program element. In this enhancement, the applicant stated that loose bolts and nuts and 

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 incorporates the 

recommendations in GALL Report AMP XI.S6. 

Based on its audit, and review of the applicant’s response to RAI B.2.1.35-01 of the Structures 

Monitoring program, the staff finds that program elements 1-6 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 

“scope of program,” “preventative actions,” “parameters monitored or measured,” “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 

Structures Monitoring program. Operating experience is reviewed from external and internal 

(also referred to as in-house) sources. External operating experience may include such things 

as INPO documents (e.g., significant operating experience reports (SOERs), significant event 

reports, significant event notifications (SENs), etc.), NRC documents (e.g., GLs, licensee event 

reports (LERs), INs, etc.), and other documents (e.g., 10 CFR Part 21 Reports, nuclear event 

reports (NERs), etc.). Internal operating experience may include such things as event 

investigations, trending reports, and lessons learned from in-house events as captured in 

program notebooks, self-assessments, and in the 10 CFR Part 50, Appendix B CAP. 

Demonstration that the effects of aging are effectively managed is achieved through objective 

evidence that shows that aging effects and mechanisms are being adequately addressed 

through inspections and the CAP with appropriate actions taken, and resolutions sought, when 

issues are identified that could affect structures’ intended function(s). Followup inspections are 

performed on certain conditions at an increased frequency to ensure that subsequent changes 

will be identified and evaluated before there is an impact on the intended function of a structure. 

In addition, the applicant performs self-assessments and uses the results of the assessments to 

enhance the 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 the audit the staff discussed with the applicant the intermittent leakage from the SFP. 

The staff noted that the leakage is discussed both in the LRA and in the Structures Monitoring 

program basis document. In the description of the leakage, the staff noted that the “E” drain line 

connected to the LGS Unit 2 SFP liner leak chase channels has been leaking about 10 ounces 

of SFP water per day since 1991. The staff expressed its concern to the applicant that the leak 
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chase channels may be blocked resulting in the limited leakage. The applicant stated that 

sampling confirmed the leakage to be from the pool but it does not endanger the SFP makeup 

capability, as it remains small and unchanging. The applicant also stated that all eight valves of 

the leak chase system are opened daily to monitor the leakage. The applicant further stated 

that in October of 2010, they confirmed through nitrogen pressurization that there is flow 

through each of the leak chase lines and that when significant deviations of monthly 

measurements of leakage volume are noted they are entered into the CAP. The applicant also 

stated that visual examinations of accessible concrete surfaces based on the inspection 

procedures of the Structures Monitoring program have indicated that there is no external 

evidence of leakage on the pool walls and floor, assuring both the integrity of the structure and 

containment of leakage within the leak chase channels. The staff finds the applicant’s response 

acceptable because (1) the valves of the leak chase system are opened daily to monitor for 

leakage, (2) flow has been confirmed to be contained within the leak chase lines (3) monthly 

measurements of leakage volume are made followed by visual examinations of accessible 

concrete surfaces under the Structure’s Monitoring program, and (4) when significant deviations 

are observed, they are addressed through the CAP.

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. 

The staff noted that the turbine building operating floor consists of the turbine pedestal and 

concrete slab on steel beams in all other floor areas. The ends of the steel beams adjacent to 

the turbine pedestal are supported by concrete ledges of the turbine pedestal. The other ends 

of the beams are supported by steel girders. The beam seat assemblies supported by the 

turbine pedestal consist of sliding surface plates, backup plates, and elastomeric pads. A 

walkdown by the applicant found that the beam ends supported by the turbine pedestal had 

settled approximately 0.5 inches as a result of deterioration/melting of the elastomeric pads. 

This condition was observed at almost all locations around the entire turbine pedestal expansion 

joint of both LGS Units 1 and 2. It was unclear to the staff if the turbine building operating floor 

and structure could still meet its intended functions and that the resulting change in alignment 

does not impact attachments or supports. By letter dated January 30, 2012, the staff issued 

RAI 2.1.35-2 requesting that the applicant provide the assessment demonstrating that the 

turbine building operating floor and structure can still perform its intended functions (e.g., 

supporting loads from the operating floor) and that the resulting change in alignment does not 

impact attachments or supports (e.g., pipe support anchor for the main steam line attached to a 

beam web does not induce stress into the pipe).

In its response dated February 28, 2012, the applicant confirmed that the change in alignment 

of the turbine enclosure operating floor and structure was caused by degraded/melted 

elastomeric pads, included as part of the sliding bearing assemblies located below the turbine 

operating deck floor beams. The applicant stated that the “comparatively small change in 

alignment” does not affect the load bearing capacity of the floor nor does it impact any turbine 

attachments or related supports (e. g., pipe support anchor for the main turbine sealing steam 

line attached to a beam web). The applicant further stated that they have evaluated the 

degraded elastomeric pads through the CAP and concluded that their current state does not 

affect the structural integrity of the turbine enclosure. A further assessment of this condition 

indicated that the degraded urethane elastomeric bearing pads between the beam end bearing 

plates and the concrete ledge resulted in a rotational change in alignment of the beams caused 

by 1/2-inch downward displacement at one end. The applicant also stated that there were no 

significant adverse structural effects on the operating concrete floor, beam structure, and turbine 
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pedestal. The applicant stated that the elastomer was not considered in the design to dampen 

any floor vibrations and that the massive freestanding reinforced concrete turbine-generator 

pedestals are founded on rock at the same level as the basemat for the turbine enclosure. The 

applicant further stated that there are no adverse structural effects, significant vibration, or 

visible distress from vibration on the turbine-generator pedestal concrete or on the adjacent 

turbine operating floor and steel beams, which are periodically monitored by the Structures 

Monitoring program.

The applicant further stated that although additional investigation caused by misalignment, 

settlement, or rotation may be pursued through the CAP given the inherent flexibility of the 

3-inch diameter main turbine steam seal leakoff piping, the induced secondary stresses would 

not be significant. The applicant also stated that there is no impact on safety-related piping and 

supports in the turbine enclosure. The applicant also stated that the safety-related portion of 

main steam piping supported from structural steel that is not affected by the displacement 

created by degraded elastomeric pads extends from the reactor enclosure wall penetration to 

the main turbine stop valves. The applicant further stated that the remainder of the main steam 

supply piping to the main turbine is of large diameter designed with a support system to 

accommodate large thermal movements.

The applicant also stated that the support system of the piping between the main turbine stop 

valves and main turbine is composed of variable supports with a comparatively large distance 

between supports such that the settlement of 0.5 inches at the end of the turbine pedestal has 

little impact on design loads and thermal displacements. The applicant also stated that the main 

turbine steam supply piping to the low-pressure turbines is supported from the turbine pedestal 

such that loads on the low-pressure turbine nozzles are unaffected by the degraded elastomeric 

pads and that piping supported from the structural steel affected by the degraded elastomeric 

pads is conventional piping, i. e. nonsafety-related and nonseismic. The applicant further stated 

that the installation tolerances for these piping systems are greater than the maximum 

displacement caused by the degraded pads. The applicant also stated that although the 

displacement is the greatest at the end of the beams supported by the turbine pedestal, the 

displacement is reduced as a function of distance from the turbine pedestal and therefore, no 

significant impact is expected on these piping systems. The applicant also stated that there 

have been no leaks or cracks in piping observed in the affected piping systems that are 

attributed to the alignment change associated with the elastomeric pad degradation.

The staff reviewed the applicant’s response and noted that the LRA assigns in Table 3.5.1, 

“Summary of Aging Management Evaluations for Structures and Component Supports,” item 

3.5.1-72 (seals; gasket; moisture barriers – caulking, flashing, and other sealants) and the 

Structures Monitoring program to manage loss of sealing caused by deterioration of seals, 

gaskets, and moisture barriers (caulking, flashing, and other sealants) of structures. The staff 

also noted an assignment report states that the elastomeric pads have degraded/melted, 

leading to a settlement of the steel beams by 0.5 inch. The staff also noted that the elastomeric 

pads are subject to loads and are part of the sliding bearing assemblies located below the 

turbine operating deck floor beams and, according to the LRA, permit the release of lateral 

forces. The staff further noted that Enhancement 9 to the Structures Monitoring program 

addresses inspection of elastomeric vibration isolation elements and structural seals for 

cracking, loss of material and hardening. Furthermore, the staff noted that enhancement 10

specifically addresses monitoring of accessible sliding surfaces. According to the RAI response 

the applicant continues to monitor the aging effects of the degraded elastomeric pad(s) by 
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claiming AMR item consistency in Table 3.5.2-16, “Turbine Enclosure Summary of Aging 

Management Evaluation.” 

The staff finds the applicant’s response acceptable because the enhanced Structures 

Monitoring program will monitor accessible sliding surfaces and has entered the degraded 

elastomeric pads in its CAP where the initial assessment of this condition is to be further 

evaluated. The staff’s concern described in RAI B.2.1.35-2 is resolved.

Based on its audit, review of the application, and review of the applicant’s responses to RAI 

B.2.1.35-2, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience. Operating experience related to the applicant’s program 

demonstrates that it can adequately manage the effects of aging on SSCs within the scope of 

the program, and that implementation of the program has resulted in the applicant taking 

corrective actions. 

UFSAR Supplement. LRA A.2.1.35 provides the UFSAR supplement for the Structures 

Monitoring program, as revised by letter dated April 13, 2012. 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 UFSAR supplement contained 

a commitment (Commitment No. 35) to enhance the Structures Monitoring program as 

described above, before entering 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 Structures Monitoring program, the staff 

determines that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that 

their implementation will make the AMP adequate to manage the applicable aging effects and 

the UFSAR supplement contained Commitment No. 35 to implement the enhancements before

the period of extended operation. 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). 

3.0.3.2.18 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants

Summary of Technical Information in the Application. LRA Section B.2.1.36 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 program 

monitors the condition of the spray pond and pumphouse and the yard facility dikes (around the 

CST storage tank) structural components and commodities. The LRA states that the AMP 

addresses reinforced concrete, steel (screens, frames and miscellaneous steel) members and 

components, and earthen water-control structures (embankments and dikes) exposed to 

uncontrolled indoor air, outdoor air, raw water, standing water, flowing water, ground water, and 

soil to manage loss of material, loss of preload, cracking, loss of bond, loss of material (spalling, 
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scaling) and cracking, increase in porosity and permeability, loss of strength, or loss of form. 

The program addresses age-related deterioration, degradation because of extreme 

environmental conditions, and the effects of natural phenomena that may affect the safety 

function of the water-control structures. The LRA also states that elements of the program are 

designed to detect degradation through inspections and evaluations and take corrective action 

to prevent a loss of intended function. The LRA further states that the AMP and monitoring of 

water-control structures is based on the guidance provided in NRC RG 1.127and 

ACI 349.3R-02. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP XI.S7. 

The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” 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.2.1.36 states an enhancement to the “preventive actions,”

“parameters monitored or inspected,” and “acceptance criteria” program elements. In this 

enhancement, the applicant stated that inspection of structural bolting integrity will be required 

to identify loss of material and loosening of bolts. 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 ensure that bolting in contact with raw water and outdoor 

air associated with the spray pond pump house and yard facility dikes around the condensate 

storage tank (CST) is inspected on both a routine and a condition-driven frequency. Also, 

recommended preventative actions, as identified in the relevant GALL Report AMPs, will be 

included consistent with the referenced NUREG-1339, EPRI NP-5769, EPRI NP-5067, and 

EPRI TR-104213 documents to ensure structural bolting integrity. 

Enhancement 2. LRA Section B.2.1.36 states an enhancement to the “parameters monitored or 

inspected” program element. In this enhancement the applicant stated that monitoring is 

required for aging effects of increased porosity and permeability of concrete structures and loss 

of material for steel components. The staff reviewed this enhancement against the 

corresponding program element in GALL Report AMP XI.S7 and finds it acceptable because 

when it is implemented, it will include GALL Report AMP recommended guidelines for 

parameters monitored or inspected identified in ACI 349.3R and ACI 201.1.

Enhancement 3. LRA Section B.2.1.36 states an enhancement to the “parameters monitored or 

inspected” program element. This enhancement will require the proper functioning of the dike 

drainage system. The staff reviewed this enhancement against the corresponding program 

element in GALL Report AMP XI.S7 and finds it acceptable because when it is implemented, it 

will include the recommended guidelines for proper functioning of drainage systems of the GALL 

Report AMP.

Enhancement 4. LRA Section B.2.1.36 states an enhancement to the “detection of aging 

effects” program element. In this enhancement the applicant stated that increased inspection 

frequency is required if the extent of degradation is such that the structure or component may 

not meet its design basis if allowed to continue uncorrected until the next normally scheduled 
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inspection. The staff reviewed this enhancement against the corresponding program element in 

GALL Report AMP XI.S7 and finds it acceptable because when it is implemented, it will 

incorporate recommendations in GALL Report AMP.

Enhancement 5. LRA Section B.2.1.36 states an enhancement to the “detection of aging 

effects” program element. In this enhancement the applicant stated that evaluation of the 

acceptability of inaccessible areas of concrete will be required when conditions exist in 

accessible areas that could indicate the presence of, or result in, degradation to such 

inaccessible areas, and examination of exposed portions of below-grade concrete is required 

when excavated for any reason. The staff reviewed this enhancement against the 

corresponding program elements in the GALL Report XI.S7 and finds it acceptable because 

when it is implemented, it will incorporate recommendations in the GALL Report AMP for aging 

management of below-grade structures and structural components. 

Enhancement 6. LRA Section B.2.1.36 states an enhancement to the “detection of aging 

effects” program element. In this enhancement the applicant stated that raw water chemistry 

will be monitored at least every 5 years for pH, chlorides, and sulfates, and that it will confirm

that the raw water remains nonaggressive, and when results exceed criteria an evaluation of the

impact on submerged concrete will be required. The staff reviewed this enhancement against 

the corresponding program element in GALL Report AMP XI.S7 and finds it acceptable because 

when it is implemented, it will include recommendations in the GALL Report AMP for aging 

management of below-grade concrete structures and structural components. 

Enhancement 7. LRA Section B.2.1.36 states an enhancement to the “detection of aging 

effects” program element. In this enhancement the applicant stated that visual examinations of 

the spray pond and pumphouse submerged wetwell concrete will be required during 

maintenance activities and if significant degradation is identified a plant-specific AMP should be 

implemented to manage concrete aging during the period of extended operation. The staff 

reviewed this enhancement against the corresponding program element in GALL Report 

AMP XI.S7 and finds it acceptable because, when it is implemented, it will require visual 

inspections of the spray pond and pumphouse submerged wetwell concrete for signs of 

degradation consistent with recommendations in the GALL Report AMP. 

Enhancement 8. LRA Section B.2.1.36 states an enhancement to the “monitoring and trending”

program element. In this enhancement, the applicant stated that active cracks in structural 

concrete shall be documented and trended until the condition is no longer occurring or until a 

corrective action is implemented. The staff reviewed this enhancement against the 

corresponding program element in GALL Report AMP XI.S7 and finds it acceptable because, 

when it is implemented, it will be consistent with the recommendations in the GALL Report AMP

for trending of changes of a degraded condition from previous inspections until it is evident that 

the change is no longer occurring or until corrective actions are implemented.

Enhancement 9. LRA Section B.2.1.36 states an enhancement to the “acceptance criteria”

program element. In this enhancement, the applicant stated that acceptance and evaluation of 

structural concrete be based on quantitative criteria of Chapter 5 of ACI 349.3R. The staff 

reviewed this enhancement against the corresponding program element in GALL 

AMP Report XI.S7 and finds it acceptable because when it is implemented, it will comply with 

recommendations in the GALL Report AMP that acceptance criteria be in accordance with 

criteria identified in ACI 349.3R. 
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Enhancement 10. LRA Section B.2.1.36 states an enhancement to the “preventive actions”

program element. In this enhancement the applicant stated that guidance will be provided 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 element in GALL Report AMP XI.S7 and finds 

it acceptable because when it is implemented, recommended preventative actions will be 

included consistent with NUREG-1339, EPRI NP-5769, EPRI NP-5067, and EPRI TR-104213 

guidance to ensure structural bolting integrity.

Based on its audit of the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants program, the staff finds that program elements 1-6 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 1-10 

associated with the “preventive actions,” “parameters monitored or inspected,” “detection of 

aging effects,” “monitoring and trending,” and “acceptance criteria” program elements and finds 

them acceptable as discussed above. 

Operating Experience. LRA Section B.2.1.36 summarizes operating experience related to 

RG 1.127 Inspection of Water-Control Structures Associated with Nuclear Power Plants 

program. Operating experience is reviewed from external and internal (also referred to as 

in-house) sources. External operating experience may include such things as Institute of 

Nuclear Power Operations (INPO) documents (e.g., SOERs, significant event reports, SENs, 

etc.), NRC documents and the applicant’s responses (e.g., GLs, LERs, INs, etc.) where 

appropriate, and other documents (e.g., 10 CFR Part 21 Reports, NERs, etc.). Internal 

operating experience may include such things as event investigations, trending reports, and 

lessons learned from in-house events as captured in program documentation, 

self-assessments, and in the 10 CFR Part 50, Appendix B, CAP. 

Demonstration that the effects of aging are effectively managed is achieved through objective 

evidence that shows that aging effects and mechanisms are being adequately managed. For 

example, the program-basis documentation indicated that in 2009 the results of the annual

maintenance activity for measuring the spray pond silt depth through ultrasonic measurements 

indicated an increase in the rate of deposits. The monitoring frequency then was increased, 

based on the increasing trend of silt build-up, from once a year, to once every 6 months. The 

expected silt depth at the next measurement is projected, based on the deposition rate, to 

ensure that silt will not exceed acceptable levels. The program basis documentation also noted 

that as part of the preventative maintenance program the spray pond and pumphouse 

submerged wetwell concrete are visually inspected using criteria and personnel qualifications 

meeting the requirements of ACI 349.3R. The LRA discusses the applicant’s approach to a 

removal of vegetative growth near the spray pond and pumphouse following a 2009 periodic 

inspection of these structures. An issue report was initiated and the vegetation was removed. 

The LGS operating experience indicates that periodic inspections and walkdowns are routinely

performed to identify conditions that could affect the intended function of these water-control 

structures. Conditions requiring corrective actions are identified and preventative maintenance 

is performed and implemented so that the water-control structures continue to maintain their 

intended functions(s).

Based on its audit and review of the application the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 
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aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. 

UFSAR Supplement. LRA Section A.2.1.36 provides the UFSAR supplement for 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 UFSAR 

supplement contains a commitment (Commitment No. 36) to enhance the RG 1.127, Inspection 

of Water-Control Structures Associated with Nuclear Power Plants program as described above.

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 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. Also, the staff reviewed the enhancements and confirmed that their implementation 

will make the AMP adequate to manage the applicable aging effects and that the UFSAR 

supplement contained Commitment No. 36 to implement the enhancements before the period of 

extended operation. 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). 

3.0.3.2.19 Protective Coating Monitoring and Maintenance Program

Summary of Technical Information in the Application. LRA Section B.2.1.37 describes the 

existing Protective Coating Monitoring and Maintenance Program as consistent, with an 

enhancement, to GALL Report AMP XI.S8, “Protective Coating Monitoring and Maintenance

Program.” The LRA states that the coatings program is a condition monitoring program that 

provides aging management of Service Level 1 coatings inside the LGS primary containment in 

indoor air and treated water environments. It further states that proper maintenance of the 

Service Level 1 coating ensures that coating degradation will not impact the operability of the 

ECCSs. The applicant also stated that Protective Coating Monitoring and Maintenance program 

provides for coating system visual inspection, assessment, and repair for any condition that 

adversely affects the ability of Service Level 1 coatings to function as intended.

The applicant stated that Service Level 1 coatings are not credited for managing the effects of 

corrosion for the carbon steel containment liners and components at LGS Units 1 and 2. The 

applicant indicated that this program ensures that the Service Level 1 coatings maintain 

adhesion so as to not affect the intended function of the ECCS suction strainers. In addition, 

the applicant stated that this program provides controls over the amount of unqualified coating,

which is defined as coating inside the primary containment that has not passed the required 

laboratory testing, including irradiation and simulated DBA conditions. Furthermore, the 

applicant stated that the quantity of unqualified coating is controlled to ensure that the amount of 

unqualified coating in the primary containment is kept within acceptable design limits.
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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 1-6 of the applicant’s program to the 

corresponding program element of GALL Report AMP XI.S8.

For the “scope of program,” “detection of aging effects,” and “monitoring and trending” program 

elements, the staff determined the need for additional information, which resulted in the 

issuance of an RAI, as discussed below.

The “scope of program,” “detection of aging effects,” and “monitoring and trending” program 

elements in GALL Report AMP XI.S8 recommends using ASTM D 5163, in as much as it 

defines the inspection frequency to be each refueling outage or during other major maintenance 

outages, as needed. However, during its audit, the staff found that the Protective Coating 

Monitoring and Maintenance program does not address inspection techniques or the frequency 

for inspection of the coating in the immersed region of the suppression pool. By letter dated 

January 30, 2012, the staff issued RAI B.2.1.37-1 requesting the applicant to provide the 

inspection technique used and frequency and scope of inspection for the Service Level 1 

immersed coating in the suppression pool.

In its response letter, dated February 28, 2012, the applicant stated that the inspection 

frequency of Service Level 1 immersed coating in the suppression pool is consistent with ASTM 

D 5163-08 and ASME Code, Section XI, Subsection IWE for containment inservice inspection. 

The applicant further stated that the wetted surfaces of the suppression pool submerged areas 

had a 100 percent inspection completed in each 10-year ASME Code ISI interval. In addition, 

the applicant stated that consistent with GALL Report AMP XI.S8 element 4 and ASTM D 

5163-08, paragraph 10.1, coating inspections will be by visual inspection techniques.

In its letter, dated September 12, 2012, responding to the SER with Open Items, the applicant 

provided additional information on the inspection frequency of the suppression pool. The 

applicant stated that an ASME IWE examination will be conducted each inservice inspection 

period (i.e., 3 times in 10 years) of 100 percent of the accessible submerged liner surface of the 

suppression pool. The staff finds the method of inspection and frequency acceptable since it is 

consistent with ASTM D 5163-08.

The staff’s review of the ASME Code Section XI, Subsection IWE program is documented in 

SER Section 3.0.3.2.13. As discussed in SER Section 3.0.3.2.13, the inspection of coatings in 

the suppression pool is included as part of ASME Code Section XI, Subsection IWE 

program. For further clarification on how the applicant will manage the degraded areas of the 

suppression pool, refer to SER Section 3.0.3.2.13. The staff’s concern described in RAI 

B.2.1.37 is resolved.

The staff also reviewed the portions of the “detection of aging effects” 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. LRA Section B.2.1.37 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that LGS will create the position of 

Nuclear Coatings Specialist qualified to ASTM D 7108. The staff reviewed this enhancement 

against the corresponding program elements in GALL Report AMP XI.S8 and finds it acceptable 

because when it is implemented, it will make the program consistent with the recommendations 

of GALL Report AMP XI.S8.
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Based on its audit of the Protective Coating Monitoring and Maintenance program, and review 

of the applicant’s responses to RAI B.2.1.37-1, the staff finds that program elements 1-6 for 

which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.S8. In addition, the staff reviewed 

the enhancement associated with the “detection of aging effects” program element and finds 

that when implemented it will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.2.1.37 summarizes operating experience related to the 

Protective Coating Monitoring and Maintenance program. 

The applicant provided the following for operating experience:

The applicant stated that Service Level 1 coating inspections in the submerged region of the 

LGS Unit 1 suppression pool were performed during refueling outages in 2004, 2006, and 2010. 

It was stated that the inspection covered 100 percent of the accessible Service Level 1 coatings 

on the suppression pool liner, downcomers, and columns. It was indicated that four areas of 

corrosion were preemptively spot recoated. The applicant completed an apparent cause 

evaluation as part of the CAP. Improved plans for monitoring coating and containment liner 

corrosion for both LGS Units 1 and 2 have been developed and are implemented through the 

ASME Code Section XI ISI program. The applicant stated that these actions will ensure that 

areas exhibiting coating defects and deficiencies are evaluated, impacts on liner degradation 

are determined, and recoating plans are developed.

The applicant stated that a design change package approved the permanent removal of the 

reactor recirculation pump motor hoists from the Unit 1, primary containment. It was determined 

that removal of the hoists would reduce the amount of unqualified coating in the primary 

containment and that the design analysis that evaluates the containment unqualified coatings 

inventory against ECCS suction strainer capacity was affected. It was reported that the design 

analysis was revised and the total weight determined in the unqualified coatings inventory of the 

calculation was reduced caused by the elimination of the hoists.

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 found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation. 

Based on its audit and review of the application, and review of the applicant’s response to 

RAI B.2.1.37-1, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience, operating experience related to the applicant’s program that 

demonstrates it can adequately manage the effects of aging on SSCs within the scope of the 

program, and that implementation of the program has resulted in the applicant taking corrective 

actions.
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UFSAR Supplement. LRA Section A.2.1.37 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 

SRP-LR Table 3.0-1. The staff also noted that the UFSAR supplement contained a commitment

(Commitment No. 37) to enhance the program by creating the position of Nuclear Coatings 

Specialist qualified to ASTM standard D 7108. It was stated that the enhancement will be 

implemented 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 Protective Coating Monitoring and 

Maintenance program, the staff determines that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. Also, the staff reviewed the 

enhancement and confirmed that its implementation will make the AMP adequate to manage 

the applicable aging effects and that the UFSAR supplement contained Commitment No. 37 to 

implement the enhancement before the period of extended operation. 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).

3.0.3.2.20 Fatigue Monitoring 

Summary of Technical Information in the Application. LRA Section B.3.1.1 describes the 

existing Fatigue Monitoring program as consistent, with an enhancement, with GALL Report 

AMP X.M1, “Fatigue Monitoring.” The LRA states that the program monitors and tracks the 

number of critical thermal, pressure, and seismic transients and requires comparison of the 

actual event parameters (pressure, temperature, or flow rate changes) to the applicable design 

transient definitions to assure the actual transients are bounded by the applicable design 

transients. In addition, the program includes counting the operational transients to ensure that 

the cumulative number of occurrences of each transient type is maintained below the number of 

cycles used in the most limiting fatigue analysis, including environmental fatigue analyses. If a 

cycle limit is approached, corrective actions are triggered to prevent exceeding the limit. 

The LRA also states that the effect of the reactor coolant environment on RCPB component 

fatigue life has been determined by performing environmental fatigue analyses for a sample of 

critical locations selected using NUREG/CR-6260 guidance and performing additional 

environmental fatigue analyses for limiting locations within each RCPB system and each RPV 

component with a ASME Code, Class 1 fatigue analysis. The applicant’s environmentally

adjusted fatigue usage factors (CUFen) were computed in accordance with NUREG/CR-6909 for 

all materials.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1-6 of the applicant’s program to the 

corresponding program elements of GALL Report AMP X.M1. 

For the “monitoring and trending” program element, the staff determined the need for additional 

information, which resulted in the issuance of an RAI, as discussed below. 
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LRA Section 4.3.1 states that each transient projection was trended to determine if recent rates 

of occurrence could be higher than the overall average rate of occurrence and the trending 

shows that recent transient occurrence rates are bounded by the average occurrence rates. 

The TLAA evaluations in LRA Sections 4.3.5, 4.6.5 and 4.6.7 are dispositioned in accordance 

with 10 CFR 54.21(c)(1)(i), the analysis remains valid for the period of extended operation, and 

rely on the 60-year projections that were discussed in LRA Section 4.3.1. The “monitoring and 

trending” program element of GALL Report AMP X.M1 recommends that trending is assessed 

to ensure that the fatigue usage factor remains below the design limit during the period of 

extended operation. During its audit, the staff found that the Fatigue Monitoring program will 

continue to monitor and track transient cycles against the cycle limits throughout the period of 

extended operation to ensure that the 60-year projections are valid. However, since the TLAAs 

described above rely on the 60-year projections that the Fatigue Monitoring program is assuring 

will remain valid throughout the period of extended operation, it is not clear to the staff if the 

validity of these TLAAs will be confirmed if the program determines that a transient cycle count 

has reached a cycle limit. 

By letter dated November 18, 2011, the staff issued RAI B.3.1-1, requesting the applicant to

confirm that the implementing procedures or corrective actions of the Fatigue Monitoring 

program ensures that the TLAAs, that rely on 60-year projections and are dispositioned in 

accordance with 10 CFR 54.21(c)(1)(i), will be evaluated if a cycle count reaches an allowable 

cycle limit. 

In its response dated, December 7, 2011, the applicant stated that each of the components with 

fatigue TLAAs, dispositioned in accordance with 10 CFR 54.21(c)(1)(i), are within the scope of 

the Fatigue Monitoring program, including the RVI (LRA Section 4.3.4), High-Energy Line Break 

Analyses Based Upon Fatigue (LRA Section 4.3.5), the Jet Pump Auxiliary Spring Wedge 

Assembly (LRA Section 4.6.5), and the Refueling Bellows (LRA Section 4.6.7). The applicant 

clarified that these fatigue analyses are based on the same set of design transients monitored 

and trended in the Fatigue Monitoring program. The staff noted that if the cumulative number of 

cycles for any of these transients exceeds 80 percent of the allowable cycle limit, the program’s 

implementing procedures trigger corrective actions to prevent exceeding the cycle count limit. 

The applicant stated that these procedures require the Fatigue Monitoring Engineer to initiate an 

action in the CAP to perform an engineering evaluation of the condition and determine the 

corrective action, which include reanalysis of the component to demonstrate that the design 

ASME Code limit will not be exceeded before or during the period of extended operation; repair 

of the component; replacement of the component, or other methods approved by the NRC. 

In addition, the applicant identified a typographical error LRA Section B.3.1.1 regarding the 

program elements that affected changing “corrective action (element 6)” to “acceptance criteria 

(element 6).” 

The staff finds the applicant’s response acceptable because the applicant confirmed that the 

implementing procedures for its Fatigue Monitoring program will ensure the validity of the 

fatigue TLAAs described above if a transient cycle count reaches 80 percent of an allowable 

cycle limit. Therefore, the staff finds that the applicant continually ensures that the results from 

its 60-year projections used to disposition these fatigue TLAAs in accordance with 

10 CFR 54.21(c)(1)(i), will remain valid during the period of extended operation; otherwise,

corrective actions will be taken. The staff’s concern described in RAI B.3.1-1 is resolved.
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The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” and “acceptance criteria” program elements 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. LRA Section B.3.1.1, as amended by letter dated December 7, 2011, states an 

enhancement to the “preventive actions,” “parameters monitored or inspected” and “acceptance 

criteria” program elements. In this enhancement, the applicant stated that the program will be 

enhanced to monitor additional plant transients that are significant contributors to fatigue usage 

and impose administrative transient cycle limits corresponding to the limiting numbers of cycles 

analyzed in the environmental fatigue calculations. 

The staff noted that the “preventive actions” program element states the program prevents the 

fatigue analyses from becoming invalid by assuring that the fatigue usage resulting from actual 

operational transients does not exceed the ASME Code design limit of 1.0, including 

environmental effects where applicable. The staff noted that the “parameters monitored or 

inspected” program element states the program monitors all plant design transients that cause 

cyclic strains, which are significant contributors to the fatigue usage factor and that the number 

of occurrences of the plant transients that cause significant fatigue usage for each component is 

to be monitored. The staff noted that the “acceptance criteria” program element states the 

acceptance criterion is maintaining the cumulative fatigue usage below the design limit through 

the period of extended operation, with consideration of the reactor water environmental fatigue 

effects.

When enhanced, the applicant’s program will monitor those additional transients not already 

monitored by the existing program that are significant contributors to fatigue usage (i.e., those 

transients assumed in a fatigue analysis) and ensure that the fatigue analyses do not become 

invalid, including environmental effects where applicable. The staff finds this consistent with the 

“parameters monitored or inspected” program elements. As described in the applicant’s letter 

dated December 7, 2011, the implementing procedures for its Fatigue Monitoring program 

includes an 80 percent action limit for cycle counts and is based on the limiting number of cycles 

used in the fatigue analyses. When enhanced, the applicant’s program will impose 

administrative transient cycle limits corresponding to the limiting numbers of cycles analyzed in 

the environmental fatigue calculations. The staff noted that setting an 80 percent action limit 

that is based on the limiting number of cycles used in the design fatigue analyses or 

environmentally assisted fatigue analyses ensures the ASME Code design limit of 1.0 is not 

exceeded, consistent with the “acceptance criteria” program element. By managing those 

transients assumed in the design fatigue analyses and environmental fatigue calculations to an 

80 percent action limit the applicant prevents the calculated CUF or CUFen values from 

becoming invalid, which the staff finds consistent with the “preventive actions” program element.

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP X.M1 and finds it acceptable because when it is implemented, the applicant’s 

program will be consistent with the recommendations of the GALL Report, as described above.

Based on its audit of the Fatigue Monitoring program, the staff finds that program elements 1-6

for which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP X.M1. In addition, the staff reviewed the 

enhancement associated with the “preventive actions,” “parameters monitored or inspected,”
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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.3.1.1 summarizes operating experience related to the 

Fatigue Monitoring program. LRA Section B.3.1.1 states that in 2009, the applicant identified 

inconsistencies in the cumulative cycle counts shown on the reactor vessel thermal transient 

monitoring data sheets prepared for LGS Units 1 and 2. The applicant clarified that the issues 

were historical and primarily associated with incorrect transferring of cumulative cycle count 

totals from one quarterly report to the next, resulting in discrepancies between the individual 

event occurrences and the cumulative cycle counts. The applicant revised its procedures to 

include improved human factors. The staff noted that the applicant’s program demonstrates 

that it performs self-assessments to ensure that accurate cycles counts are maintained;

otherwise, corrective actions are taken to ensure that design limits and cumulative cycle counts 

are within the design.

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 found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. 

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 4.3-2. The staff 

also noted that the UFSAR supplement included a commitment (Commitment No. 44) to 

enhance the existing Fatigue Monitoring program to monitor additional plant transients that are 

significant contributors to fatigue usage and to impose administrative transient cycle limits 

corresponding to the limiting numbers of cycles used in the environmental fatigue calculations 

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 Fatigue Monitoring program, the staff 

determines that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. Also, the staff reviewed the enhancement and confirmed that its 

implementation will make the AMP adequate to manage the applicable aging effects and that 

the UFSAR supplement contains Commitment No. 44 to implement the enhancement before the 

period of extended operation. 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 
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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).

3.0.4 QA Program Attributes Integral to Aging Management Programs 

As required by 10 CFR 54.21(a)(3), the applicant is required to demonstrate that the effects of 

aging on SCs subject to an AMR will be adequately managed so that their intended function(s) 

will be maintained consistent with the CLB for the period of extended operation. SRP-LR, 

Branch Technical Position (BTP) RLSB-1, “Aging Management Review – Generic,” describes 

10 elements of an acceptable AMP. Elements (7), (8), and (9) are associated with the QA 

activities of “corrective actions,” “confirmation process,” and “administrative controls.”

BTP RLSB-1 Table A.1-1, “Elements of an Aging Management Program for License Renewal,”

provides the following description of these program elements:

(1) “corrective actions” – “corrective actions,” including root cause determination and 

prevention of recurrence, should be timely

(2) “confirmation process” – the “confirmation process” should ensure that preventive 

actions are adequate and that appropriate corrective actions are completed and effective

(3) “administrative controls” – “administrative controls” should provide for a formal review 

and approval process

BTP IQMB-1, “Quality Assurance for Aging Management Programs,” notes that AMP aspects 

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 may use the existing 10 CFR Part 50 Appendix B QA Program to address the 

elements of “corrective actions,” “confirmation process,” and “administrative controls.”

BTP IQMB-1 provides the following guidance on the QA attributes of AMPs:

 • safety-related SCs are subject to 10 CFR Part 50 Appendix B requirements that 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, an applicant has an option to expand 

the scope of its 10 CFR Part 50 Appendix B 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 commitment in the UFSAR supplement in accordance with 10 CFR 54.21(d)

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 LRA, 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 (SR) and 

nonsafety-related components.
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LRA Appendix A, Section A.1.5 states: 

The Quality Assurance Program [QAP] 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 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 an AMR.

3.0.4.2 Staff Evaluation 

As required by 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,” 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 controls. Table A.1-1, 

“Elements of an Aging Management Program for License Renewal,” of Branch Technical 

Position RLSB-1 provides the following description of these quality attributes:

 • Attribute No. 7 – “corrective actions,” including root cause determination and prevention 

of recurrence, should be timely

 • Attribute No. 8 – “confirmation process, which should ensure that preventive actions are 

adequate and that appropriate corrective actions have been completed and are effective

 • Attribute No. 9 – “administrative controls,” which should provide a formal review and 

approval process.

The SRP-LR, Branch Technical Position IQMB-1, “Quality Assurance for Aging Management 

Programs,” states that those aspects of the AMP that affect 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, 

QAP may be used to address the elements of “corrective action,” “confirmation process,” and 

“administrative control.” Branch Technical Position 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 
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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 Appendix A, Section A.1.5, and LRA Appendix B, Section B.1.3, and the 

applicant’s implementing procedures, which describe how the existing LGS QAP includes the 

QA-related elements (“corrective action,” “confirmation process,” and “administrative controls”) 

for AMPs consistent with the staff’s guidance described in Branch Technical Position IQMB-1. 

The staff also reviewed a sample of AMP program basis documents and confirmed that the 

AMPs implement the CAP, confirmation processes, and administrative controls as described in 

the LRA. Based on its review, the staff determined that the quality 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 of LRA Appendix A, Section A.1.5 and Appendix B, 

Section B.1.3, the AMP program basis documents the staff concluded that the QA attributes 

(“corrective action,” “confirmation process,” and “administrative control”) of the applicant’s AMPs 

are consistent with SRP-LR, Branch Technical Position RLSB-1. 

3.0.5 Operating Experience for Aging Management Programs

3.0.5.1 Summary of Technical Information in Application

LRA Section B.1.4 describes the consideration of operating experience for AMPs. The LRA 

states that the description of each AMP contains a discussion of operating experience relevant 

to the program. This information was obtained through the review of in-house operating 

experience captured by the CAP, program self-assessments, program health reports, and 

through the review of industry operating experience. The applicant also states that operating 

experience was obtained through interviews with system engineers, program engineers, and 

other plant personnel. Plant-specific and industry operating experience were used for new 

programs, as applicable. In addition, the LRA states that, during the first 10 years of entering 

the period of extended operation, the owners of AMPs credited for license renewal will review 

plant-specific and industry operating experience to confirm the effectiveness of the AMPs and 

followup actions will be taken as appropriate to provide additional assurance that aging of SSCs 

within the scope of license renewal will be adequately managed throughout the period of 

extended operation.

3.0.5.2 Staff Evaluation

Pursuant to 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effect 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. SRP-LR, Revision 2, 

Appendix A, describes 10 elements of an acceptable AMP. SRP-LR Section A.1.2.3.10 

describes Element 10, “Operating Experience,” as consisting of these three attributes:
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(1) Consideration of future plant-specific and industry operating experience relating 

to aging management programs should be discussed. Reviews of operating 

experience by the applicant in the future may identify areas where aging 

management programs should be enhanced or new programs developed. An 

applicant should commit to a future review of plant-specific and industry 

operating experience to confirm the effectiveness of its aging management 

programs or indicate a need to develop new aging management programs. This 

information should provide objective evidence to support the conclusion that the 

effects of aging will be adequately managed so that the structure and component 

intended function(s) will be maintained during the period of extended operation.

(2) Operating experience with existing programs should be discussed. The 

operating experience of AMPs that are existing programs, including past 

corrective actions resulting in program enhancements or additional programs, 

should be considered. A past failure would not necessarily invalidate an AMP 

because the feedback from operating experience should have resulted in 

appropriate program enhancements or new programs. This information can 

show where an existing program has succeeded and where it has failed (if at all) 

in intercepting aging degradation in a timely manner. This information should 

provide objective evidence to support the conclusion that the effects of aging will 

be adequately managed so that the structure- and component-intended 

function(s) will be maintained during the period of extended operation.

(3) For new AMPs that have yet to be implemented at an applicant’s facility, the 

programs have not yet generated any operating experience (OE). However, 

there may be other relevant plant-specific OE at the plant or generic OE in the 

industry that is relevant to the AMP’s program elements even though the OE was 

not identified as a result of the implementation of the new program. Thus, for 

new programs, an applicant may need to consider the impact of relevant OE that 

results from the past implementation of its existing AMPs that are existing 

programs and the impact of relevant generic OE on developing the program 

elements. Therefore, operating experience applicable to new programs should 

be discussed. Additionally, an applicant should commit to a review of future 

plant-specific and industry operating experience for new programs to confirm its 

effectiveness.

SER Section 3.0.3 discusses the staff’s review of the second and third attributes, which concern 

operating experience associated with existing and new programs, respectively. The below 

evaluation discusses the staff’s review of the first attribute, which concerns the consideration of 

future operating experience and applies to both existing and new programs.

The staff reviewed LRA Sections B.1.4 and B.2.1.1 through B.2.1.43 to determine whether the 

applicant will implement adequate activities for the ongoing review of both plant-specific and 

industry operating experience to identify areas where the AMPs should be enhanced or new 

AMPs developed. Although LRA Section B.1.4 states that the applicant will review 

plant-specific and industry operating experience during the first 10 years of entering the period 

of extended operation to confirm the effectiveness of the AMPs and to determine appropriate 

followup actions, it is not clear how specifically, the applicant will use future operating 

experience to ensure that the AMPs will remain effective for managing the effects of aging 

during the period of extended operation. 
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By letter dated February 16, 2012, the staff issued RAI B.1.4-1 requesting that the applicant 

describe in detail the programmatic activities that will be used to continually identify aging 

issues, evaluate them, and, as necessary, enhance the AMPs or develop new AMPs. In the 

description of these activities, the staff also requested that the applicant specifically address the 

following:

 • sources of plant-specific and industry operating experience information reviewed on an 

ongoing basis

 • criteria for determining when operating experience concerns aging

 • training of plant personnel for identifying age-related issues

 • evaluation of operating experience to determine its potential impact on the plant aging 

management activities

 • consideration of SCs, their materials, environments, aging effects, aging mechanisms, and 

AMPs in operating experience evaluations

 • consideration of AMP inspections results

 • records kept of operating experience evaluations

 • process for the timely implementation of enhancements identified through operating 

experience evaluations

 • administrative controls over the operating experience review activities

The applicant’s response to RAI B1.4-1, in its letter dated March 13, 2012, provided further 

details on how it will review plant-specific and industry operating experience. In summary, the 

applicant stated that it will use its established, mature plant Operating Experience program and 

its CAP to evaluate and address degraded conditions including plant-specific and industry 

operating experience and to provide assurance of the effectiveness of AMPs and the 

development of new or enhanced AMPs when operating experience indicates that the current 

AMPs may not be fully effective. The applicant described how plant-specific operating 

experience is captured and processed through the CAP and stated that industry operating 

experience will be obtained from a number of sources, including the INPO website and NRC 

generic communications. The applicant also described the process and criteria used to identify 

and evaluate operating experience and stated that plant-specific operating experience will be 

reported to the industry. Training requirements for plant personnel responsible for screening, 

assigning, evaluating, and submitting plant-specific and industry operating experience is also 

described. Several enhancements to the Operating Experience program were identified and the 

applicant stated that these enhancements will be completed before entering the period of 

extended operation.

Subsequent to the receipt of the applicant’s response to RAI B.1.4-1, the staff issued its final 

License Renewal Interim Staff Guidance (LR-ISG) 2011-05, “Ongoing Review of Operating 

Experience.” 

The staff evaluated the details of the applicant’s description of the ongoing operating experience 

review activities with respect to the following framework set forth in LR-ISG-2011-05:

• consideration of operating experience in the 10 CFR Part 50, Appendix B, QA program

• sources of operating experience
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• consideration of all incoming plant-specific and industry operating experience

• identification of operating experience related to aging

• information considered in operating experience evaluations

• consideration of AMP implementation results as operating experience

• training

• reporting operating experience to the industry

• implementation schedule

First, the staff evaluated how the applicant’s 10 CFR Part 50, Appendix B, QA program will 

consider operating experience on age-related degradation and aging management. LRA 

Sections A.1.5 and B.1.3 state that the QA program implements the requirements of 

10 CFR Part 50, Appendix B, and is applicable to safety-related and nonsafety-related SSCs

subject to an AMR. The staff finds the QA program acceptable because the scope of the 

program includes nonsafety-related SSCs. This expanded scope of the QA program can 

incorporate operating experience related to aging degradation and aging management for all 

SSCs identified in the IPA.

Second, the staff evaluated the sources of operating experience reviewed by the applicant. 

LRA Section B.1.4 states that plant-specific operating experience comes from sources such as 

event investigations, trending reports, and lessons learned from in-house events, as captured in 

self-assessments and the CAP. The LRA also states that, under the CAP, issue reports are 

required to address actual or potential plant problems, including unexpected plant equipment 

degradation, damage, malfunction, or loss of function. Other plant-specific sources, as further 

described in the applicant’s response to RAI B.1.4-1, include tests, inspections, plant 

walkdowns, and adverse results, which include adverse AMP-related inspection results. In 

addition, the response to RAI B.1.4-1 states that the applicant will enhance the CAP to include 

direction to include operating experience related to aging. The staff determined that the 

applicant’s CAP is adequate to capture applicable sources of plant-specific operating 

experience because the CAP receives input from a broad scope of plant activities used to 

identify potential age-related issues. In addition, the applicant’s enhancement will further 

ensure that the CAP will not preclude the capture and evaluation of operating experience 

related to aging, which is consistent with the guidance in LR-ISG-2011-05.

The response dated March 13, 2012, also provides examples of industry operating experience 

documents screened under the Operating Experience program for applicability to LGS. The 

applicant stated that these documents include Institute of Nuclear Power Operations (INPO)

Event Reports, NRC Bulletins, GLs, INs, and Regulatory Issue Summaries, as well as topical 

reports and vendor correspondence. The applicant further stated that LR-ISG documents will 

be added to the scope of items that are screened. The staff finds acceptable the sources of 

industry operating experience considered by the applicant because the Operating Experience 

program prescribes review of operating experience from what the staff considers to be the 

primary providers of industry operating experience information (i.e., NRC, other nuclear power 

plants through INPO, and vendors). The NRC previously endorsed use of the INPO program as 

the mechanism for the central collection and screening of all events from both United States and 

foreign nuclear plants in GL 82-04, “Use of INPO SEE-IN Program,” dated March 9, 1982.

Third, the staff evaluated the applicant’s activities for screening of all incoming plant-specific 

and industry operating experience to determine whether it may involve age-related degradation 

or impacts to aging management activities. The applicant’s response dated March 13, 2012, 

states the CAP and the Operating Experience program are used together to evaluate and 
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address adverse plant-specific and industry operating experience including aging-related 

degradation. The applicant further stated that the existing Operating Experience program and 

operating experience coordinator training will be enhanced to ensure that both internal and 

external aging-related operating experience is properly reviewed and disseminated for 

evaluation by the appropriate plant or corporate personnel. The applicant also stated that 

identification coding will be established within the CAP and with communication at the industry 

level to identify and trend operating experience related to aging management. The staff finds 

acceptable the use of the CAP and the Operating Experience program to screen operating 

experience in this respect because both programs would not preclude the capture of 

plant-specific and industry operating experience related to aging. 

Fourth, the staff evaluated the applicant’s identification of plant-specific operating experience as 

related to aging in the CAP. The applicant’s response dated March 13, 2012, stated

identification coding will be established within the CAP database to identify operating 

experience concerning age-related degradation applicable to the plant. The applicant further 

stated that the coding will be used to address specific issues, assess the adequacy of existing 

AMPs, and to enhance them as necessary. In addition, the applicant stated that personnel will 

be required to periodically assess the performance of the AMPs and determine if AMP revisions 

or new AMPs are appropriate. The staff finds acceptable the applicant’s process for identifying 

operating experience as related to aging because all operating experience items submitted into 

the CAP and Operating Experience program will be reviewed and identified as involving 

potential aging issues. 

Fifth, the staff evaluated the information that the applicant will consider in the operating 

experience evaluations. The applicant’s response dated March 13, 2012, states that operating 

experience evaluations relating to aging management will consider the following:

 • SSCs that are similar or identical to those involved with the identified operating experience 

issue, to gain relevant lessons learned

 • materials of construction, operating environment and aging effects associated with the 

identified aging issue so that lessons learned can be applied to susceptible SSCs in the 

scope of license renewal

 • aging mechanisms associated with the operating experience to confirm that LGS has 

appropriate AMPs in place to manage aging that could be caused by these mechanisms

 • AMPs involved with this operating experience so that if the AMPs have been demonstrated 

to be ineffective, similar AMPs in place at LGS can be evaluated to determine if AMP 

changes are appropriate, or if a new AMP is needed

The response further states that an issue report will be initiated when plant-specific or industry 

vulnerabilities are determined. The applicant stated that plant-specific vulnerabilities 

determined by the evaluation will be processed and further evaluated through the CAP. An 

evaluation is also performed for an issue report initiated by industry operating experience. The 

response states that, if a deficient condition related to aging is identified by the evaluation, and 

applicable to SSCs within the scope of license renewal, the applicant will determine whether 

AMPs should be enhanced or new AMPs developed. The staff finds acceptable the information 

that will be considered in the applicant’s operating experience evaluations because this 

information will involve potential aging issues and consideration of the fundamental components 

of an AMR, namely the potentially affected plant SSCs, materials, environments, aging effects, 
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aging mechanisms, and AMPs. Consideration of this information in the operating experience

reviews will facilitate the assessment of all potential impacts to the aging management activities. 

Sixth, the staff evaluated the applicant’s consideration of AMP implementation results as 

operating experience. The applicant’s response dated March 13, 2012, states that the Exelon 

work management system records all results of AMP inspections, tests, analyses, etc. 

regardless of whether they meet the applicable acceptance criteria. The response further states 

that an issue report is initiated within the CAP for results that do not meet the acceptance 

criteria and appropriate corrective actions are taken. Corrective actions include correcting the 

specific condition, considering the extent of condition, and evaluating the adequacy of existing 

AMPs. The applicant stated that the evaluation will consider modification of existing AMPs or 

the development of new AMPs. The staff finds the applicant’s consideration of the AMP 

inspection results acceptable because unsatisfactory results will be entered into the CAP, which 

is used to evaluate plant-specific operating experience. The staff also finds the applicant’s 

response acceptable because data collected by the AMPs will be reviewed and revisions to the 

programs will be implemented as necessary, which will further help to ensure that the programs

are effective. 

Seventh, the staff evaluated the training of plant personnel responsible for implementing the 

AMPs and those personnel who may submit, screen, assign, evaluate, or otherwise process 

plant-specific and industry operating experience. The applicant’s response dated 

March 13, 2012, states that the Operating Experience program has personnel that are assigned 

and trained in the functions of screening, assigning, evaluating, and submitting plant-specific 

and industry operating experience. The applicant further described the roles of four key 

personnel: (1) the Exelon Fleet Coordinator, who is central input for all operating experience for 

the Exelon fleet; (2) the LGS Site Operating Experience Program Coordinator, who is the 

operating experience champion and responsible for processing both internal fleet operating 

experience and outgoing operating experience notifications to the industry; (3) the Station Aging 

Management Coordinator (AMC), who will be the LGS lead for overseeing the effective 

implementation of activities related to license renewal and reviewing internal and external 

operating experience for lessons learned applicable to LGS and aging-related operating 

experience that should be shared with the industry; and (4) the LGS AMP owners for existing 

and new AMPs, who are involved with the development, review, and approval of the AMPs 

credited for aging management. 

The applicant stated that the fleet and LGS Station Operating Experience Program Coordinator 

training will be updated to enhance the review, dissemination, and evaluation of internal and 

external age-related operating experience. The applicant further stated that the LGS AMC will 

be trained to be proficient in screening and evaluating age-related operating experience and 

AMP owners have received classroom training that includes component aging. The applicant 

also stated that training enhancements will be made periodically to include aging management 

information and that the Operating Experience program requires newly assigned personnel to 

complete training to effectively perform the job function. The staff finds acceptable the 

applicant’s training of plant personnel because the primary personnel responsible for screening, 

assigning, evaluating, and submitting operating experience issues will receive training on 

aging-related topics. The staff also finds the applicant’s training acceptable because it will be 

periodically updated and will be required for new personnel.

Eighth, the staff evaluated the reporting of LGS operating experience to the industry. The 

applicant’s response dated March 13, 2012, states that the Operating Experience program will 
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be enhanced to include guidance for reporting plant-specific operating experience related to 

aging to the industry. The applicant stated that this guidance will include the following:

 • observation of aging-related degradation significantly beyond what was expected, based 

upon an existing AMP inspection frequency, methodology, etc.

 • aging effects or mechanisms not previously seen or accounted for in the AMPs

 • other significant changes required or being made to AMPs that may be of interest to the 

industry

Also, the applicant stated that the roles of the AMC and LGS Site Operating Experience 

Program Coordinator include determining and processing aging-related operating experience 

that will be shared with the industry. As previously described, the AMC will be trained in 

screening and evaluating operating experience concerning age-related degradation. The staff 

finds acceptable the applicant’s guidelines for reporting internal operating experience to the 

industry because they address aging issues and because the identification of noteworthy 

operating experience will be from individuals with training on aging topics. This reporting of 

operating experience to the industry is consistent with the NRC’s endorsement of the INPO 

program in GL 82-04.

Ninth and last, the staff evaluated the implementation schedule for the operating experience 

review activities described by the applicant. The applicant’s response dated March 13, 2012, 

describes enhancements to the Operating Experience program to provide assurance that 

age-related degradation operating experience will be considered to determine the effectiveness 

of AMPs and the need for enhancements or new AMPs. The applicant’s response dated June 

19, 2012, describes the timetable and basis for completion of the enhancements. The applicant 

stated that it plans to implement the enhancements within 2 years following the receipt of the 

renewed operating license, which will be approximately 9 years before the period of extended 

operation. The applicant also stated that the current Operating Experience program and CAP 

have been shown to be effective in identifying and addressing age-related degradation. In 

addition, the applicant stated that these enhancements will be initiated across the Exelon 

Nuclear plant fleet and will require collaboration, coordination, and management within a 

significant group of people. 

LR-ISG-2011-05 states that any enhancements to the existing programmatic activities for the 

ongoing review of operating experience that are necessary for license renewal should be put in 

place no later than the date the renewed operating licenses are issued. The applicant 

described several enhancements; however, it plans to implement them after issuance of the 

renewed licenses. Therefore, the staff could not determine whether operating experience 

related to aging management and age-related degradation will be considered in the period 

between issuance of the renewed licenses and implementation of the enhancements. The staff 

identified this issue as OI 3.0.5-1.

The applicant responded to OI 3.0.5-1 by letter dated September 12, 2012. The applicant 

stated that, in the period between issuance of the renewed licenses and implementation of the 

enhancements, it will consider operating experience related to aging management and 

age-related degradation in accordance with its existing processes. The applicant also stated 

that, if the enhancements are not implemented by the time the renewed licenses are issued, it 

will review all LR-ISG documents issued before implementation of the enhancements and the 

first revision of the GALL Report issued after implementation of the enhancements to identify 
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significant guidance changes driven by industry operating experience that should be 

incorporated into the aging management activities.

The staff reviewed the applicant’s response to OI 3.0.5-1 and determined that, as proposed, it 

would allow a 2-year period after license renewal before operating experience related to aging is 

considered in maintaining the AMPs. As such, this consideration of operating experience will 

begin at a later date rather than immediately upon receipt of the renewed operating licenses. 

The staff determined that the response does not provide reasonable assurance that the 

applicant will consider relevant plant-specific and industry operating experience and incorporate 

it into the aging management activities on an ongoing basis. Therefore, by letter dated 

October 10, 2012, the staff issued RAI B.1.4-4 requesting the applicant to clearly address how 

plant-specific and industry operating experience will be considered on an ongoing basis before

full implementation of the Operating Experience program enhancements.

The applicant responded to RAI B.1.4-4 by letter dated October 12, 2012. The response 

removes the applicant’s compensatory plan to review LR-ISG documents and GALL Report 

revision as an alternative to implementing the enhancements before issuance of the renewed 

licenses. Instead, the response states that all of the previously described enhancements to the 

Operating Experience program will be implemented no later than the date when the renewed 

operating licenses are issued and the associated activities will be conducted on an ongoing 

basis throughout the terms of the renewed licenses. The staff reviewed this response and finds 

it acceptable because the implementation date for the enhancements is consistent with the 

guidance in LR-ISG-2011-05. The applicant’s implementation of these enhancements, in 

conjunction with its existing operating experience review activities, will ensure that age-related 

degradation and aging management is appropriately addressed in the ongoing processing of 

plant-specific and industry operating experience. The staff’s concern described in RAI B.1.4-4 

is resolved and OI 3.0.5-1 is closed.

Based on its review of the application and the applicant’s responses to RAIs B.1.4-1, B.1.4-2, 

and B.1.4-4, 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) for the 

enhancement to 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.

3.0.5.3 UFSAR Supplement

The staff reviewed the USAR supplement in LRA Appendix A to determine whether the 

applicant provided an adequate summary description of the programmatic activities for the 

ongoing review of operating experience. The staff found no such description. By letter dated 

February 16, 2012, the staff issued RAI A.1-1, requesting that the applicant provide a summary 

description of these activities for the USAR supplement required by 10 CFR 54.21(d).

The applicant’s response to RAI A.1-1, provided by letter dated March 13, 2012, revises the

UFSAR supplement to include LRA Section A.1.6, which provides a summary description of the 

operating experience review activities and identifies enhancements to the existing Operating 

Experience program. However, this description states that the enhancements will be 

implemented before the period of extended operation. The staff issued RAI B.1.4-2, by letter 

dated June 12, 2012, requesting the applicant to provide further clarification regarding 
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implementation of actions associated with the consideration of operating experience for AMPs. 

By letter dated June 19, 2012, the applicant responded to RAI B.1.4-2 stating that the Operating 

Experience program enhancements will be implemented within 2 years following receipt of the 

renewed operating licenses. The applicant also explained its reasoning and justification for this

timetable. However, the applicant did not update the UFSAR supplement to reflect that the 

proposed enhancements will be implemented within 2 years following receipt of the renewed 

operating licenses. Therefore, by letter dated July 10, 2012, the staff issued RAI B.1.4-3, 

requesting that the applicant update the UFSAR supplement to be consistent with the response 

to RAI B.1.4-2. By letter dated July 11, 2012, the applicant revised LRA Section A.1.6, 

accordingly.

Although the applicant included the enhancement implementation schedule in the revised 

UFSAR supplement summary description, as discussed in SER Section 3.0.5.2, the staff could 

not determine whether operating experience related to aging management and age-related 

degradation will be considered in the period between issuance of the renewed licenses and 

implementation of the enhancements. The staff identified this issue as OI 3.0.5-1.

In its response to OI 3.0.5-1, the applicant revised the UFSAR supplement to state that, if the 

Operating Experience program enhancements are not implemented by the time the renewed 

licenses are issued, it will review all LR-ISG documents issued before implementation of the 

enhancements and the first revision of the GALL Report issued after implementation of the 

enhancements to identify significant guidance changes driven by industry operating experience 

that should be incorporated into the aging management activities. The staff reviewed this 

revision to the UFSAR supplement and determined that it would allow a 2-year period after 

license renewal before operating experience related to aging is considered in maintaining the 

aging management programs. As such, the staff determined that the proposed UFSAR 

supplement does not provide reasonable assurance that the applicant will consider relevant 

plant-specific and industry operating experience and incorporate it into the aging management 

activities on an ongoing basis. By letter dated October 10, 2012, the staff issued RAI B.1.4-4 

requesting that the applicant revise the UFSAR supplement to clearly address how 

plant-specific and industry operating experience will be considered on an ongoing basis before

full implementation of the Operating Experience program enhancements.

In its response to RAI B.1.4-4, the applicant revised UFSAR Section A.1.6 to state that the 

enhancements will be implemented no later than the date when the renewed operating licenses 

are issued and conducted on an ongoing basis throughout the terms of the renewed licenses. 

As discussed in SER 3.0.5.2, the staff finds this implementation schedule acceptable and 

capturing this schedule in the UFSAR supplement summary description provides assurance that 

operating experience related to aging management and age-related degradation will be 

considered on an ongoing basis. Therefore, the staff finds that the UFSAR supplement 

summary description of the programmatic operating experience review activities is sufficiently 

comprehensive such that later changes can be controlled by 10 CFR 50.59. The staff’s concern 

described in RAI B.1.4 4 is resolved and OI 3.0.5 1 is closed.

3.0.5.4 Conclusion

Based on the staff’s review of the applicant’s programmatic activities for the ongoing review of 

operating experience and the information provided by the applicant in the LRA, in response to 

RAIs B.1.4-1, B.1.4-2, B.1.4-3, and B.1.4-4, and with consideration of the guidance in 

LR-ISG-2011-05, the staff concluded that the applicant has demonstrated that operating 
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experience will be reviewed on an ongoing basis from the time of issuance of the renewed 

licenses and 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 

10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for these activities and 

concludes that it provides an adequate summary description, as required by 10 CFR 54.21(d).

3.1 Aging Management of Reactor Vessel, Internals and Reactor Coolant System

This SER section documents the staff’s review of the applicant’s AMR results for the reactor 

vessel, internals, and RCS components and component groups of:

 • RCPB

 • RPV

 • RVI

3.1.1 Summary of Technical Information in the Application 

LRA Section 3.1 provides AMR results for the reactor vessel, RVIs, and RCS 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, RVIs, and 

RCS 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, RVIs, and RCS

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 AMRs to ensure the applicant’s claim that certain AMRs are 

consistent with the GALL Report. 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. The staff’s 

evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff’s evaluation 

are documented in SER Section 3.1.2.1.

During its review, the staff also selected 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 are 

documented in SER Section 3.1.2.2.
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The staff also conducted a technical review of the remaining AMRs not consistent with or 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 are documented in SER 

Section 3.1.2.3.

For SSCs that the applicant claimed are not applicable or required no aging management, the 

staff reviewed the AMR items and the plant’s operating experience to verify the applicant’s 

claims.

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.

Table 3.1-1 Staff Evaluation for Reactor Vessel, Reactor Vessel Internals and Reactor 

Coolant System Components in the SRP-LR

Component Group

(SRP-LR Item No.)

Aging Effect or

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 

caused by

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 

caused by

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 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 

caused by

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)
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Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel pressure 

vessel support skirt 

and attachment 

welds (3.1.1-4)

Cumulative 

fatigue damage 

caused by

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, 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 

caused by

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 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 

caused by

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 

caused by

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)
3-183

Component Group

(SRP-LR Item No.)

Aging Effect or

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), or 

stainless steel; or 

nickel alloy steam 

generator 

components exposed 

to reactor coolant 

(3.1.1-8)

Cumulative 

fatigue damage 

caused by

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 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 

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 

caused by

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 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 

caused by

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 Not applicable to 

BWRs (see SER 

Section 3.1.2.2.1)
3-184

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel or stainless 

steel pump and valve 

closure bolting 

exposed to high 

temperatures and 

thermal cycles 

(3.1.1-11)

Cumulative 

fatigue damage 

caused by

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)

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 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M1, 

“ASME Code 

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 Not applicable to 

BWRs (see SER 

Section 3.1.2.2.2(1) 

and 3.1.2.2.2(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 

caused by

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(1))

Steel (with or without 

cladding) reactor 

vessel beltline shell, 

nozzles, and welds; 

safety injection 

nozzles (3.1.1-14)

Loss of fracture 

toughness 

caused by

neutron 

irradiation 

embrittlement

Chapter XI.M31, 

“Reactor Vessel 

Surveillance”

Yes Reactor Vessel 

Surveillance

Consistent with the 

GALL Report (see 

SER Section

3.1.2.2.3(2))
3-185

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel and 

nickel alloy reactor 

vessel internal 

components exposed 

to reactor coolant 

and neutron flux 

(3.1.1-15)

Reduction in 

ductility and 

fracture 

toughness 

caused by

neutron 

irradiation

Ductility - Reduction 

in Fracture 

Toughness is a 

TLAA to be 

evaluated for the 

period of extended 

operation (see SRP, 

Section 4.7, “Other 

Plant-Specific 

TLAAs,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1).

Yes Not applicable Not applicable to 

BWRs (see SER 

Section

3.1.2.2.3(3))

Stainless steel and 

nickel alloy top head 

enclosure vessel 

flange leak detection 

line (3.1.1-16)

Cracking caused 

by SCC, 

intergranular 

SCC

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 

caused by SCC in 

the vessel flange 

leak detection line

Yes Not applicable Not applicable to 

LGS (see SER 

Section

3.1.2.2.4(1))

Stainless steel 

isolation condenser 

components exposed 

to reactor coolant 

(3.1.1-17)

Cracking caused 

by SCC, 

intergranular 

SCC

Chapter XI.M1, 

“ASME Code 

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 

LGS (see SER 

Section

3.1.2.2.4(2))

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 

caused by 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 Not applicable to 

BWRs (see SER 

Section 3.1.2.2.5)
3-186

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

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 caused 

by SCC

A plant-specific aging 

management 

program is to be 

evaluated

Yes Not applicable Not applicable to 

BWRs (see SER 

Section

3.1.2.2.6(1))

Cast austenitic 

stainless steel 

Class 1 piping, piping 

components, and 

piping elements 

exposed to reactor 

coolant (3.1.1-20)

Cracking caused 

by SCC

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 Not applicable to 

BWRs (see SER 

Section

3.1.2.2.6(2))

Steel and stainless 

steel isolation 

condenser 

components exposed 

to reactor coolant 

(3.1.1-21)

Cracking caused 

by cyclic loading

Chapter XI.M1, 

“ASME Code 

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 

LGS (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 

caused by

erosion

A plant-specific aging 

management 

program is to be 

evaluated

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.8)

Stainless steel or 

nickel alloy PWR 

reactor vessel 

internal components 

(inaccessible 

locations) exposed to 

reactor coolant and 

neutron flux 

(3.1.1-23)

Cracking caused 

by SCC and 

irradiation-assist

ed SCC

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.9)
3-187

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel or 

nickel alloy PWR 

reactor vessel 

internal components 

(inaccessible 

locations) exposed to 

reactor coolant and 

neutron flux 

(3.1.1-24)

Loss of fracture 

toughness 

caused by

neutron 

irradiation 

embrittlement; or 

changes in 

dimension 

caused by void 

swelling; or loss 

of preload 

caused by

thermal and 

irradiation 

enhanced stress 

relaxation; or 

loss of material 

caused by wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.10)

Steel (with nickel

alloy 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 caused 

by primary water 

SCC

Chapter XI.M2, 

“Water Chemistry”

Yes Not applicable Not applicable to 

BWRs (see SER 

Section

3.1.2.2.11(1) and 

3.1.2.2.11(2))

Stainless steel 

Combustion 

Engineering core 

support barrel 

assembly: lower 

flange weld exposed 

to reactor coolant 

and neutron flux.

Upper internals 

assembly: fuel 

alignment plate 

(applicable to plants 

with core shrouds 

assembled with full 

height shroud plates) 

exposed to reactor 

coolant and neutron 

flux. Lower support 

structure: core 

support plate 

(applicable to plants 

with a core support 

plate) exposed to 

reactor coolant and 

neutron flux 

(3.1.1-26)

Cracking caused 

by fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry,” if 

fatigue life cannot be 

confirmed by TLAA

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.12)
3-188

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Nickel alloy 

Westinghouse 

control rod guide 

tube assemblies, 

guide tube support 

pins exposed to 

reactor coolant and 

neutron flux 

(3.1.1-27)

Cracking caused 

by SCC and 

fatigue

A plant-specific aging 

management 

program is to be

evaluated

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.13)

Nickel alloy 

Westinghouse 

control rod guide 

tube assemblies, 

guide tube support 

pins, and Zircaloy-4 

Combustion 

Engineering in-core

instrumentation 

thimble tubes 

exposed to reactor 

coolant and neutron 

flux (3.1.1-28)

Loss of material 

caused by wear

A plant-specific aging 

management 

program is to be 

evaluated

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.14)

Nickel alloy core 

shroud and core 

plate access hole 

cover (welded 

covers) exposed to 

reactor coolant 

(3.1.1-29)

Cracking caused 

by SCC, 

intergranular 

SCC, 

irradiation-assist

ed SCC

Chapter XI.M1, 

“ASME Code 

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

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 caused 

by SCC, 

intergranular 

SCC, cyclic 

loading

Chapter XI.M1, 

“ASME Code 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry”

No ASME Code 

Section XI 

Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD and 

Water Chemistry

Consistent with the 

GALL Report

Steel and stainless 

steel isolation 

condenser 

components exposed 

to reactor coolant 

(3.1.1-31)

Loss of material 

caused by

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.M1, 

“ASME Code 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry”

No One-Time 

Inspection and 

Water Chemistry

Consistent with the 

GALL Report

(see SER 

Section 3.1.2.1.3)
3-189

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel, 

nickel alloy, or CASS 

reactor vessel 

internals, core 

support structure, 

exposed to reactor 

coolant and neutron 

flux (3.1.1-32)

Cracking, or loss 

of material 

caused by wear

Chapter XI.M1, 

“ASME Code 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD”

Yes Not applicable 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 caused 

by SCC

Chapter XI.M1, 

“ASME Code 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD” for 

ASME components, 

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

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 caused 

by SCC

Chapter XI.M1, 

“ASME Code 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD” for 

ASME components, 

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable 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 caused 

by cyclic loading

Chapter XI.M1, 

“ASME Code 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components

No, Not applicable 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 caused 

by cyclic loading

Chapter XI.M1, 

“ASME Code 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel reactor vessel 

flange (3.1.1-37)

Loss of material 

caused by wear

Chapter XI.M1, 

“ASME Code 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-190

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Cast austenitic 

stainless steel 

Class 1 pump 

casings, and valve 

bodies and bonnets 

exposed to reactor 

coolant >250 °C

(>482 °F) (3.1.1-38)

Loss of fracture 

toughness 

caused by

thermal aging 

embrittlement

Chapter XI.M1, 

“ASME Code 

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 Code 

Section XI 

Inservice

Inspection, 

Subsections IWB, 

IWC, and IWD and 

Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and Ducting 

Components

Consistent with the 

GALL Report

(see SER 

Section 3.1.2.1.4)

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 caused 

by SCC, 

intergranular 

SCC (for 

stainless steel 

only), and 

thermal, 

mechanical, and 

vibratory loading

Chapter XI.M1, 

“ASME Code 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

Chapter XI.M2, 

“Water Chemistry,”

and XI.M35, 

“One-Time 

Inspection of ASME 

Code Class 1

Small-bore Piping”

No ASME Code 

Section XI 

Inservice

Inspections, 

Subsections IWB, 

IWC, and IWD, 

Water Chemistry, 

and One-Time 

Inspection of 

ASME 

Code Class 1

Small-bore Piping

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 caused 

by cyclic loading

Chapter XI.M1, 

“ASME Code 

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 

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 caused 

by primary water 

SCC

Chapter XI.M1, 

“ASME Code 

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 

BWRs (see SER 

Section 3.1.2.1.1)
3-191

Component Group

(SRP-LR Item No.)

Aging Effect or

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 (mechanical 

covers) exposed to 

reactor coolant 

(3.1.1-41)

Cracking caused 

by SCC, 

intergranular 

SCC, 

irradiation-assist

ed SCC

Chapter XI.M1, 

“ASME Code 

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 

LGS (see SER 

Section 3.1.2.1.1)

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 caused 

by SCC, primary 

water SCC

Chapter XI.M1, 

“ASME Code 

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 

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 

caused by pitting 

and crevice 

corrosion

Chapter XI.M1, 

“ASME Code 

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

Consistent with the 

GALL Report

(see SER 

Section 3.1.2.1.5)

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 

caused by

erosion

Chapter XI.M1, 

“ASME Code 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 2 components

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-192

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Nickel alloy and steel 

with nickel alloy 

cladding reactor 

coolant pressure 

boundary 

components exposed 

to reactor coolant 

(3.1.1-45)

Cracking caused 

by primary water 

SCC

Chapter XI.M1, 

“ASME Code 

Section XI ISI, IWB, 

IWC & IWD,” and 

Chapter XI.M2, 

“Water Chemistry,”

and, for nickel alloy, 

Chapter XI.M11B, 

“Cracking of Nickel

Alloy Components 

and Loss of Material 

Due to Boric 

Acid-induced 

Corrosion in RCPB 

Components (PWRs 

Only)”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel, 

nickel alloy, nickel

alloy welds and/or 

buttering CRD head 

penetration pressure 

housing or nozzles 

safe ends and welds 

(inlet, outlet, safety 

injection) exposed to 

reactor coolant 

(3.1.1-46)

Cracking caused 

by SCC, primary 

water SCC

Chapter XI.M1, 

“ASME Code 

Section XI ISI, IWB, 

IWC & IWD,” and 

Chapter XI.M2, 

“Water Chemistry,”

and, for nickel alloy, 

Chapter XI.M11B, 

“Cracking of Nickel

Alloy Components 

and Loss of Material 

Due to Boric 

Acid-induced 

corrosion in RCPB 

Components (PWRs 

Only)”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel, 

nickel alloy CRD

head penetration 

pressure housing 

exposed to reactor 

coolant (3.1.1-47)

Cracking caused 

by SCC, primary 

water SCC

Chapter XI.M1, 

“ASME Code 

Section XI ISI, IWB, 

IWC & IWD,” and 

Chapter XI.M2, 

“Water Chemistry”

No Not applicable 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 

caused by boric 

acid corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion,” and 

Chapter XI.M11B, 

“Cracking of Nickel

Alloy Components 

and Loss of Material 

Due to Boric 

Acid-Induced 

Corrosion in RCPB 

Components (PWRs 

Only)”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-193

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel reactor coolant 

pressure boundary 

external surfaces or 

closure bolting 

exposed to air with 

borated water 

leakage (3.1.1-49)

Loss of material 

caused by boric 

acid corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

CASS Class 1

piping, piping 

component, and 

piping elements and 

CRD pressure 

housings exposed to 

reactor coolant 

>250 °C (>482 °F) 

(3.1.1-50)

Loss of fracture 

toughness 

caused by

thermal aging 

embrittlement

Chapter XI.M12, 

“Thermal Aging 

Embrittlement of 

Cast Austenitic 

Stainless Steel 

(CASS)”

No Not applicable Not applicable to 

LGS (See SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy Babcock 

& Wilcox reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-51)

Cracking caused 

by SCC, 

irradiation-assist

ed SCC, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy 

Combustion 

Engineering reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-52)

Cracking caused 

by SCC, 

irradiation-assist

ed SCC, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy 

Westinghouse 

reactor internal 

components exposed 

to reactor coolant 

and neutron flux 

(3.1.1-53)

Cracking caused 

by SCC, 

irradiation-assist

ed SCC, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No Not applicable 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 (3.1.1-54)

Loss of material 

caused by wear

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M37, 

“Flux Thimble Tube 

Inspection”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-194

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel 

thermal shield 

assembly, thermal 

shield flexures 

exposed to reactor 

coolant and neutron 

flux (3.1.1-55)

Cracking caused 

by fatigue; Loss 

of material 

caused by wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy 

Combustion 

Engineering reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-56)

Loss of fracture 

toughness 

caused by

neutron 

irradiation 

embrittlement; or 

changes in 

dimension 

caused by void 

swelling; or loss 

of preload 

caused by

thermal and 

irradiation 

enhanced stress 

relaxation; or 

loss of material 

caused by wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy Babcock 

& Wilcox reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-58)

Loss of fracture 

toughness 

caused by

neutron 

irradiation 

embrittlement; or 

changes in 

dimension 

caused by void 

swelling; or loss 

of preload 

caused by

thermal and 

irradiation 

enhanced stress 

relaxation; or 

loss of material 

because of wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-195

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel or 

nickel alloy 

Westinghouse 

reactor internal 

components exposed 

to reactor coolant 

and neutron flux 

(3.1.1-59)

Loss of fracture 

toughness 

caused by

neutron 

irradiation 

embrittlement; or 

changes in 

dimension 

because of void 

swelling; or loss 

of preload 

caused by

thermal and 

irradiation 

enhanced stress 

relaxation; or 

loss of material 

caused by wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not applicable 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 

caused by

flow-accelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Flow-Accelerated 

Corrosion

Consistent with the

GALL Report (see 

SER 

Section 3.1.2.1)

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 

caused by

flow-accelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

High-strength, 

low-alloy steel, or 

stainless steel 

closure bolting; 

stainless steel CRD

head penetration 

flange bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-62)

Cracking caused 

by SCC

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel or stainless 

steel closure bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-63)

Loss of material 

caused by

general (steel 

only), pitting, 

and crevice 

corrosion or 

wear

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report
3-196

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel closure bolting 

exposed to 

air-indoor,

uncontrolled 

(3.1.1-64)

Loss of material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel CRD

head penetration 

flange bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-65)

Loss of material 

caused by wear

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

High-strength, 

low-alloy steel, or 

stainless steel 

closure bolting; 

stainless steel CRD

head penetration 

flange bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-66)

Loss of preload 

caused by

thermal effects, 

gasket creep, 

and 

self-loosening

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable 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 

caused by

thermal effects, 

gasket creep, 

and 

self-loosening

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”) 

caused by

corrosion of 

carbon steel 

tube support 

plate

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable 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 caused 

by outer 

diameter SCC

and 

intergranular 

attack

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable 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 caused 

by primary water 

SCC

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-197

Component Group

(SRP-LR Item No.)

Aging Effect or

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 caused 

by SCC 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 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 

caused by

erosion, general, 

pitting, and 

crevice 

corrosion, 

ligament 

cracking caused 

by corrosion

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable 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 

caused by

wastage and 

pitting corrosion

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable 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 

caused by

flow-accelerated 

corrosion

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable 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 

caused by

flow-accelerated 

corrosion and 

general 

corrosion

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable 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 

caused by

fretting

Chapter XI.M19, 

“Steam Generators”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-198

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Nickel alloy steam 

generator tubes and 

sleeves exposed to 

secondary feedwater 

or steam (3.1.1-77)

Loss of material 

caused by wear 

and fretting

Chapter XI.M19, 

“Steam Generators”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

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 caused 

by SCC

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection,” or 

Chapter XI.M1, 

“ASME Code 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD.”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel; steel 

with nickel alloy or 

stainless steel 

cladding; and nickel

alloy reactor coolant 

pressure boundary 

components exposed 

to reactor coolant 

(3.1.1-79)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

and One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel or 

steel with stainless 

steel cladding 

pressurizer relief 

tank: tank shell and 

heads, flanges, 

nozzles (none-ASME 

Code Section XI 

components) 

exposed to treated 

borated water >60°C 

(>140°F) (3.1.1-80)

Cracking caused 

by SCC

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable 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 caused 

by SCC

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable 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 caused 

by SCC, primary 

water SCC

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-199

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel steam 

generator shell 

assembly exposed to 

secondary feedwater 

or steam (3.1.1-83)

Loss of material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable 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 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

and One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel, 

nickel alloy, and steel 

with nickel alloy 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 

caused by pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

and One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel steam 

generator primary 

side divider plate 

exposed to reactor 

coolant (3.1.1-86)

Cracking caused 

by SCC

Chapter XI.M2, 

“Water Chemistry”

No Not applicable 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 

caused by pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel; steel 

with nickel alloy or 

stainless steel 

cladding; and nickel

alloy reactor coolant 

pressure boundary 

components exposed 

to reactor coolant 

(3.1.1-88)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-200

Component Group

(SRP-LR Item No.)

Aging Effect or

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 closed 

cycle cooling water 

(3.1.1-89)

Loss of material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable 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 

caused by

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable 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 caused 

by SCC; loss of 

material caused 

by general, 

pitting, and 

crevice 

corrosion, or 

wear (BWR)

Chapter XI.M3, 

“Reactor Head 

Closure Stud Bolting”

No Reactor Head 

Closure Stud 

Bolting

Consistent with the 

GALL Report

High-strength 

low-alloy steel 

closure head stud 

assembly exposed to 

air with potential for 

reactor coolant 

leakage (3.1.1-92)

Cracking caused 

by SCC; loss of 

material caused 

by general, 

pitting, and 

crevice 

corrosion, or 

wear (PWR)

Chapter XI.M3, 

“Reactor Head 

Closure Stud Bolting”

No Not applicable 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 

caused by

selective 

leaching

Chapter XI.M33, 

“Selective Leaching “

No Not applicable 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 caused 

by SCC, 

intergranular 

SCC

Chapter XI.M4, 

“BWR Vessel ID 

Attachment Welds,”

and Chapter XI.M2, 

“Water Chemistry”

No BWR Vessel ID 

Attachment Welds 

and Water 

Chemistry

Consistent with the 

GALL Report

Steel (with or without 

stainless steel 

cladding) feedwater 

nozzles exposed to 

reactor coolant 

(3.1.1-95)

Cracking caused 

by cyclic loading

Chapter XI.M5, 

“BWR Feedwater 

Nozzle”

No BWR Feedwater 

Nozzle

Consistent with the 

GALL Report
3-201

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel (with or without 

stainless steel 

cladding) CRD return 

line nozzles exposed 

to reactor coolant 

(3.1.1-96)

Cracking caused 

by cyclic loading

Chapter XI.M6, 

“BWR Control Rod 

Drive Return Line 

Nozzle”

No BWR CRD 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 caused 

by SCC, 

intergranular 

SCC

Chapter XI.M7, 

“BWR Stress 

Corrosion Cracking,”

and Chapter XI.M2, 

“Water Chemistry”

No BWR Stress 

Corrosion 

Cracking, Water 

Chemistry, 

One-Time 

Inspection, and 

ASME Code 

Section XI 

Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWB

Consistent with the 

GALL Report

(see SER 

Section 3.1.2.1.6)

Stainless steel or 

nickel alloy 

penetrations: 

instrumentation and 

SLC exposed to 

reactor coolant 

(3.1.1-98)

Cracking caused 

by SCC, 

intergranular 

SCC, cyclic 

loading

Chapter XI.M8, 

“BWR Penetrations,”

and Chapter XI.M2, 

“Water Chemistry”

No BWR Penetrations 

and Water 

Chemistry

Consistent with the 

GALL Report

CASS; 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 

caused by

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 

caused by 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 caused 

by 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 CRD

assemblies CRD

housing exposed to 

reactor coolant 

(3.1.1-102)

Cracking caused 

by SCC, 

intergranular 

SCC

Chapter XI.M9, 

“BWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No BWR Vessel 

Internals and 

Water Chemistry

Consistent with the 

GALL Report
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Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel and 

nickel alloy reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-103)

Cracking caused 

by SCC, 

intergranular 

SCC, 

irradiation-assist

ed SCC

Chapter XI.M9, 

“BWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No BWR Vessel 

Internals and 

Water Chemistry

Consistent with the 

GALL Report

X-750 alloy reactor 

vessel internal 

components exposed 

to reactor coolant 

and neutron flux 

(3.1.1-104)

Cracking caused 

by intergranular 

SCC

Chapter XI.M9, 

“BWR Vessel 

Internals” for core 

plate, and Chapter 

XI.M2, “Water 

Chemistry”

No BWR Vessel 

Internals and 

Water Chemistry

Consistent with the 

GALL Report

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 

LGS (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 NA None Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping element 

exposed to gas, 

concrete, air with 

borated water 

leakage, air-indoor, 

uncontrolled 

(3.1.1-107)

None None NA None Consistent with the 

GALL Report

The staff’s review of the reactor vessel, RVIs, and RCS component groups followed any one of 

several approaches. One approach, documented in SER Section 3.1.2.1, reviewed AMR 

results for components that the applicant indicated are consistent with the GALL Report and 

require no further evaluation. Another approach, documented in SER Section 3.1.2.2, reviewed 

AMR results for components that the applicant indicated are consistent with the GALL Report 
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and for which further evaluation is recommended. A third approach, documented in SER 

Section 3.1.2.3, reviewed AMR results for components that the applicant indicated are not 

consistent with, or not addressed in, the GALL Report. The staff’s review of AMPs credited to 

manage or monitor aging effects of the reactor vessel, RVIs, and RCS components is 

documented in SER Section 3.0.3.

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, RVIs, and RCS components:

 • ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

 • BWR CRD Return Line Nozzle

 • BWR Feedwater Nozzle

 • BWR Penetrations

 • BWR Stress Corrosion Cracking

 • BWR Vessel ID Attachment Welds

 • BWR Vessel Internals

 • Bolting Integrity

 • Flow-Accelerated Corrosion

 • Inspection of internal Surfaces in Miscellaneous Piping and Ducting Components

 • One-Time Inspection

 • One-Time 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 AMRs for the RCPB, RPV, and RVIs

components and indicate AMRs claimed to be consistent with the GALL Report.

The staff reviewed the information in the LRA. 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 was applicable and that the applicant identified the appropriate GALL Report AMRs. The 

staff’s evaluation follows.

LRA Table 3.1.1, item 3.1.1-60, addresses steel piping components exposed to reactor coolant 

that are being managed for wall thinning caused by flow-accelerated corrosion. The GALL 

Report recommends GALL Report AMP XI.M17, “Flow-Accelerated Corrosion,” to manage wall 

thinning for this component group. The applicant stated that this item is not applicable because 

there are no steel piping, piping components, or piping elements exposed to reactor coolant that 

are susceptible to wall thinning caused by flow-accelerated corrosion in the reactor vessel, 

internals and reactor coolant system. The staff evaluated the applicant’s claim and reviewed 
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the information provided in EPRI 1013013, “An Evaluation of Flow-Accelerated Corrosion in the 

Bottom Head Drain Lines of Boiling Water Reactors,” which concluded that both Limerick 

Generating Station (LGS) units were viewed as having very limited susceptibility to damage 

from this concern caused by the high level of oxidant present. However, a more recent EPRI 

document, 1016949, “Flow-Accelerated Corrosion in Boiling Water Reactor Bottom Head Drain 

Lines – 2008 Update,” concludes that some degree of inspection of the drain lines should be 

performed. It was not clear to the staff how the applicant’s claim that no components exposed 

to reactor coolant are susceptible to wall thinning in the RCS was valid. By letter dated 

February 14, 2012, the staff issued RAI 3.1.1.60-1 requesting the applicant to provide its bases 

for its claim that there are no steel piping components exposed to reactor coolant that are 

susceptible to flow-accelerated corrosion in the RCS. 

In its response dated March 13, 2012, the applicant stated that the bottom head drain line 

includes approximately a 7-foot-long section of 2-inch-diameter carbon steel piping, and 

although it is excluded from inspection requirements, it is considered susceptible to 

flow-accelerated corrosion. The response also stated that an extent of condition review 

identified additional RCS components within the feedwater system that are being managed by 

the Flow-Accelerated Corrosion program, but were not included in LRA Table 3.1.2-1. The 

response also revised LRA Table 3.1.2-1, to include item 3.1.1-60 under “Class 1 Piping and 

Fittings and Branch Connections less than NPS 4,” and “Piping, piping components, and piping 

elements.” The applicant’s response is acceptable because the carbon steel components 

susceptible to flow-accelerated corrosion addressed in item 3.1.1-60 are now included in the 

revised LRA Table 3.1.2-1. The staff’s concern described in RAI 3.1.1-60 is resolved.

LRA Table 3.1.1, item 3.1.1-99 addresses CASS, precipitation hardened stainless steel, 

martensitic stainless steel and X-750 alloy reactor internal components exposed to reactor 

coolant and neutron flux. For the AMR item that cites generic note C, the LRA credits BWR 

Vessel Internals program to manage loss of fracture toughness caused by thermal aging 

embrittlement and neutron irradiation embrittlement of the CASS RVI components. The GALL 

Report recommends GALL Report AMP XI.M9, "BWR Vessel Internals" to ensure that this aging 

effect is adequately managed. 

GALL Report AMP XI.M9 states that it does not directly monitor for loss of fracture toughness 

that is induced by thermal aging or neutron irradiation embrittlement. The GALL Report also 

states that the impact of loss of fracture toughness on component integrity is indirectly managed 

by using visual or volumetric examination techniques to monitor for cracking in the components. 

The GALL Report also states that loss of fracture toughness caused by neutron embrittlement in 

CASS materials can occur with a neutron fluence greater than 1.0E+17 n/cm2 (E > 1 MeV) and 

loss fracture toughness of CASS material caused by thermal embrittlement is dependent on the 

material’s casting method, molybdenum content, and ferrite content. 

In its review, the staff noted that the BWR Vessel Internal program includes periodic visual 

inspections based on material susceptibility evaluation. However, LRA Section B.2.1.9 for the 

BWR Vessel Internals program does not address the screening criteria for the susceptibility of 

CASS components to loss of fracture toughness. Therefore, the staff needed to clarify whether 

the applicant’s screening criteria for material susceptibility are consistent with the GALL Report. 

By letter dated January 18, 2012, the staff issued RAI 3.1.1.99-1, requesting that the applicant 

describe the screening criteria for the susceptibility of CASS RVI components to loss of fracture 

toughness caused by thermal aging and neutron irradiation embrittlement. The staff also 
3-205

requested that if the screening criteria are not consistent with the GALL Report, the applicant 

justify why the applicant's screening criteria are adequate to manage the aging effect.

In its response dated February 16, 2012, the applicant stated that the screening criteria used to 

determine the susceptibility of CASS RVI components to loss of fracture toughness are 

consistent with GALL Report AMP XI.M9. The applicant also confirmed that the screening 

criteria to determine the susceptibility of CASS components to thermal aging are based on the 

casting method, molybdenum content, and percent ferrite, consistent with criteria set forth in the 

NRC letter, dated May 19, 2000, which is referenced in the GALL Report. The applicant further 

indicated that if casting method, ferrite or molybdenum content cannot be determined for any 

CASS components, they will be assumed to be susceptible to thermal aging for the purposes of 

determining program examination requirements. In addition, the applicant stated that CASS 

components that are exposed to neutron fluence in excess of 1.0E+17 n/cm2 (E > 1 MeV) are 

susceptible to neutron irradiation embrittlement. In its review, the staff finds the applicant’s 

response acceptable because the applicant’s screening criteria used to determine the 

susceptibility of CASS RVI components to loss of fracture toughness are consistent with the 

GALL Report.

The staff’s evaluation of the BWR Vessel Internals program is documented in SER Section 

3.0.3.2.2. In its review of the components associated with items 3.1.1-99, the staff finds the 

applicant’s proposal to manage loss of fracture toughness for these components acceptable 

because the BWR Vessel Internals program includes periodic visual inspections based on the 

adequate screening criteria to determine the material susceptibility to loss of fracture toughness, 

consistent with the GALL Report. 

LRA Table 3.1.2-3 contains an AMR result for stainless steel (part of jet pump assembly) 

components in a reactor coolant and neutron flux environment with an aging effect of loss of 

preload being managed by the BWR Vessels Internals program. The staff noted that loss of 

preload is usually associated with bolts and in the reactor coolant and neutron flux environment 

is addressed as a TLAA. Therefore, by letter dated January 17, 2012, the staff issued RAI 

3.1.2.3-1 requesting the applicant to clarify what component is referenced in the AMR item, and 

what specific features or activities of the BWR Vessel Internals program will manage the aging 

effect of loss of preload. By letter dated February 15, 2012 the applicant responded to 

RAI 3.1.2.3-1 and stated that the component referenced in the AMR is the jet pump slip joint 

repair clamps and that the AMR referenced in the staff’s RAI was deleted in response to 

RAI 4.6.9-1 because the TLAA analysis provided in LRA Section 4.6.9 was revised to document 

that the fluence value used to determine loss of preload in the design analysis will not be 

exceeded during the period of extended operation. The staff finds this response acceptable 

because the applicant clarified that the aging effect of loss of preload will not be managed by 

the BWR Vessel Internals program. The staff’s evaluation of the associated TLAA is 

documented in SER Section 4.6.9.2. As such, the staff’s concern described in RAI 3.1.2.3-1 is 

resolved.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their 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).
3-206

3.1.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.1.1 items 3.1.1-41, and 3.1.1.105, the applicant claimed that they were not 

applicable. 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 3.1.1 items 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, 3.1.1-51 through 3.1.1-59, 3.1.1-61, 3.1.1-64, 3.1.1-65, 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 PWRs. The staff reviewed the SRP-LR, 

confirmed these items only apply to PWRs, and finds these items are not applicable to LGS.

For LRA Table 3.1.1, item 3.1.1-50, the applicant claimed it was not applicable. The staff 

reviewed the LRA and confirmed that the applicant’s LRA does not have any AMR results that 

are applicable for this item. As addressed in GALL Report AMP XI.M12, pump casings and 

valve bodies do not require material screening for susceptibility to thermal aging embrittlement 

and the existing ASME Code Section XI inspection requirements are adequate to manage loss 

of fracture toughness caused by thermal aging embrittlement. In addition, LRA Table 3.1.1, 

item 3.1.1-38 addresses the applicant’s aging management for loss of fracture toughness of the 

Class 1 CASS pump casings and valve bodies.

LRA Table 3.1.1, item 3.1.1-62, addresses high-strength, low-alloy steel, or stainless steel

closure bolting and stainless steel CRD head penetration flange bolting exposed to air with 

reactor coolant leakage. The GALL Report recommends GALL Report AMP XI.M18 “Bolting 

Integrity” to manage cracking caused by SCC for this component group. The applicant stated 

that this item is not applicable because it is only applicable to PWR plants. The staff lacks 

sufficient information to evaluate the applicant’s claim because although the SRP-LR states that 

item 3.1.1-62 is applicable to PWRs, the applicant has carbon and low-alloy steel bolting 

exposed to air with reactor coolant leakage within the scope of license renewal. The staff noted 

that the applicant is managing these items for loss of material and loss of preload, but not 

cracking caused by SCC. By letter dated January 18, 2012, the staff issued RAI 3.1.2.1.1-1 

requesting the applicant to state the basis for why cracking caused by SCC is not applicable to

carbon and low-alloy steel closure bolting within the scope of license renewal and exposed 

externally to air with reactor coolant leakage in the RCS.

In its response dated February 16, 2012, the applicant stated that with the exception of the 

reactor head closure bolting, which is managed by the Reactor Head Closure Stud Bolting 

program, there are no stainless steel or high-strength carbon or low-alloy steel bolts within the 

scope of license renewal that are exposed to air with reactor coolant leakage in the RCS;

therefore, no bolting other than the reactor head closure studs is susceptible to SCC.

The staff finds the applicant’s response acceptable because there are no stainless steel or 

high-strength carbon or low-alloy steel bolts within the scope of license renewal that are 

exposed to air with reactor coolant leakage in the RCS that would be managed by the Bolting 

Integrity program. The staff’s concern described in RAI 3.1.2.1.1-1 is resolved.
3-207

3.1.2.1.2 Cracking Caused by SCC, Intergranular SCC, and Irradiation-Assisted SCC

LRA Table 3.1.1, item 3.1.1-29 addresses nickel alloy core shroud and core plate access hole 

cover (welded) components exposed to reactor coolant, which are being managed for cracking 

caused by SCC, IGSCC, and irradiation-assisted SCC. The LRA credits the BWR Vessel 

Internals program and the Water Chemistry program to manage the aging effect. The GALL 

Report recommends GALL Report AMP XI.M1, “ASME Code Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD,” and GALL Report AMP XI.M2, “Water Chemistry,” along with 

augmented inspections for crevice condition for the access hole cover to ensure that these 

aging effects are adequately managed. The associated AMR items cite generic note E, 

indicating that the LRA AMR is consistent with the GALL Report item for material, environment, 

and aging effect, but a different AMP is credited.

For those items associated with generic note E, GALL Report AMP XI.M1 recommends using 

periodic visual, surface, or volumetric examination and leakage testing 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. In 

addition, the GALL Report recommends augmented inspection for the welded core plate access 

hole cover where crevice conditions exist. In its review of components associated with 

item 3.1.1-29 for which the applicant cited generic note E, the staff noted that the BWR Vessel 

Internals program is substituted for the ASME Code Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD program because it proposes to manage the aging of 

nickel-alloy and stainless steel RVI components through ISIs in accordance with

component-specific BWRVIP documents that include industry-approved inspection procedures

and flaw evaluations. The staff noted that the BWRVIP recommended inspections are often 

more stringent than those inspections specified by ASME Code, Section XI, such as the 

BWRVIP use of EVT-1 or UT, in place of VT-1 or VT-3 from ISI for select components and 

locations. The staff noted that the applicant’s use of its Water Chemistry program is consistent 

with the recommendations of the GALL Report.

The staff’s evaluation of the BWR Vessel Internals and Water Chemistry programs are 

documented in SER Sections 3.0.3.2.2 and 3.0.3.1.2, respectively. The staff noted that the 

Water Chemistry program includes controls of chemistry parameters that create an environment 

that is not conducive for any form of SCC to occur.

In its review of components associated with item 3.1.1-29, the staff finds the applicant’s 

proposal to manage aging using the BWR Vessel Internals program and Water Chemistry 

program acceptable because the BWR Vessel Internals program follows the guidelines 

recommended by the BWRVIP and includes specific flaw evaluation and repair 

recommendations to facilitate post-inspection review; and the applicant’s use of the Water 

Chemistry program creates an environment that is not conducive for loss of material to occur, 

and is consistent with the recommendations of the GALL Report.

The staff concludes that 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).
3-208

3.1.2.1.3 Loss of Material Caused by General, Pitting, and Crevice Corrosion

LRA Table 3.1.2-1 items associated with LRA Table 3.1.1, item 3.1.1-31, address stainless steel 

and carbon steel RPV flange leak detection line and carbon steel ASME Code, Class 1, piping 

and branch connections less then NPS 4 exposed to reactor coolant, which will be managed for 

loss of material caused by general, pitting, and crevice corrosion. For these AMR items that cite 

note E with plant-specific note 2, the LRA credits the Water Chemistry program and the 

One-Time Inspection program to manage the aging effects for steel and stainless steel RPV 

flange leak detection line and carbon steel ASME Code, Class 1, piping and branch connections 

less than NPS 4. 

The staff noted that LRA Table 3.1.2-1 relates these AMR items with the GALL Report

item IV.C1.RP-39, which manages the aging effects of steel and stainless steel isolation 

condenser components exposed to reactor coolant. The staff also noted that the applicant does 

not have isolation condenser components in its design; however, the material, environment, and 

aging effect combination of the GALL Report item IV.C1.RP-39 is applicable to the applicant’s 

components cited in LRA Table 3.1.2-1 (i.e., RPV flange leak detection line and small-bore 

ASME Code, Class 1, piping and branch connections). Therefore, the staff finds the applicant’s 

AMR result that identifies these components under the GALL Report item IV.C1.RP-39, 

appropriate. The GALL Report recommends GALL Report AMPs XI.M1, “ASME Code 

Section XI Inservice Inspection IWB, IWC, and IWD,” and XI.M2, “Water Chemistry” to ensure 

that loss of material caused by general, pitting, and crevice corrosion are adequately managed 

for steel and stainless steel isolation condenser components exposed to reactor coolant. GALL 

Report AMP XI.M1 includes VT-2 examination of pressure-retaining components during system 

leakage testing, which confirms that the component integrity is not affected by loss of material 

caused by corrosion. In addition, GALL Report AMP XI.M2 includes the specified limits for 

corrosive substances (such as chlorides, sulfates, and dissolved oxygen), sampling and 

analysis frequencies for water chemistry parameters, and control of reactor water chemistry to 

mitigate the environmental effects on loss of material caused by corrosion. 

The staff noted that the applicant’s carbon steel RPV flange leak detection line is not normally 

exposed to reactor coolant during normal operation. The staff also noted that the applicant’s 

carbon steel ASME Code, Class 1, piping and branch connections less then NPS 4, are being 

managed for cracking caused by SCC by the applicant’s existing ASME Code Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD, One-Time Inspection of ASME Code 

Class 1 Small-bore Piping, and Water Chemistry programs, consistent with the GALL Report. 

The staff’s evaluations of the ASME Code Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD, One-Time Inspection of ASME Code Class 1 Small-bore Piping, and the Water 

Chemistry programs are documented in SER Sections 3.0.3.1.1, 3.0.3.1.14, and 3.0.3.1.2, 

respectively.

In its review of the components associated with LRA item 3.1.1-31, for which the applicant cited 

generic note E, the staff finds the applicant’s proposal to manage aging using the One-Time 

Inspection program and the Water Chemistry program acceptable because the Water Chemistry 

program includes periodic monitoring of water chemistry conditions, and control of known 

detrimental contaminants below the specified levels, such that loss of material is mitigated or 

prevented. In addition, the One-Time Inspection program will confirm the effectiveness of the 

Water Chemistry program before the period of extended operation.
3-209

The staff concludes that for the components associated with LRA item 3.1.1-31, 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).

3.1.2.1.4 Loss of Fracture Toughness Due to Thermal Aging Embrittlement

LRA Table 3.1.1, item 3.1.1-38 addresses CASS Class 1 pump casings, and valve bodies and 

bonnets exposed to reactor coolant greater than 250° C (482 °F). For the AMR item that cites 

generic note E, the LRA credits the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components program to manage loss of fracture toughness caused by thermal aging 

embrittlement of the CASS pump casing in the reactor water cleanup (RWCU) system. The 

GALL Report recommends GALL Report AMP XI.M1, “ASME Code Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD” to ensure that this aging effect is adequately 

managed for Class 1 components. GALL Report AMP XI.M1 also recommends using visual 

inspections to manage aging. The LRA does not provide sufficient information on how the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program will 

manage this aging effect for the pump casing as further evaluated below. 

In its review, the staff noted that LRA item 3.1.1-38 is associated with SRP-LR Table 3.1-1, 

ID 38, which addresses aging management for Class 1 RCPB components. Therefore, the staff 

needed to clarify whether the pump casing in the RWCU system is an ASME Code Class 1 

component, for which the GALL Report recommends the ASME Code Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD program to manage the aging effect. The staff 

also needed to clarify whether the operating temperature of the pump casing confirms that loss 

of fracture toughness caused by thermal aging embrittlement is applicable to this component. 

The staff further noted that LRA Section B.2.1.26, which describes the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components program, does not provide specific 

information about how this program will manage loss of fracture toughness of the pump casing. 

By letter dated January 18, 2012, the staff issued RAI 3.1.1.38-1 requesting the applicant to

provide additional information to clarify the following items: (1) ASME Code Class of the pump 

casing in the RWCU system and examination categories and methods for the pump casing, 2) 

operating temperature of the pump casing to confirm whether loss of fracture toughness 

caused by thermal aging embrittlement is applicable to this component (i.e., T > 482 °F), (3) 

operating experience of this component in terms of occurrence of cracking and leakage, and (4) 

how the applicant’s program will manage loss of fracture toughness of the pump casing.

In its response dated February 16, 2012, the applicant stated that the RWCU pump casings are 

ASME Code Class 3 components. The applicant also indicated that ASME Code Section XI, 

Subsection IWD, Table IWD-2500-1 provides the examination requirements for ASME 

Code Class 3 components and ASME Code Table IWD-2500-1 does not include any 

examination requirements for pump casings. The applicant further confirmed that that the pump 

casings (RWCU B and C pump casings) on both units are made from CASS material and the 

operating temperature of the pumps in the RWCU system is nominally 545 °F such that loss of 

fracture toughness caused by thermal aging embrittlement is applicable to the pump casings. 

The applicant further confirmed that that the pump casings (RWCU B and C pump casings) on 

both LGS Units 1 and 2 have not had any indication of flaws, cracking or leakage from the pump 

casings. In its response, the applicant indicated that consistent with the “detection of aging 

effects” program element of GALL Report AMP XI.M38, the Inspection of Internal Surfaces in 
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Miscellaneous Piping and Ducting Components program, will manage loss of fracture toughness 

for the pump casings by implementing visual inspections for evidence of cracking whenever the 

pumps are disassembled for maintenance. The applicant further stated that any evidence of 

cracking identified during visual inspection will be evaluated for potential loss of intended 

function under the CAP.

In its review, the staff noted that the basis for using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program to manage loss of fracture toughness 

of the RWCU CASS pump casings has not been identified as an enhancement to the “scope of 

program” element. The basis also does not establish exactly which type of visual inspections 

and inspection frequency will be used to detect crack indications as an indirect measure for 

determining whether loss of fracture toughness is occurring in the RWCU pump casings. In 

addition, the program does not address how the visual inspection method and frequency will be 

capable of detecting and resolving flaw sizes that are less than the limiting lower bound critical 

flaw size for the RWCU pump casings, as assessed for limiting thermal aging embrittlement 

conditions. Thus, the staff needed additional information for concluding that the program (LRA 

Section B.2.1.26) will be capable of managing thermal aging embrittlement of the RWCU CASS 

pump casings.

By letter dated May 18, 2012, the staff issued RAI 3.1.1.38-1.1, requesting the applicant to

justify why the applicant’s opportunistic inspections and inspection method are sufficient to 

manage loss of fracture toughness of the pump casings through timely detection of a flaw 

before it grows to the size that can lead to rapid unstable crack propagation caused by thermal 

aging embrittlement. The staff also requested that as part of the response, the applicant clarify 

which type of visual inspection method (e.g., EVT-1, VT-1 or VT-3) will be used to detect flaws 

in the components and justify why the performance of these visual inspections on an 

opportunistic basis is considered to be capable of detecting and resolving a flaw before unstable 

crack propagation in the components (e.g., the basis for concluding that the visual inspection 

method and frequency will be capable of detecting and resolving a flaw smaller than the critical 

crack size of the component under reduced fracture toughness conditions, as induced by 

thermal aging embrittlement). In addition, the staff requested that the applicant justify why the 

applicant’s use of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program to manage loss of fracture toughness of these pump casings is not

identified as an enhancement to the “scope of program” element of GALL Report AMP XI.M38.

In its response dated May 31, 2012, the applicant clarified that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components program is a new program and that 

LRA Section A.2.1.26, which provides the UFSAR supplement for this program, was revised to 

specifically include aging management for loss of fracture toughness and cracking as additional 

aging effects for the program as part of its response to RAI B.2.1.26-1 within the letter dated 

February 15, 2012. The applicant also indicated that GALL Report AMP XI.M38 is used to 

manage cracking in stainless steel piping and piping components, as specified in GALL Report 

item VII.H2.AP-128. 

In addition, the applicant indicated that the inspections of the ASME Code, Class 3, pump 

casings will be performed using VT-3 method, in a consistent manner with the inspection 

method specified by ASME Code, Section XI, Table IWB-2500-1 for Class 1 pump casings. The 

applicant further indicated GALL Report item IV.C1.R-08 addresses aging management of loss 

of fracture of toughness due the thermal aging embrittlement in ASME Code Class 1 CASS 

pump casings and valve bodies that are exposed to the reactor coolant at temperatures greater 
3-211

than 482 °F. GALL Report item IV.C1.R-08 recommends that GALL Report AMP XI.M1, “ASME 

Code Section XI, Inservice Inspection, Subsections IWB, IWC, and IWD,” be used to manage 

this aging effect. 

In its response, the applicant indicated that GALL Report item IV.C1.R-08 clarifies that for pump 

casings and valve bodies, screening for susceptibility to thermal aging is not necessary and the 

ASME Code Section XI inspection requirements are sufficient for managing the effects of loss of 

fracture toughness caused by thermal aging embrittlement of Class 1 CASS pump casings and 

valve bodies. Furthermore, the applicant indicated that since ASME Code Section XI does not 

include an internal inspection requirement for Class 3 pump casings, the use of the 

opportunistic inspections specified in the applicant’s program is sufficient to manage loss of 

fracture toughness of the RWCU CASS pump casings. 

In its review, the staff confirmed that the applicant’s response to RAI B.2.1.26-1, dated 

February 15, 2012, includes the revised UFSAR supplement that clarifies loss of fracture 

toughness is one of the aging effects that are managed by the applicant’s Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components program. The staff also finds that 

the applicant’s revision to the UFSAR supplement is adequate because this revision clarifies 

that loss of fracture toughness is one of the aging effects that are managed by the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components program. 

The staff further noted that that the VT-3 method, which the applicant’s inspections will use for 

the Class 3 pump casings, is the same method specified in ASME Code Section XI, Table 

IWB-2500-1 for Class 1 pump casings. However, the applicant’s response did not clearly 

address justification as to why applicant’s opportunistic inspections would be adequate to 

manage the aging effect of the RWCU CASS pump casings. Therefore, the staff required 

additional information to further evaluate the adequacy of the opportunistic inspections for the 

aging management. 

By letter dated June 12, 2012, the staff issued RAI 3.1.1.38-1.2, requesting that the applicant 

provide results from any inspection(s) that have been performed on the CASS pump casings 

including when the inspection(s) were completed. The staff also requested that based on the 

history and results of the previous inspections, the applicant justify why the aging management 

would not need to ensure the following inspections of the RWCU pump casings: (1) an 

inspection of the representative pump casing of each unit before the period of extended 

operation, and (2) at least an inspection of the representative pump casing of each unit during 

the period of extended operation. 

In its response dated June 19, 2012, the applicant stated that the maintenance procedure for 

disassembly of the RWCU pumps includes a step to examine the casing interior for evidence of 

defects such as cracks, localized wear or pitting and damaged machined surfaces. The 

applicant also indicated that the RWCU CASS pumps were last inspected during the conduct of 

maintenance that required pump disassembly between 2001 and 2003. The applicant further 

indicated that none of the inspections identified pump casing degradation. Since ASME Code, 

Section XI does not include requirements to perform internal inspections of Class 3 pump 

casings, these inspections were not the examinations specified in ASME Code, Section XI.
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In addition, the applicant provided the following information in terms of the service 

characteristics and conditions of the RWCU CASS pump casings: 

 • These RWCU pumps with CASS casings are infrequently in service. The original design 

included three 50 percent capacity RWCU CASS pumps on each unit. The “A” RWCU 

pumps on both LGS units were replaced in the 1999−2001 timeframe with 100 percent 

capacity carbon steel pumps that use a different design that has proven to be very reliable.

 • Since 2001, the CASS “B” and “C” pumps have been normally valved out of service, and are 

operated very infrequently, only when the “A” RWCU pump is not available. Run time data 

are not collected on these pumps, but the system engineer can only recall the “B” and “C” 

pumps being used once caused by “A” pump unavailability during power operations. This 

instance was on LGS Unit 1 for approximately 6 weeks in 2006.”

 • Most of the “B” and “C” pump operating time expected in the future is during refueling 

outages at operating temperature less than 212 °F when maintenance activities take the “A” 

pump out of service. These pumps are not likely to experience thermal aging embrittlement 

before or during the period of extended operation since thermal aging embrittlement is 

applicable to components exposed to operating temperatures greater than 482 °F, they 

operated at these temperatures for only approximately 15 years, and from 2001 through the 

period of extended operation the CASS pumps are expected to be normally out of service at 

ambient temperature.

In its review, the staff noted that the applicant inspected the RWCU CASS pump casings as part 

of maintenance between 2001 and 2003 and the inspections did not identify any pump casing 

degradation. The applicant also clarified that the CASS RWCU “B” and “C” pumps are only 

seldom operated because they serve as standby pumps to the carbon steel “A” RWCU pump. 

In addition, the applicant clarified that most of the “B” and “C” pump operating time expected in 

the future is during refueling outages at operating temperatures less than 220 oF because they 

are normally isolated from the reactor coolant system. The staff finds that the applicant’s 

response is acceptable because the applicant clarified that the previous inspections, which were 

performed as part of maintenance, did not identify any degradation of the pump casings and the 

opportunistic inspections specified in the applicant’s program is sufficient to manage the 

potential concern about thermal aging embrittlement of the standby CASS pumps. Therefore, 

the staff’s concern described in RAIs 3.1.1.38-1, 3.1.1.38-1.1, and 3.1.1.38-1.2 is resolved.

The staff’s evaluation of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program is documented in SER Section 3.0.3.1.16. In its review of components 

associated with item 3.1.1-38 for which the applicant cited generic note E, the staff finds the 

applicant’s proposal to manage loss of fracture toughness using the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components program acceptable because 

(1) the applicant’s inspection method for the Class 3 RWCU CASS pump casings is consistent 

with that specified in ASME Code Section XI, Table IWB-2500-1 for Class 1 pump casings, 

(2) the applicant’s opportunistic inspections associated with the pump maintenance are 

adequate for aging management in consideration of the service characteristics and conditions of 

the CASS pump casings (i.e., very infrequent services at temperatures greater than 482 °F as 

stand-by pumps, and the service temperatures less than 212 degrees F during refueling 

outages), and (3) the inspections that were performed as part of applicant’s maintenance 

activities indicate the absence of degradation in the pump casings such that the operating 

experience also supports the adequacy of the applicant’s aging management approach. 
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The staff concludes that for LRA Item 3.1.1 38, 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).

3.1.2.1.5 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.1.1, item 3.1.1-43 addresses nickel-alloy and stainless steel RVI components

exposed to reactor coolant, which are being managed for loss of material caused by pitting and

crevice corrosion. The LRA credits the BWR Vessel Internals program and the Water

Chemistry program to manage the aging effect. The GALL Report recommends GALL Report 

AMP XI.M1, “ASME Code 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. The associated AMR items cite generic note E, indicating that the LRA 

AMR is consistent with the GALL Report item for material, environment, and aging effect, but a 

different AMP is credited.

For those items associated with generic note E, GALL Report AMP XI.M1 recommends using

periodic visual, surface, or volumetric examination and leakage testing along with GALL Report 

AMP XI.M2, which recommends monitoring and controlling known detrimental contaminants in

accordance with the recommendations of BWRVIP-130 to manage the aging of this item. In its 

review of components associated with item 3.1.1-43 for which the applicant cited generic

note E, the staff noted that the BWR Vessel Internals program is substituted for the ASME Code 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program because the 

applicant proposes to manage the aging of nickel-alloy and stainless steel RVI components 

through ISIs in accordance with component-specific BWRVIP documents that include 

industry-approved inspection procedures and flaw evaluations. The staff noted that the 

BWRVIP requires the use of enhanced inspection methods such as EVT-1 or UT, in lieu of the 

ISI required VT-1 or VT-3 for select components and locations. The staff noted that the 

applicant’s use of its Water Chemistry program is consistent with the recommendations of the 

GALL Report.

The staff’s evaluation of the BWR Vessel Internals and Water Chemistry programs are 

documented in SER Sections 3.0.3.2.2 and 3.0.3.1.2, respectively. The staff noted that the 

Water Chemistry program includes controls of chemistry parameters that create an environment 

not conducive for loss of material to occur.

In its review of components associated with item 3.1.1-43, the staff finds the applicant’s

proposal to manage aging using the BWR Vessel Internals program and Water Chemistry

program acceptable because the BWR Vessel Internals program follows the guidelines

recommended by the BWRVIP, which includes specific flaw evaluation and repair 

recommendations to facilitate post-inspection review; and the applicant’s use of the Water 

Chemistry program creates an environment not conducive for loss of material to occur, and is 

consistent with the recommendations of the GALL Report.

The staff concludes that 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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3.1.2.1.6 Cracking Caused by 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 4 NPS exposed to reactor coolant, 

which will be managed for cracking caused by SCC and IGSCC. For the AMR items that cite 

generic note A, the applicant proposes use of the BWR Stress Corrosion Cracking program and 

Water Chemistry program to manage the aging effect, consistent with the GALL Report. 

For LRA Table 3.1.1, item 3.1.1-97 the GALL Report recommends using GALL Report 

AMP XI.M2, “Water Chemistry,” and GALL Report AMP XI.M7, “BWR Stress Corrosion 

Cracking.” GALL Report AMP XI.M2 recommends water chemistry control to manage aging by 

limiting the concentrations of chemical species known to cause SCC and IGSCC and controlling 

dissolved oxygen levels to minimize the environmental effect on the aging effect. GALL Report 

AMP XI.M7 recommends volumetric examinations of stainless steel and nickel alloy 

components to detect and manage cracking caused by SCC and IGSCC. 

For the AMR item that addresses nickel alloy tubing with generic note E, the LRA credits the 

Water Chemistry program and One-Time Inspection program to manage the aging effect of the 

nickel alloy tubing within the HPCI steam flow element. The Water Chemistry program 

proposes to manage the aging of the components through periodic monitoring of the reactor 

coolant and control of known detrimental contaminants, such as chlorides, dissolved oxygen, 

and sulfate. The One-Time Inspection program proposes to manage the aging of the 

components through a one-time inspection of the representative sample including the lead 

components most susceptible to aging. The applicant indicated that the One-Time Inspection 

program will ensure that unacceptable degradation does not occur or will trigger additional 

actions to maintain the intended function of affected components during the period of extended 

operation. 

In its review, the staff noted that LRA Table 3.1.2-1 (LRA page 3.1-37) relates nickel alloy 

piping, piping components, and piping elements to LRA Table 3.1.1, item 3.1.1-97, indicating 

that these components are subject to cracking caused by SCC and IGSCC and the aging effect 

is managed by the One-Time Inspection program and the Water Chemistry program. The staff 

also noted that the One-Time Inspection program does not include periodic inspections that are 

included in the BWR Stress Corrosion Cracking program or the ASME Code Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD program. The LRA does not clearly 

indicate whether any of these nickel alloy components addressed under item 3.1.1-97 is 

included in the scope of the BWR Stress Corrosion Cracking program or the ASME Code 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program. 

By letter dated April 30, 2012, the staff issued RAI 3.1.1.97-1, requesting the applicant to

provide information to clarify why any of these nickel alloy components are not included in the 

scope of the BWR Stress Corrosion Cracking program or the ASME Code Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD program, which includes periodic inspections 

(e.g., describe pipe size, location, and ASME Code classes of the components and the coolant 

temperature to which these components are exposed). The staff also requested that the 

applicant justify why the One-Time Inspection program, which does not include periodic 

inspections, is adequate to manage cracking caused by SCC and IGSCC of the nickel alloy 

components. The staff further requested that as part of the response, the applicant clarify if 

SCC or IGSCC has been observed in these components in order to demonstrate that 
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applicant’s operating experience supports the adequacy of the One-Time Inspection program to 

manage the aging effect.

In its response dated May 7, 2012, the applicant stated that the only nickel alloy components 

described in LRA Table 3.1.1, item 3.1.1-97 are tubing sections within the HPCI steam supply 

flow elements. The applicant also indicated that these tubing sections are 7/8-inch outer 

diameter and are completely contained within the flow element housings. In addition, the 

applicant stated that these flow elements are within the ASME Code Class 1 section of the 

HPCI steam supply piping and the nickel alloy tubing is exposed to a reactor coolant 

environment at nominal 1,035 psig and 550 °F. The applicant stated that since the tubing is 

internal to the flow element housings, it is not a pressure-retaining component within the context 

of ASME Code, Section XI, and is not within the scope of the ASME Code Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD program. The applicant indicated that because the 

tubing sections are less than 4 NPS, these components are not included in the scope of the 

BWR Stress Corrosion Cracking program. The staff confirmed that tubing less than 4 NPS is 

not included in the scope of the BWR Stress Corrosion Cracking program. 

In its response, the applicant also indicated that its review of plant-specific operating experience 

did not identify any indication of aging (cracking or loss of material) of the nickel alloy tubing 

within the flow elements. The applicant further explained that the “detection of aging effects”

program element of GALL Report AMP XI.M32, indicates that the One-Time Inspection program

includes inspection and testing techniques that have a demonstrated history of effectiveness in 

managing aging effects including cracking and loss of material. In addition, the applicant 

indicated that its Water Chemistry and One-Time Inspection programs are consistent with GALL 

Report AMPs XI.M2 and XI.M32, respectively, as described in LRA Sections B.2.1.2 and 

B.2.1.22; therefore, the One-Time Inspection program in conjunction with the Water Chemistry 

program is adequate to manage cracking of the nickel alloy tubing sections within the HPCI 

steam supply flow elements.

The staff finds the applicant’s response acceptable because the applicant confirmed that the 

nickel alloy tubing sections are 7/8-inch outer diameter within the flow element pressure 

boundary and these components are not subject to the periodic volumetric examinations 

specified in the BWR Stress Corrosion Cracking program and ASME Code Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD program. In addition, the applicant confirmed that 

the plant-specific operating experience did not identify any indication of cracking or loss of 

material of these components, which also supports the adequacy of the applicant’s proposal to 

use the One-Time inspection program for the aging management. Therefore, the staff’s 

concern in RAI 3.1.1.97-1 is resolved.

For the AMR item that addresses stainless steel pump casing and valve bodies with generic 

note E, the LRA credits the Water Chemistry program and ASME Code Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD program to manage the aging effect of these 

components. The Water Chemistry program proposes to manage the aging of the components 

through periodic monitoring and control of the reactor coolant chemistry to mitigate 

environmental effect on SCC and IGSCC. The ASME Code Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD program includes periodic visual and volumetric examinations 

to manage aging. For example, the 2001 edition through the 2003 addenda of ASME Code,

Section XI, Subsection IWB, Table IWB-2500-1 specifies visual VT-1 examination of pump 

casing welds and visual VT-3 examination of pump casing internal surfaces. ASME Code,
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Section XI, Table IWB-2500-1 also specifies volumetric examination of valve body welds for the 

valves, NPS 4 or larger.

In its review, the staff noted that LRA Table 3.1.2-1 (LRA page 3.1-40) relates the CASS valve 

body to LRA item 3.1.1-97, indicating that this component type is subject to cracking caused by

SCC and IGSCC. The LRA also indicates that the aging effect is managed by the Water 

Chemistry program and ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD program.

As addressed above, Table IWB-2500-1 of the 2001 edition through the 2003 addenda of the 

ASME Code Section XI requires that the valve body welds of valves, NPS 4 or larger, should be 

examined using volumetric examination in accordance with Examination Category B-M-1, 

item No. B12.40. The staff further noted that Appendix VIII, Supplement 9 of the 2001 edition 

with 2002 and 2003 addenda of the ASME Code Section XI, Division 1 indicates that the 

qualification requirements for ultrasonic examination of cast austenitic piping welds are in the

course of preparation. However, the LRA does not provide the following information necessary 

to determine the inspection method in accordance with the ASME Code Section XI: (1) the size 

of the CASS valve bodies and (2) whether the valve bodies have a weld.

By letter dated April 30, 2012, the staff issued RAI 3.1.1.97-2, requesting the applicant to

provide the information to clarify the size of the CASS valve bodies and whether the valve 

bodies have a weld that requires volumetric examination. The staff also requested that if the 

valve bodies contain welds, the applicant describe the inspection method that will be used to 

detect and manage cracking in these components and justify why the inspection method is 

adequate to detect and manage cracking caused by SCC and IGSCC.

In its response, dated May 7, 2012, the applicant provided the size data for the CASS valve 

bodies and confirmed that all of the CASS valve bodies are greater than NPS 4. The applicant 

also indicated that none of these valve bodies have welds as described in ASME 

Code Section XI Table IWB-2500-1, Examination Category B-M-1 and referenced 

Figure IWB-2500-17. The applicant further indicated that since none of the CASS valve bodies 

have welds, volumetric examination per ASME Code Section XI, Table IWB-2500-1, 

Examination Category B-M-1, item No. B12.40 is not required for these valves. 

The staff finds that the applicant’s response acceptable because the applicant confirmed that all 

of these CASS valve bodies are greater than NPS 4 and none of these valve bodies have welds 

such that volumetric examination would be required in accordance with ASME Code Section XI, 

item No. B12.40. The staff also noted that ASME Code Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD program includes visual examination of the internal surfaces of 

these valve bodies as specified in item No. B12.50, which is adequate to detect and manage 

cracking of these valve bodies. The staff’s concern in RAI 3.1.1.97-2 is resolved.

The staff’s evaluations of the Water Chemistry program and One-Time Inspection program are 

documented in SER Sections 3.0.3.1.2 and 3.0.3.1.12, respectively. In its review of the nickel 

alloy tubing 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 the Water Chemistry program and 

One-Time Inspection program acceptable because the Water Chemistry program limits the 

concentrations of chemical species known to cause SCC and IGSCC and controls the dissolved 

oxygen level to minimize the environmental effect on aging, and the One-Time Inspection 

program includes a one-time inspection of selected components to confirm the effectiveness of 
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the Water Chemistry program such that it is ensured to adequately manage cracking caused by

SCC and IGSCC of these components.

In addition, the staff’s evaluation of the ASME Code Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD program is documented in SER Section 3.0.3.1.1. In its 

review of the stainless steel pump casing 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 the Water Chemistry program and ASME Code Section XI Inservice Inspection,

Subsections IWB, IWC, and IWD program acceptable because the Water Chemistry program 

limits the concentrations of chemical species known to cause SCC and IGSCC and controls the 

dissolved oxygen level to minimize the environmental effect on aging as described above, and 

the ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program 

includes visual examination of these components, which is adequate to detect and manage 

cracking caused by SCC and IGSCC of the components.

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).

3.1.2.1.7 Conclusion

The staff evaluated the GALL Report AMR items that the applicant claimed were not applicable. 

On the basis of its review, the staff concludes that the AMR results that the applicant claimed 

were not applicable are not applicable to LGS Units 1 and 2.

As discussed in SER Section 3.0.2.2, for those AMRs that the applicant claimed consistency 

with the GALL Report, the staff evaluated the applicant’s claim of consistency. The staff also 

reviewed information pertaining to the applicant’s consideration of recent operating experience 

and proposals for managing aging effects. On the basis of its review, the staff concludes that 

the AMR results, which the applicant claimed to be consistent with the GALL Report, are 

consistent.

Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their 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 evaluates aging management, as recommended by 

the GALL Report, for the reactor vessel, internals, and RCS components and provides 

information concerning how it will manage the following aging effects:

 • cumulative fatigue damage

 • loss of material caused by general, pitting, and crevice corrosion

 • loss of fracture toughness caused by neutron irradiation embrittlement

 • cracking caused by SCC and IGSCC
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 • crack growth caused by cyclic loading

 • cracking caused by SCC

 • cracking caused by cyclic loading

 • loss of material caused by erosion

 • cracking caused by SCC and irradiation-assisted SCC

 • loss of fracture toughness caused by neutron irradiation embrittlement; change in dimension 

caused by void swelling; loss of preload caused by stress relaxation; or loss of material 

caused by wear

 • cracking caused by primary water stress corrosion cracking (PWSCC)

 • cracking caused by fatigue

 • cracking caused by SCC and fatigue

 • loss of material caused by wear

 • QA for aging management of nonsafety-related components

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 

criteria contained in SRP-LR Section 3.1.2.2. The staff’s review of the applicant’s further 

evaluation follows.

3.1.2.2.1 Cumulative Fatigue Damage 

LRA Section 3.1.2.2.1 addresses the applicant’s AMR basis for managing cumulative fatigue 

damage for the RPV, RVIs, RCPB, and CRD system. The applicant stated that fatigue is a 

TLAA as defined in 10 CFR 54.3 and these TLAAs are required to be evaluated in accordance 

with 10 CFR 54.21(c). Additional information for these TLAAs is discussed in LRA Section 4.3.

The applicant identified the following items in LRA Table 3.1.1 that are applicable: 

Item 3.1.1-1 – The applicant stated that metal fatigue of steel top head closure 

studs is a TLAA addressed in LRA Section 4.3. 

Item 3.1.1-3 – The applicant stated that metal fatigue of steel, stainless steel, and 

steel with nickel-alloy reactor internal components is a TLAA addressed in LRA 

Section 4.3. 

Item 3.1.1-4 – The applicant stated that metal fatigue of steel pressure vessel 

support skirt and attachment welds is a TLAA addressed in LRA Section 4.3.

Item 3.1.1-6 – The applicant stated that metal fatigue of the stainless steel, steel 

with nickel-alloy or stainless steel cladding, and nickel-alloy RCPB piping, piping 

components, and piping elements is a TLAA addressed in LRA Section 4.3. 
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Item 3.1.1-7 – The applicant stated that metal fatigue of steel or stainless steel 

and nickel-alloy reactor vessel components is a TLAA in LRA Section 4.3. 

Item 3.1.1-11 – The applicant stated that metal fatigue of the stainless steel or 

steel pump and valve closure bolting is a TLAA addressed in LRA Section 4.3. 

The staff noted that 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 are 

specifically related to components in a PWR design; therefore, the staff finds it appropriate that 

the applicant did not address these items in the LRA.

The staff reviewed LRA Section 3.1.2.2.1 against the further evaluation criteria in SRP-LR 

Section 3.1.2.2.1, which states that fatigue is a TLAA as defined in 10 CFR 54.3, and that these 

TLAAs are to be evaluated in accordance with 10 CFR 54.21(c)(1) and SRP-LR Section 4.3. 

The staff also reviewed the AMR items associated with LRA Section 3.1.2.2.1, and found that 

the AMR results are consistent with the GALL Report and SRP-LR.

Based on its review, the staff concludes that the applicant has met the SRP-LR

Section 3.1.2.2.1 criteria. For those items that apply to LRA Section 3.1.2.2.1, the staff 

determined 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). SER Section 4.3 documents the staff’s review of the 

applicant’s evaluation of the TLAA for these components.

3.1.2.2.2 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:

(1) LRA Section 3.1.2.2.2, item 1, which is 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 components 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 confirmed that the item is applicable 

only to PWRs and noted that the applicant’s units are a BWR design and do not have 

steam generators; therefore, the staff finds it acceptable.

(2) LRA Section 3.1.2.2.2, item 2, which is 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 components 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 confirmed that the item is applicable 

only to PWRs and noted that the applicant’s units are a BWR design and do not have 

steam generators; therefore, the staff finds it acceptable.

3.1.2.2.3 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:
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(1) LRA Section 3.1.2.2.3 item 1, which is associated with LRA Table 3.1.1, item 3.1.1-13, 

states that these TLAAs are evaluated in accordance with 10 CFR 54.21(c)(1) and that 

the evaluations are addressed in LRA Section 4.2. This is consistent with SRP-LR 

Section 3.1.2.2.3 item 1 and is, therefore, acceptable. The staff’s evaluation of the 

TLAAs for all ferritic materials with neutron fluence greater than 1 x 1017 n/cm2

(E > 1 MeV) is documented in SER Section 4.2.

(2) LRA Section 3.1.2.2.3, item 2, which is associated with LRA Table 3.1.1, item 3.1.1-14, 

addresses carbon or low-alloy steel with stainless steel cladding reactor vessel beltline 

shell and welds exposed to reactor coolant and neutron flux that will be managed for 

loss of fracture toughness caused by neutron irradiation embrittlement. In LRA 

Section 3.1.2.2.3.2, the applicant credits its Reactor Vessel Surveillance program to 

manage the loss of fracture toughness of the reactor vessel beltline components and 

welds exposed to a reactor coolant and flux environment. This is an existing program 

that manages the loss of fracture toughness caused by neutron irradiation embrittlement 

of the reactor vessel beltline materials in a reactor coolant and neutron flux environment. 

The program meets the requirements of 10 CFR Part 50, Appendix H, and the Reactor 

Vessel Surveillance program is part of the BWRVIP ISP described in BWRVIP-86-A and 

BWRVIP-116. In addition, the program includes monitoring of plant operating conditions 

to ensure appropriate steps are taken if reactor vessel exposure conditions are altered,

such as the review and updating of 60-year fluence projections to support upper-shelf

energy calculations and pressure-temperature limit curves. The LRA states that the 

Reactor Vessel Surveillance program is consistent with the elements of GALL Report 

AMP XI.M31, “Reactor Vessel Surveillance.”

The criteria in SRP-LR Section 3.1.2.2.3, for item 2 states that loss of fracture toughness 

caused by neutron irradiation embrittlement could occur in BWR and PWR reactor 

vessel beltline shell, nozzle, and welds exposed to reactor coolant and neutron flux. 

The SRP-LR also states that a reactor vessel materials surveillance program monitors 

neutron irradiation embrittlement of the reactor vessel, and is plant-specific depending 

on matters such as the composition of limiting materials, availability of surveillance 

capsules, and projected fluence levels. The SRP-LR further states that specific 

recommendations for an acceptable AMP are provided in GALL Report AMP XI.M31,

“Reactor Vessel Surveillance.” 

The staff’s evaluation of the Reactor Vessel Surveillance program is documented in SER 

Section 3.0.3.1.11. In its review the staff noted that the applicant’s program addresses 

irradiation embrittlement of the RPV beltline and extended beltline materials through 

testing that monitors the properties of beltline materials. During its review the staff noted 

that the Reactor Vessel Surveillance program is consistent with GALL Report 

AMP XI.M31. Based on its review of components associated with item 3.1.1-14, the 

staff finds the applicant’s use of its Reactor Vessel Surveillance program acceptable 

because the applicant will continue to use the existing program during the period of 

extended operation, consistent with its CLB.

Based on the program identified, the staff concludes that the applicant’s program meets 

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 function(s) will remain consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).
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(3) LRA Section 3.1.2.2.3 item 3, associated with LRA Table 3.1.1, item 3.1.1-15, states that 

Ductility – Reduction in Fracture Toughness is a plant-specific TLAA for Babcock and 

Wilcox (B&W) reactor internals. The applicant stated that this item is not applicable 

because it is associated with PWRs only, specifically, B&W-designed PWRs. The staff 

confirmed that this item is associated only with B&W-designed PWRs and, therefore, 

finds the applicant’s claim acceptable.

3.1.2.2.4 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:

(1) LRA Section 3.1.2.2.4, associated with LRA Table 3.1.1, items 3.1.1-16 and 3.1.1-39, 

addresses carbon and stainless steel top head enclosure vessel flange leak detection 

lines exposed to reactor coolant, which will be managed for cracking by the ASME Code 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD; Water Chemistry; and 

One-Time Inspection of ASME Code Class 1 Small-Bore Piping programs. The criteria 

in SRP-LR Section 3.1.2.2.4, item 1, state that cracking caused by SCC and IGSCC 

could occur in stainless steel and nickel alloy BWR top head enclosure vessel flange 

leak detection lines. The SRP-LR also states that a plant-specific AMP should be 

evaluated because existing programs may not be capable of mitigating or detecting 

cracking caused by SCC or IGSCC. 

The applicant addressed the further evaluation criteria of the SRP-LR by stating that the 

top head enclosure vessel flange leak detection lines are stainless steel ASME 

Code Class 1 piping that also have the potential for cracking caused by thermal, 

mechanical, and vibratory loading mechanisms. As such, the applicant explained that 

instead of LRA Table 3.1.1, item 3.1.1-16, it used item 3.1.1-39, which credits the ASME 

Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD; Water 

Chemistry; and One-Time Inspection of ASME Code Class 1 Small-Bore Piping 

programs to manage cracking. The applicant also indicated that the stainless steel 

portions of the lines are welded to short sections of carbon steel piping, which in turn are 

welded to nozzles on each flange. Cracking of the carbon steel sections is also 

managed by these three AMPs. The applicant further stated that the Water Chemistry 

program will monitor and control water chemistry to prevent or mitigate cracking; periodic 

examinations, in accordance with the ASME Code Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD program, will identify, evaluate, and manage the 

effects of cracking; and these examinations will be supplemented by a one-time 

inspection under the One-Time Inspection of ASME Code Class 1 Small-Bore Piping 

program.

The staff’s evaluation of the ASME Code Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD; Water Chemistry; and One-Time Inspection of ASME 

Code Class 1 Small-Bore Piping programs is documented in SER Sections 3.0.3.1.1, 

3.0.3.1.2, and 3.0.3.1.14, respectively. The staff confirmed from the UFSAR that the 

carbon and stainless steel top head enclosure vessel flange leak detection lines are 

ASME Code, Class 1, and 1-inch NPS. SRP-LR Table 3.1-1 summarizes AMPs 

evaluated in the GALL Report Chapter IV for the reactor vessel, internals, and reactor 

coolant system. Item 39 in this table specifically addresses steel, stainless steel, or steel 

with stainless steel cladding ASME Code Class 1 piping, fittings, and branch 
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connections less than 4 inches NPS exposed to reactor coolant, which are subject to 

cracking caused by stress corrosion, intergranular stress corrosion (stainless steel only), 

and thermal, mechanical, and vibratory loading. The applicant’s AMR for the top head 

enclosure vessel flange leak detection lines is consistent with SRP-LR Table 3.1-1, 

item 39, because the lines are ASME Code Class 1 and less than 4 inches NPS, and 

because they are made of materials, in a service environment, and subject to the same 

aging effect as described in SRP-LR Table 3.1-1, item 39. This item credits aging 

management through GALL Report AMPs XI.M1, XI.M2, and XI.M35 and recommends 

no further evaluation. As discussed in SER Sections 3.0.3.1.1, 3.0.3.1.2, and 3.0.3.1.14, 

the staff determined that the applicant’s AMPs are each consistent with the 

corresponding GALL Report programs. Specifically, the ASME Code Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD program is consistent with GALL 

Report AMP XI.M1, the Water Chemistry program is consistent with GALL Report 

AMP XI.M2, and the One-Time Inspection of ASME Code Class 1 Small-Bore Piping 

program is consistent with GALL Report AMP XI.M35. As such, the applicant’s use of 

SRP-LR Table 3.1-1, item 39, is consistent with the GALL Report.

In its review of components associated with LRA Table 3.1.1, items 3.1.1-16 and 

3.1.1-39, the staff finds that the applicant has met the further evaluation criteria, and the 

applicant’s proposal to manage cracking using the ASME Code Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD; Water Chemistry; and One-Time 

Inspection of ASME Code Class 1 Small-Bore Piping programs is acceptable because 

these programs will mitigate and detect cracking caused by SCC and IGSCC. The 

Water Chemistry program will mitigate cracking through the control of water chemistry. 

The ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

program will detect cracking through periodic visual examinations conducted during 

system leakage tests, as per ASME Code, Section XI, Table IWB-2500-1, Examination 

Category B-P, “All Pressure Retaining Components.” In addition, cracking will be 

detected through the volumetric or destructive examinations implemented in accordance 

with the One-Time Inspection of ASME Code Class 1 Small-Bore Piping program. This 

approach is consistent with SRP-LR Table 3.1-1, item 39.

In addition, the staff notes that, under the applicant’s current ISI program, the visual 

examinations during system leakage tests are conducted at reduced pressure before

reactor cavity draining during each refueling outage. Performance of the examinations 

in this manner is by an NRC-approved relief request; however, this request is only valid 

for the third ISI interval. Therefore, the future use of this approach to manage aging in 

subsequent ISI intervals, which encompass the period of extended operation, will require 

subsequent NRC approval. If such a request is not approved for any subsequent 

inservice inspection interval, then the visual examinations must be performed at normal 

pressure, as required by 10 CFR 50.55a and ASME Code Section XI. 

Based on the programs identified, the staff determines that the applicant’s programs 

meet SRP-LR Section 3.1.2.2.4, item 1, criteria. For those items associated with LRA 

Section 3.1.2.2.4, item 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 function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

(2) LRA Section 3.1.2.2.4.2, 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 its 
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design does not use an isolation condenser. The staff reviewed the Units 1 and 2 

UFSAR and confirmed that the design of the applicant’s units does not include an 

isolation condenser; therefore, the staff finds the applicant’s review result acceptable.

3.1.2.2.5 Crack Growth Caused by Cyclic Loading 

LRA Section 3.1.2.2.5 refers to Table 3.1.1, item 3.1.1-18, and addresses crack growth caused 

by cyclic loading. The applicant stated that this aging effect is not applicable to LGS, which is a 

BWR. 

SRP-LR Section 3.1.2.2.5 states that crack growth caused by cyclic loading could occur in 

reactor vessel shell forgings clad with stainless steel using a high-heat-input welding process. 

SRP-LR Table 3.1-1 identifies item 18 as applicable to PWRs. The staff confirmed that SRP-LR 

Section 3.1.2.2.5 is not applicable to LGS because it is a BWR, and the staff guidance in this 

SRP-LR section is only applicable to PWR-designed reactor vessel shells fabricated of 

SA508-CI forgings clad with stainless steel using a high-heat-input welding process.

Based on the information above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.1.2.2.5 do not apply to LGS Units 1 and 2 because the guidance is applicable to 

PWRs.

3.1.2.2.6 Cracking Caused by 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.

(1) LRA Section 3.1.2.2.6, item 1, which is 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 stated that this item is not applicable because the associated item in LRA 

Table 3.1.1 is applicable to PWRs only. The staff confirmed that this item is associated 

only with PWRs and, therefore, finds the applicant’s claim acceptable.

(2) LRA Section 3.1.2.2.6, item 2, which is associated with LRA Table 3.1.1, item 3.1.1-20, 

addresses cracking caused by SCC in Class 1 PWR CASS reactor coolant system 

piping, piping components, and piping elements. 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 confirmed that this item is associated only with PWRs and, therefore, 

finds the applicant’s claim acceptable.

Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.6 criteria do not apply.

3.1.2.2.7 Cracking Caused by 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 caused by 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 

its design does not use an isolation condenser. The staff reviewed the LGS Units 1 and 2 

UFSAR and confirmed that its designs do not include an isolation condenser; therefore, the staff 

finds the applicant’s review result acceptable.
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3.1.2.2.8 Loss of Material Caused by Erosion

LRA Section 3.1.2.2.8, which is associated with LRA Table 3.1.1, item 3.1.1-22, addresses loss 

of material caused by erosion in PWR 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 

confirmed that this item is associated only with PWRs and, therefore, finds the applicant’s claim 

acceptable.

3.1.2.2.9 Cracking Caused by Stress Corrosion Cracking and Irradiation-Assisted Stress 

Corrosion Cracking

LRA Section 3.1.2.2.9, which is associated with LRA Table 3.1.1, item 3.1.1-23, addresses 

cracking caused by SCC, and irradiation-assisted SCC could occur in inaccessible locations for

stainless steel and nickel-alloy primary and expansion PWR reactor vessel internal 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. The staff confirmed that this item is associated only 

with PWRs and, therefore, finds the applicant’s claim acceptable.

3.1.2.2.10 Loss of Fracture Toughness Caused by Neutron Irradiation Embrittlement, Change 

in Dimension Because of Void Swelling, Loss of Preload Because of Stress Relaxation, or Loss 

of Material Because of Wear

LRA Section 3.1.2.2.10, which is associated with LRA Table 3.1.1, item 3.1.1-24, addresses 

loss of fracture toughness caused by neutron irradiation embrittlement, change in dimension 

caused by void swelling, loss of preload caused by stress relaxation, or loss of material caused 

by wear, which could occur in inaccessible locations for stainless steel and nickel-alloy primary 

and expansion PWR reactor vessel internal 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. The 

staff confirmed that this item is associated only with PWRs and, therefore, finds the applicant’s 

claim acceptable.

3.1.2.2.11 Cracking Caused by 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.

(1) LRA Section 3.1.2.2.11, item 1, which is associated with LRA Table 3.1.1, item 3.1.1-25, 

addresses foreign operating experience in steam generators with a similar design to that 

of Westinghouse Model 51 which has identified extensive cracking caused by PWSCC in 

steam generator divider plate assemblies fabricated of Alloy 600 and/or the associated 

Alloy 600 weld materials, even with proper primary water chemistry (EPRI TR-1014982). 

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 confirmed that this item is associated 

only with PWRs and, therefore, finds the applicant’s claim acceptable.

(2) LRA Section 3.1.2.2.11, item 2, which is associated with LRA Table 3.1.1, item 3.1.1-25, 

addresses cracking caused by PWSCC that could occur in steam generator nickel alloy 

tube-to-tube sheet welds exposed to reactor coolant. The applicant stated that this 

item is not applicable because the associated item in LRA Table 3.1.1 is applicable to 
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PWRs only. The staff confirmed that this item is associated only with PWRs and, 

therefore, finds the applicant’s claim acceptable.

Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.11 criteria do not apply.

3.1.2.2.12 Cracking Caused by Fatigue

LRA Section 3.1.2.2.12, which is associated with LRA Table 3.1.1, item 3.1.1-26, addresses 

cracking caused by fatigue as an aging effect that can occur for the lower flange weld in the 

core support barrel assembly, fuel alignment plate in the upper internals assembly, and core 

support plate lower support structure in PWR internals designed by Combustion Engineering. 

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 confirmed that this item is associated only 

with PWRs and, therefore, finds the applicant’s claim acceptable.

3.1.2.2.13 Cracking Caused by Stress Corrosion Cracking and Fatigue

LRA Section 3.1.2.2.13, which is associated with LRA Table 3.1.1, item 3.1.1-27, addresses 

cracking caused by SCC and fatigue that could occur in nickel alloy control rod guide tube 

assemblies, guide tube support pins exposed to reactor coolant, and neutron flux. 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 confirmed that this item is associated only with PWRs 

and, therefore, finds the applicant’s claim acceptable.

3.1.2.2.14 Loss of Material Because of Wear

LRA Section 3.1.2.2.14, associated with LRA Table 3.1.1, item 3.1.1-28, addresses loss of 

material caused by wear in nickel alloy control rod guide tube assemblies, guide tube support 

pins, and Zircaloy-4 in-core instrumentation lower thimble tubes exposed to reactor coolant and 

neutron flux. The applicant stated that this item is not applicable because it is associated with 

PWRs only. The staff confirmed that this item is associated only with PWRs and, therefore, 

finds the applicant’s claim acceptable.

3.1.2.2.15 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.

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 not consistent with or not addressed 

in the GALL Report.

In LRA Tables 3.1.2-1 through 3.1.2-3, the applicant, via notes F through J, indicated 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 
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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.

3.1.2.3.1 Reactor Coolant Pressure Boundary – 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 

RCPB component groups.

In LRA Table 3.1.2-1, the applicant stated that CASS main steam flow elements exposed to 

steam is being managed for loss of material by a TLAA. The AMR item cites generic note H, 

which indicates that the aging effect is not addressed in the GALL Report for this component, 

material, and environment combination. TLAAs are evaluated in accordance with 

10 CFR 54.21(c)(1), and the staff’s evaluation of the TLAA for this item is documented in SER 

Section 4.6.4.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.1.2.3.2 Reactor Pressure 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 

RPV component groups.

In LRA Table 3.1.2-2, the applicant stated that for low-alloy steel and carbon or low-alloy steel 

with stainless steel cladding RPV components exposed to uncontrolled indoor air there is no 

aging effect and no AMP is proposed. The AMR items cite generic note H. Items associated 

with RPV components and generic note H cite plant-specific note 2, which states that the 

components have external temperatures greater than 212 °F and, therefore, are not exposed to 

wetting caused by condensation and moisture accumulation.

The staff reviewed the associated items in the LRA to confirm that no credible aging effects are 

applicable for this component, material, and environment combination. The staff noted that 

moisture accumulation is not expected to occur on components with temperatures above the 

atmospheric dew point, which is necessarily less than the boiling point of water, 212 °F. The 

staff finds the applicant’s proposal acceptable based on its review of ASM Handbook, 

Volume 13A, 2003, “Atmospheric Corrosion,” which states that the atmospheric corrosion 

reaction will not occur without the presence of an electrolyte (i.e., moisture). 
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In LRA Table 3.1.2-2, the applicant stated that the N16 nozzles exposed to reactor coolant and 

neutron flux are being managed for loss of fracture toughness by a TLAA. The AMR item cites 

generic note H, which indicates that the aging effect is not addressed in the GALL Report for 

this component, material, and environment combination. TLAAs are evaluated in accordance 

with 10 CFR 54.21(c)(1), and the staff’s evaluation of the TLAA for this item would have been 

documented in SER Section 4.2.2, but because the N16 nozzles and the associated welds are 

made from austenitic material (nickel alloy 600), no significant loss of fracture toughness is 

expected.

In LRA Table 3.1.2-2, the applicant stated that the nickel alloy reactor vessel internal 

attachments exposed to reactor coolant will be managed for loss of material by the BWR Vessel 

ID Attachment Welds. The AMR item cite generic note H. Items associated with nickel alloy 

reactor vessel internal attachments in Table 3.1.2-2 cite plant-specific note 5, which states that 

loss of material caused by wear is applicable to the steam dryer support brackets as identified 

by operating experience review. 

The staff noted that this material and environment combination is identified in the GALL Report, 

which addresses nickel alloy reactor vessel internal attachments exposed to reactor coolant and 

recommends One-Time Inspection and Water Chemistry programs to manage loss of material; 

however, the applicant has also identified BWR Vessel ID Attachment Welds program to 

manage loss of material. The applicant addressed the GALL Report identified aging effects for 

this component, material and environment combination in AMR items in LRA Table 3.1.2-2.

The staff’s evaluation of the BWR Vessel ID Attachment Welds program is documented in SER 

Section 3.0.3.1.4. The staff noted that the program includes inspections of reactor vessel 

internal attachments in accordance with ASME Code, Section XI, Subsection IWB, Examination 

Category B-N-2, which allows the use of visual VT-3 examination to determine the general 

mechanical and structural condition of the component, consistent with the GALL Report. During 

its review, the staff noted that loss of material is not explicitly addressed in GALL Report 

AMP XI.M4 or BWRVIP-48-A; therefore, it was not clear to the staff whether the VT-3 inspection 

is an appropriate and effective inspection method to identify loss of material of the steam dryer 

support brackets. By letter dated November 18, 2011, the staff issued RAI B.2.1.4-1 requesting 

the applicant justify that the VT-3 inspection is an appropriate and effective inspection method to 

identify loss of material caused by wear for the steam dryer support brackets. In its response 

dated December 7, 2011, the applicant explained that BWRVIP48-A refers to ASME 

Code Section XI, Subsection IWB-3520 for acceptance criteria and corrective actions for wear 

are in accordance with ASME Code Section XI, Subsection IWB-3140. The staff’s review of the 

applicant’s response to RAI B.2.1.4-1 is documented in SER Section 3.0.3.1.4. 

The staff finds the applicant’s proposal to manage aging using the BWR Vessel ID Attachment 

Welds program acceptable because the program includes augmented inspections with a 

demonstrated capability of detecting loss of material and establishes acceptance criteria and 

corrective actions consistent with ASME Code, Section XI, which implement measures to 

mitigate or prevent the aging effect caused by loss of material. In addition, the staff finds the 

applicant’s use of this program conservative because it is being credited to manage loss of 

material in addition to the GALL Report recommendations.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 
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Report. The staff finds 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).

3.1.2.3.3 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 

RVI component groups.

In LRA Table 3.1.2-3, the applicant stated that there is a TLAA for stainless steel core plate 

bolts exposed to reactor coolant and neutron flux, which cite generic note H. The staff 

confirmed that there is a TLAA, as documented in LRA Section 4.6.3, for this component and 

material. The staff’s evaluation of the TLAA for the core plate bolts is documented in SER 

Section 4.6.3.

In LRA Table 3.1.2-3, the applicant stated that Alloy X-750 jet pump assemblies: thermal sleeve 

inlet header, riser brace arm, holddown beams, inlet elbow, mixing assembly, diffuser castings, 

slip joint clamp, and wedge assemblies 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. 

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 LRA, which states that the 

components are also being managed for cracking, cumulative fatigue damage, loss of fracture 

toughness, and loss of preload, BWRVIP-41, Revision 2, and 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 BWR Vessel Internals program is documented in SER 

Section 3.0.3.2.2. The staff noted that high-strength, Alloy X-750 material is used to minimize 

the effects of wear, but cannot prevent wear from occurring in the jet pump wedge assemblies 

caused by excessive vibration that is sometimes present in the assemblies. The staff also 

noted that the GALL Report recommends that stainless steel and nickel alloy jet jump 

components (GALL AMR item IV.B1.RP-377) exposed to reactor coolant be managed for loss of 

material caused by wear with the BWR Vessel Internals program; the irradiation effect of the 

neutron flux does not influence the loss of material caused by wear so that this item is 

essentially the same as the GALL Report item. 

The staff finds the applicant’s proposal to manage aging using the BWR Vessel Internals 

program acceptable because the VT-1 visual inspections described in BWRVIP-41 are capable 

of resolving the evidence for mechanical wear of the components and the BWRVIP-41 report 

recommends frequent inspections that are able to monitor the performance of the jet pump. In 

addition, the GALL Report includes the same program to manage loss of material caused by

wear for stainless steel and nickel alloy jet pump components in a similar environment.

In LRA Table 3.1.2 3, the applicant stated that loss of preload due to stress relaxation and 

irradiation-assisted creep is an applicable aging effect for the following jet pump assembly 

components that are exposed to a reactor coolant and neutron flux environment: (a) jet pump 
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auxiliary spring wedge assemblies, which are wedged mechanical connections made of Inconel 

X-750, (b) jet pump restrainer bracket pad repair clamps, which are bolted/screwed mechanical 

connections made of Type 304 austenitic stainless steel, and (c) jet pump assembly inlet-mixer 

to diffuser slip joint clamps, which are bolted/screwed mechanical connections made of Inconel 

X-750 materials. For these components, the applicant cited generic note H and stated that it 

evaluated the loss of preload as TLAAs in LRA Section 4.6. As part of the TLAA evaluation for 

the jet pump restrainer bracket pad repair clamps, the LRA also credits the BWR Vessel 

Internals Program for managing loss of preload. However, in its January 24, 2012, response to 

RAI 4.6.9 1, the applicant revised the AMR item for the jet pump restrainer bracket pad repair 

clamps. Instead of managing the aging effect under the BWR Vessel Internals Program, the 

applicant stated that it re-evaluated the TLAA to show that the existing design analysis will 

remain valid through the period of extended operation; thus, no AMP is credited for acceptance 

of the TLAA in accordance with the 10 CFR 54.21(c)(1) criteria.

The staff verified that the information provided by the applicant is consistent with the design 

basis information for the jet pump assembly components in UFSAR Section 4.5.2. The staff 

also confirmed that LRA Section 4.6 includes the applicable TLAAs for the jet pump auxiliary 

spring wedge assembly, jet pump restrainer bracket pad repair clamps, and jet pump assembly 

inlet-mixer to diffuser slip joint clamps, as documented in LRA Sections 4.6.5, 4.6.6, and 4.6.9, 

respectively. The staff’s evaluations of the TLAAs for these components are documented in 

SER Sections 4.6.5, 4.6.6, and 4.6.9, respectively. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

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 RCS components within the scope of 

license renewal and subject to an AMR will be adequately managed so that the intended 

functions will remain 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 SER section documents the staff’s review of the applicant’s AMR results for the engineered 

safety features systems components and component groups of:

 • containment atmosphere control

 • CS

 • HPCI

 • reactor core isolation cooling 

 • RHR

 • standby gas treatment
3-230

3.2.1 Summary of Technical Information in the Application 

LRA Section 3.2 provides AMR results for the ESF systems components and component 

groups. LRA Table 3.2.1, “Summary of Aging Management Programs for Engineered Safety 

Features Evaluated in Chapter V of NUREG-1801,” is a summary comparison of the applicant’s 

AMRs with those evaluated in the GALL Report for the ESF systems 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.

3.2.2 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 AMRs to ensure the applicant’s claim that certain AMRs are 

consistent with the GALL Report. 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 was 

applicable and that the applicant identified the appropriate GALL Report AMRs. The staff’s 

evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff’s evaluation 

are documented in SER Section 3.2.2.1.

During its review, the staff also selected AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

were consistent with the SRP-LR Section 3.2.2.2 acceptance criteria. The staff’s evaluations 

are documented in SER Section 3.2.2.2.

The staff also conducted a technical review of the remaining AMRs not consistent with or not 

addressed in the GALL Report. The technical review evaluated whether all plausible aging 

effects have been identified and whether the aging effects listed were appropriate for the 

material-environment combinations specified. The staff’s evaluations are documented in SER 

Section 3.2.2.3.

For SSCs the applicant claimed were not applicable or required no aging management, the staff 

reviewed the AMR items and the plant’s operating experience to verify the applicant’s claims.

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.
3-231

Table 3.2-1 Staff Evaluation for Engineered Safety Features Systems Components in the 

GALL Report

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

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 

caused by

fatigue

Fatigue is a 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 

caused by

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 NA Not applicable to 

BWRs (see SER 

Section 3.2.2.2.2) 

Stainless steel 

partially-encased 

tanks with breached 

moisture barrier 

exposed to raw water 

(3.2.1-3)

Loss of material 

caused by 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 caused by

cracking of the 

perimeter seal from 

weathering.

Yes NA Not applicable to 

BWRs (see SER 

Section

3.2.2.2.3(1))

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

air-outdoor (3.2.1-4)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes NA Not applicable to 

LGS (see SER 

Section

3.2.2.2.3(2))
3-232

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel orifice 

(miniflow 

recirculation) 

exposed to treated 

water (borated) 

(3.2.1-5)

Loss of material 

caused by

erosion

A plant-specific aging 

management 

program is to be 

evaluated for erosion 

of the orifice caused 

by extended use of 

the centrifugal HPSI 

pump for normal 

charging. See LER 

50-275/94-023 for 

evidence of erosion.

Yes NA 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 

caused by

general 

corrosion; 

fouling that 

leads to 

corrosion

A plant-specific aging 

management 

program is to be 

evaluated

Yes NA Not applicable to 

LGS (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 caused 

by stress 

corrosion 

cracking

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes NA Not applicable to 

LGS (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 

caused by boric 

acid corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No NA Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Steel external 

surfaces, bolting 

exposed to air with 

borated water 

leakage (3.2.1-9)

Loss of material 

caused by boric 

acid corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No NA Not applicable to 

BWRs (see SER 

Section 3.2.1.1)

CASS 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 

caused by

thermal aging 

embrittlement

Chapter XI.M12, 

“Thermal Aging 

Embrittlement of 

Cast Austenitic 

Stainless Steel 

(CASS)”

No NA Not applicable to 

LGS (see SER 

Section 3.2.2.1.1)
3-233

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

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, 

treated water 

(3.2.1-11)

Wall thinning 

caused by

flow-accelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No 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 caused 

by cyclic 

loading, stress 

corrosion 

cracking

Chapter XI.M18, 

“Bolting Integrity”

No NA Not applicable to 

LGS (see SER 

Section 3.2.2.1.1)

Steel; stainless steel 

bolting, closure 

bolting exposed to 

air-outdoor 

(external), air-indoor, 

uncontrolled 

(external) (3.2.1-13)

Loss of material 

caused by

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 

caused by

general 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No NA 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 

caused by

thermal effects, 

gasket creep, 

and 

self-loosening

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

(see SER 

Section 3.2.2.1)

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 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry, 

One-Time 

Inspection, and 

Bolting Integrity

Consistent with the 

GALL Report

(see SER 

Section 3.2.2.1.2)

Aluminum, stainless 

steel piping, piping 

components, and 

piping elements 

exposed to treated 

water (3.2.1-17)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry, 

One-Time 

Inspection, and 

Bolting Integrity

Consistent with the 

GALL Report

(see SER 

Section 3.2.2.1.3)
3-234

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel 

containment isolation 

piping and 

components (internal 

surfaces) exposed to 

treated water 

(3.2.1-18)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time

Inspection”

No NA See SER 

Section 3.2.2.1.1

Stainless steel heat 

exchanger tubes 

exposed to treated 

water (3.2.1-19)

Reduction of 

heat transfer 

caused by

fouling

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

and One-Time 

Inspection

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 caused 

by stress 

corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry”

No NA 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 caused 

by stress 

corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry”

No NA 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 

caused by pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry”

No NA Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Steel heat exchanger 

components, 

containment isolation 

piping and 

components (internal 

surfaces) exposed to 

raw water (3.2.1-23)

Loss of material 

caused by

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

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw water 

(3.2.1-24)

Loss of material 

caused by

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No NA Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1)
3-235

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel heat 

exchanger 

components, 

containment isolation 

piping and 

components (internal 

surfaces) exposed to 

raw water (3.2.1-25)

Loss of material 

caused by

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 and RG 

1.127,

“Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants”

Consistent with the 

GALL Report

(see SER 

Section 3.2.2.1.4)

Stainless steel heat 

exchanger tubes 

exposed to raw water 

(3.2.1-26)

Reduction of 

heat transfer 

caused by

fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No NA 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 

caused by

fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No NA See SER 

Section 3.2.2.1.1

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water >60 °C 

(>140 °F) (3.2.1-28)

Cracking caused 

by stress 

corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (see SER 

Section 3.2.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water (3.2.1-29)

Loss of material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (see SER 

Section 3.2.2.1.1)

Steel heat exchanger 

components exposed 

to closed-cycle 

cooling water 

(3.2.1-30)

Loss of material 

caused by

general, pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (see SER 

Section 3.2.2.1.1)

Stainless steel heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water (3.2.1-31)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (see SER 

Section 3.2.2.1.1)
3-236

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Copper alloy heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water (3.2.1-32)

Loss of material 

caused by

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (see SER 

Section 3.2.2.1.1)

Copper alloy, 

stainless steel heat 

exchanger tubes 

exposed to 

closed-cycle cooling 

water (3.2.1-33)

Reduction of 

heat transfer 

caused by

fouling

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (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 closed-cycle 

cooling water 

(3.2.1-34)

Loss of material 

caused by

selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No NA Not applicable to 

LGS (see SER 

Section 3.2.2.1.1)

Gray cast iron motor 

cooler exposed to 

treated water 

(3.2.1-35)

Loss of material 

caused by

selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Selective 

Leaching

Consistent with the 

GALL Report

Gray cast iron piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water (3.2.1-36)

Loss of material 

caused by

selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No NA 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 

caused by

selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No NA Not applicable to 

LGS (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 

caused by

elastomer 

degradation

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces of 

Mechanical 

Components

Consistent with the 

GALL Report

Steel containment 

isolation piping and 

components 

(external surfaces) 

exposed to 

condensation 

(external) (3.2.1-39)

Loss of material 

caused by

general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No NA Not applicable to 

LGS (see SER 

Section 3.2.2.1.1)
3-237

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

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 

caused by

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 

caused by

general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No NA Not applicable to 

LGS (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 

caused by pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No NA Not applicable to 

LGS (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 

caused by

elastomer 

degradation

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No NA 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 

caused by

general 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No NA See SER 

Section 3.2.2.1.1

Steel encapsulation 

components exposed 

to air-indoor, 

uncontrolled 

(internal) (3.2.1-45)

Loss of material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No NA 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 

caused by

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
3-238

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

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 

caused by

general, pitting, 

crevice, and 

boric acid 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No NA 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 

caused by 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 

caused by

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 

caused by 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 

caused by

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 

caused by

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No NA Not applicable to 

LGS (see SER 

Section 3.2.2.1.1)

stainless steel piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.2.1-53)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No NA Not applicable to 

LGS (see SER 

Section 3.2.2.1.1)
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Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel; stainless steel 

underground piping, 

piping components, 

and piping elements 

exposed to 

air-indoor,

uncontrolled or 

condensation 

(external) (3.2.1-53x)

Loss of material 

caused by

general (steel 

only), pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No NA Not applicable to 

LGS (see SER 

Section 3.2.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water >60 °C 

(>140 °F) (3.2.1-54)

Cracking caused 

by 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 Code 

Section XI 

Inservice

Inspection, 

Subsections 

IWB, IWC, and 

IWD

Consistent with the 

GALL Report

(see SER 

Section 3.2.2.1.5)

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.

NA Not applicable to 

LGS (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

NA 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

NA Consistent with the 

GALL Report
3-240

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

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 (3.2.1-58)

None None NA – No 

AEM or 

AMP

NA 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

NA Not applicable to 

LGS

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

NA 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

NA Not applicable to 

LGS (see SER 

Section 3.2.2.1.1)

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

NA Not applicable to 

LGS (see SER 

Section 3.2.2.1.1)
3-241

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

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 

(external), air with 

borated water 

leakage, concrete, 

gas, air-indoor, 

uncontrolled 

(internal) (3.2.1-63)

None None NA – No 

AEM or 

AMP

NA 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

NA Not applicable to 

LGS (see SER 

Section 3.2.2.1.1)

The staff’s review of the ESF systems component groups followed any one of several 

approaches. One approach, documented in SER Section 3.2.2.1, reviewed AMR results for 

components that the applicant indicated are consistent with the GALL Report and require no 

further evaluation. Another approach, documented in SER Section 3.2.2.2, reviewed AMR 

results for components that the applicant indicated are consistent with the GALL Report and for 

which further evaluation is recommended. A third approach, documented in SER 

Section 3.2.2.3, reviewed AMR results for components that the applicant indicated are not 

consistent with, or not addressed in, the GALL Report. The staff’s review of AMPs credited to 

manage or monitor aging effects of the ESF systems components is documented in SER 

Section 3.0.3.

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

 • 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

 • TLAA

 • Water Chemistry
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LRA Tables 3.2.2-1 through 3.2.2-6 summarize AMRs for the ESF systems components and 

indicate AMRs claimed to be consistent with the GALL Report.

The staff audited and reviewed the information in the LRA. 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 was applicable and that the applicant identified the appropriate GALL 

Report AMRs. The staff’s evaluation follows.

LRA Table 3.2.1, item 3.2.1-15 addresses copper alloy, nickel alloy, steel, and stainless steel 

bolting and closure bolting exposed to any environment, including air-outdoor (external), raw 

water, treated borated water, fuel oil, treated water, and air-indoor, uncontrolled (external) which 

will be managed for loss of preload caused by thermal effects, gasket creep, and self-loosening. 

During its review of carbon steel, low-alloy steel, and stainless steel bolting exposed to treated 

water (external) and stainless steel bolting exposed to raw water (external) associated with 

item 3.2.1-15 for which the applicant cited generic note A, the staff noted that LRA 

Section B.2.1.11, Bolting Integrity states that, “Inspection activities for bolting in a submerged 

environment are performed in conjunction with associated component maintenance activities.” 

It is not clear to the staff how the submerged bolted connections will be inspected and how often 

inspections will occur. By letter dated February 14, 2012, the staff issued RAI 3.2.2.1.1-1 

requesting the applicant to state the parameters that will be inspected for during opportunistic 

inspections of normally submerged bolting and the basis for why these parameters will be 

capable of assessing the condition of the bolting before loss of intended function occurs, and 

the minimum number of inspections that will be conducted during the period of extended 

operation.

In its response dated March 13, 2012, the applicant stated that the submerged bolts in the CS

system, HPCI system, reactor core isolation cooling system, and RHR system are visually 

inspected for loss of material and loss of preload at least once every 10-year ISI inspection 

interval. The applicant also stated that the submerged bolts in the condenser and air removal 

system are visually inspected for loss of material and loss of preload whenever the expansion 

joint is replaced, which is planned on a 12-year frequency. The applicant further stated that the 

submerged bolts in the fuel pool cooling and cleanup system, and the circulating water system 

are visually inspected for loss of material and loss of preload when the fuel pool weir plates are 

adjusted and when the circulating water screens are removed, which normally occurs during 

refueling outages. The applicant stated that in each application, the bolting is not high strength. 

The visual inspection checks for degradation including corrosion and missing or loose parts.

The staff finds the applicant’s response acceptable because the visual inspection techniques 

will be able to identify loss of material and loss of preload aging effects that enables assessment 

of the condition of the bolting before loss of intended function occurs; set inspection frequencies 

provide opportunities to inspect the components for aging; the applicant’s program follows 

recommended industry bolting techniques including design, torqueing, gasket compression, and 

lubrication, which helps to maintain preload and the possibility of lubrication-related corrosion; 

the condenser and air removal system is continuously monitored for system pressure; and the 

applicant’s CAP would provide additional opportunistic inspection opportunities for components. 

The staff’s concern described in RAI 3.2.2.1.1-1 is resolved.

The staff concludes that for LRA item 3.2.1-15, 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).

LRA AMR Tables 3.2.2-3 and 3.2.2-4 list gray cast iron turbine lube oil reservoirs exposed 

internally to lube oil; however, selective leaching is not considered to be an aging effect. The 

applicant proposes to manage aging of these components with the Lubricating Oil Analysis and 

One-Time Inspection programs.

According to the LRA, the Lubricating Oil Analysis program directs the condition monitoring 

activities (sampling, analyses, and trending) to manage loss of material and reduction of heat 

transfer in piping, piping components, piping elements, heat exchangers, and tanks. The 

One-Time Inspection program provides inspections focusing on locations that are isolated from 

the flow stream, that are stagnant, or have low flow for extended periods and are susceptible to 

the gradual accumulation or concentration of agents that promote certain aging effects. The 

inspections will include a representative sample of the system population and will focus on the 

bounding or lead components most susceptible to aging caused by time in service, and severity 

of operating conditions.

Selective leaching is known to occur in susceptible materials such as gray cast iron and 

uninhibited brasses with greater than 15-percent zinc when an electrolyte is present. Based on 

the information provided in the LRA, the staff was unable to determine whether susceptible 

locations will be included in the sample for inspection. Moreover, visual inspections alone may 

not be sufficient to detect selective leaching. Therefore, by letter dated February 14, 2012, the 

staff issued RAI 3.2.2.1.1-2, requesting the applicant to explain if the inspection samples will 

include susceptible locations to confirm that selective leaching does not occur in areas where 

water can accumulate. If it is determined that selective leaching is a relevant aging effect or 

mechanism to be managed, the applicant was requested to explain which program and 

inspection method(s) will be used to manage the loss of material caused by selective leaching.

In its response, dated March 13, 2012, the applicant stated that Lubricating Oil Analysis

program checks for water and particulates to detect evidence of contamination by moisture or 

excessive corrosion. It also cited element 6 of GALL Report AMP XI.M39 which states 

“phase-separated water in any amount is not acceptable.” 

The applicant concluded that the lack of water in the oil precludes the existence of an electrolyte 

in this environment, and the aging mechanism of selective leaching is not applicable. The 

applicant also stated that the HPCI and RCIC turbine lube oil reservoirs have not exhibited 

degradation caused by water pooling, and that both the HPCI and RCIC turbine lube oil 

reservoirs are sampled quarterly for water and are drained, cleaned, and inspected every 

2 years. Lastly, the applicant stated that the efficacy of the Lube Oil Analysis program at 

minimizing the potential for water pooling is confirmed through the implementation of the 

One-Time Inspection program, which confirms the absence of corrosion in material subject to 

lube oil.

The staff finds the applicant’s response acceptable because the Lubricating Oil Analysis 

program checks for the presence of water, and on a quarterly basis, it samples the turbine lube 

oil reservoirs for water, and every 2 years, the reservoirs are drained, cleaned, and inspected. 

These actions will timely detect and potentially prevent the accumulation of any water, which 

could lead to a loss of material. In addition, the effectiveness of the Lubricating Oil Analysis 
3-244

program is confirmed by the One-Time Inspection program. The staff’s concern described in 

RAI 3.2.2.1.1-2 is resolved. 

3.2.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.2.1 items 3.3.2.1-10, 3.3.2.1-28 through 3.2.1.34, 3.2.1.37, 3.2.1-39, 3.2.1-41, 

3.2.1-42, 3.2.1-52, 3.2.1-53, 3.2.1-53x, 3.2.1.55, 3.2.1.59, 3.2.1-61, 3.2.1-62, and 3.2.1.64, the 

applicant claimed that they were not applicable. The staff reviewed the LRA and UFSAR and 

confirmed that the applicant’s LRA does not have any AMR results that are applicable for these 

items.

For LRA Table 3.2.1 items 3.2.1-8, 3.2.1-9, 3.2.1-20, 3.2.1-21, 3.2.1-22, 3.2.1-24, 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 these items only apply to PWRs, and finds these 

items are not applicable to LGS.

LRA Table 3.2.1, item 3.2.1-12 addresses steel high-strength closure bolting exposed to air with 

steam or water leakage. The GALL Report recommends GALL Report AMP XI.M18 “Bolting 

Integrity” to manage cracking caused by cyclic loading and stress corrosion cracking for this 

component group. The applicant stated that this item is not applicable because there is no steel 

high-strength bolting exposed to air with steam or water leakage in the engineered safety 

feature systems. The staff evaluated the applicant’s claim and finds it acceptable because:

 • The UFSAR states that ASTM A-193 fasteners were used in the engineered safety features 

systems. The minimum tensile specification for A-193 fasteners is 120 ksi. RG 1.65, issued 

April 2010, states that a design conservative value of 150 ksi yield strength should be used 

to ensure that studs are relatively immune to stress corrosion cracking. Given that there is a 

30 ksi margin between the minimum tensile specification and the threshold for SCC, it is 

reasonable to conclude that LGS Units 1 and 2 do not have any high-strength fasteners.

 • LRA Section 4.3.2 states that for the ESF systems, the cyclic loading was based on stress 

 range reduction factor methodology. The TLAA evaluation states that the 60-year cycle 

 projections demonstrate that the total number of thermal and pressure cycles of all of the 

 transient types added together will not exceed 7,000 cycles during the period of extended 

 operation. Therefore, it is reasonable to conclude that cracking caused by cyclic loading 

 does not need to be managed for aging.

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 caused by 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 engineered safety features systems. The staff evaluated the 

applicant’s claim and found it acceptable because all ESF system bolting exposed to air is being 

managed for loss of material by the Bolting Integrity program citing item 3.2.1-13, or the 

External Surfaces Monitoring of Mechanical Components program citing item 3.2.1-40. Both of 

these programs conduct periodic visual inspections capable of detecting loss of material caused 

by general corrosion in bolting, and use of these programs is consistent with the GALL Report.
3-245

LRA Table 3.2.1, item 3.2.1-18 addresses the internal surfaces of stainless steel containment 

isolation piping and components exposed to treated water. The GALL Report recommends 

GALL Report AMPs XI.M2, “Water Chemistry” and XI.M32, “One-Time Inspection” to manage 

loss of material caused by pitting and crevice corrosion for this component group. The applicant 

stated that this item is not applicable because there are no stainless steel containment isolation 

piping and components exposed to treated water in the ESF systems. The staff evaluated the 

applicant’s claim and found it acceptable because, as stated in LRA Section 2.3.2.2, the 

containment isolation piping and components are evaluated in the RCPB systems and are not 

included in the ESF system. The staff confirmed that stainless steel piping exposed to treated 

water that are managed for loss of material in the RCPB systems reference LRA items 3.2.1-17 

or 3.3.1-25, which manage these components in a manner consistent with LRA item 3.2.1-18 

and the GALL Report recommendations.

LRA Table 3.2.1, items 3.2.1-26 and 3.2.1-27 address stainless steel heat exchanger tubes 

exposed to raw water that are being managed for reduction of heat transfer caused by fouling. 

The GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle Cooling Water 

System” to manage reduction of heat transfer for this component group. The applicant stated 

that these items are not applicable because the reduction of heat transfer for stainless steel

RHR heat exchanger components exposed to raw water is evaluated in auxiliary systems 

Table 3.3.1, item 3.3.1-42. The staff noted that LRA item 3.3.1-42 is similar to items 3.2.1-26 

and 3.2.1-27 and also uses the Open-Cycle Cooling Water System program to manage this 

aging effect for comparable components. The staff evaluated the applicant’s claim and found it 

acceptable because the staff confirmed that stainless steel RHR heat exchanger components 

exposed to raw water in the ESF systems are evaluated in the auxiliary systems section and 

reference LRA item 3.3.1-42, which manage for loss of material in a manner consistent with 

LRA items 3.2.1-26 and 3.2.1-27, and the GALL Report recommendations.

LRA Table 3.2.1, item 3.2.1-43 addresses elastomers, elastomer seals, and components 

exposed internally to uncontrolled indoor air. The GALL Report recommends GALL Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components” to manage hardening and loss of strength caused by elastomer degradation for 

this component group. The applicant stated that this item is not applicable because there are 

no elastomer seals and components exposed internally to uncontrolled indoor air in ESF

systems. The staff evaluated the applicant’s claim and found it acceptable because a review of 

LRA Section 2.3.2 and the LGS Units 1 and 2 UFSAR did not reveal any elastomeric materials 

exposed internally to uncontrolled indoor air, and LRA Table 3.2.2-6 lists elastomeric items 

associated with ducting and components and flexible connectors for which the internal 

environment is identified as internal wetted air or gas. These elastomeric items are being age 

managed by GALL Report AMP XI.M38, as recommended by the GALL Report.

LRA Table 3.2.1, item 3.2.1-44 addresses steel piping and components (internal surfaces), 

ducting and components (internal surfaces) exposed internally to uncontrolled indoor air. The 

GALL Report recommends GALL Report AMP XI. M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components,” to manage loss of material caused by general 

corrosion. The LRA states that this item is not applicable because there are no steel piping and 

components, ducting and components with internal surfaces exposed to uncontrolled indoor air 

in the ESF systems. The LRA also states that internal environment is considered condensation 

by LRA Table 3.2.1, item 3.2.1-46, which credits the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program for managing steel piping and 

components for loss of material. The staff evaluated the applicant’s claim and finds it 
3-246

acceptable because the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program proposes to manage loss of material using visual inspections that are 

capable of detecting aging before loss of intended function. 

3.2.2.1.2 Loss of Material Caused by General, Pitting, and Crevice Corrosion

LRA Table 3.2.1, item 3.2.1-16 addresses steel containment piping and components (internal 

surfaces) and piping, piping components, and piping elements exposed to treated water that will 

be managed for loss of material caused by general, pitting, and crevice corrosion. The staff 

noted that the applicant also applied this item to heat exchangers, tanks, and bolting and for all 

of the subject components (except bolting) exposed to a steam environment. For the AMR 

items that cite generic note E, the LRA credits the Bolting Integrity program to manage the aging 

effect for carbon and low-alloy steel bolting. The GALL Report recommends GALL Report 

AMPs XI.M2, “Water Chemistry,” and XI.M32, “One-Time Inspection” to ensure that this aging 

effect is adequately managed for piping components. 

GALL Report AMPs XI.M2 and XI.M32 recommend using water chemistry controls and a 

one-time inspection to verify the effectiveness of those controls to manage aging. The staff 

noted that, while LRA Section B.2.1.11, Bolting Integrity states that “inspection activities for 

bolting in a submerged environment are performed in conjunction with associated component 

maintenance activities,” it was not clear how the submerged bolted connections will be 

inspected and how often inspections will occur. By letter dated February 14, 2012, the staff 

issued RAI 3.2.2.1.1-1 requesting the applicant to state the parameters that will be inspected 

during opportunistic inspections of normally submerged bolting, the basis for why these 

parameters will be capable of assessing the condition of the bolting before loss of intended 

function occurs, and the minimum number of inspections that will be conducted during the 

period of extended operation. The applicant’s response and the staff’s evaluation of that 

response are documented in SER Section 3.2.2.1. 

The staff’s evaluation of the Bolting Integrity program is documented in SER Section 3.0.3.2.3. 

The staff noted that the applicant will visually inspect submerged bolting for loss of material at 

least once every 10-year ISI inspection interval in the CS, HPCI, and reactor core isolation 

cooling systems and at least once every 12 years in the condenser and air removal system. 

The staff also noted that water in the submerged environments in the above systems is 

maintained with the condensate cleanup system, which uses filters and demineralizers to 

maintain water purity. In its review of components associated with item 3.2.1-16 for which the 

applicant cited generic note E, the staff finds the applicant’s proposal to manage aging using the 

Bolting Integrity program acceptable because the water quality in the submerged environments 

is maintained to minimize contaminants that could promote corrosion and the periodic visual 

inspections in the Bolting Integrity program are capable of detecting loss of material before loss 

of intended function.

3.2.2.1.3 Loss of Material Caused by 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 that will be managed for loss of 

material caused by general, pitting, and crevice corrosion. The staff noted that the applicant 

only applied this item to stainless steel piping, piping component, and piping elements exposed 

to treated water and steam. For the AMR items that cite generic note E, the LRA credits the 

Bolting Integrity program to manage the aging effect for carbon and low-alloy steel bolting. The
3-247

GALL Report recommends GALL Report AMPs XI.M2, “Water Chemistry,” and XI.M32, 

“One-Time Inspection” to ensure that these aging effects are adequately managed for piping 

components. 

The applicant stated that for item 3.2.1-17, the applicability is limited to stainless steel piping, 

piping components, and piping elements exposed to treated water and steam. The staff noted 

that a search of the LGS Units 1 and 2 UFSAR confirmed that no aluminum piping, piping 

component, and piping elements exposed to treated water and steam are within the scope of 

license renewal and present in the ESF systems.

GALL Report AMPs XI.M2 and XI.M32 recommend using water chemistry controls and a 

one-time inspection to verify the effectiveness of those controls to manage aging. The staff 

noted that, while LRA Section B.2.1.11, Bolting Integrity states that “inspection activities for 

bolting in a submerged environment are performed in conjunction with associated component 

maintenance activities,” it is not clear how the submerged bolted connections will be inspected 

and how often inspections will occur. By letter dated February 14, 2012, the staff issued 

RAI 3.2.2.1.1-1 requesting the applicant to state the parameters that will be inspected during 

opportunistic inspections of normally submerged bolting, the basis for why these parameters will 

be capable of assessing the condition of the bolting before loss of intended function occurs, and 

the minimum number of inspections that will be conducted during the period of extended 

operation. The applicant’s response and the staff’s evaluation of that response are documented 

in SER Section 3.2.2.1. 

The staff’s evaluation of the Bolting Integrity program is documented in SER Section 3.0.3.2.3. 

The staff noted that the applicant will visually inspect submerged bolting for loss of material at 

least once every 10-year ISI inspection interval in the CS, HPCI, RCIC cooling, and RHR

systems. The staff also noted that water in the submerged environments in the above systems 

is maintained with the condensate cleanup system, which uses filters and demineralizers to 

maintain water purity. In its review of components associated with item 3.2.1-17 for which the 

applicant cited generic note E, the staff finds the applicant’s proposal to manage aging using the 

Bolting Integrity program acceptable because the water quality in the submerged environments 

is maintained to minimize contaminants that could promote corrosion and the periodic visual 

inspections in the Bolting Integrity program are capable of detecting loss of material before loss 

of intended function.

3.2.2.1.4 Loss of Material Caused by Pitting, Crevice, and Microbiologically-Influenced 

Corrosion; Fouling that Leads to Corrosion

LRA Table 3.2.1, item 3.2.1-25 addresses stainless steel heat exchanger and containment 

isolation piping components exposed to raw water that will be managed for loss of material 

caused by pitting, crevice, and microbiologically influenced corrosion (MIC) and fouling that 

leads to 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 effects for stainless steel components, including removable screens, screen 

frames, weir plates, and splitter assembly vortex suppressors. The GALL Report recommends 

GALL Report AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure these aging effects 

are adequately managed. 

GALL Report AMP XI.M20 recommends using periodic visual inspections and water chemistry 

controls to manage aging. The staff noted that the RG 1.127, Inspection of Water-Control 
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Structures Associated with Nuclear Power Plants program proposes to manage the aging of 

stainless steel components through the use of periodic visual inspection. The staff also noted 

that water chemistry controls associated with the Open-Cycle Cooling Water System program 

would equally affect the water control structures, so no additional chemistry controls would be 

needed. 

The staff’s evaluation of the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants program is documented in SER Section 3.0.3.2.18. In its review of 

components associated with item 3.2.1-25 for which the applicant cited generic note E, the staff 

finds the applicant’s proposal to manage aging using RG 1.127, Inspection of Water-Control

Structures Associated with Nuclear Power Plants program is acceptable because the program 

performs comparable visual inspections to identify loss of material and corrosion as those that 

are performed in the Open-Cycle Cooling Water System program.

The staff concludes that for LRA item 3.2.1-25, 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).

3.2.2.1.5 Cracking Caused by Stress Corrosion Cracking

LRA Table 3.2.1, item 3.2.1-54 addresses stainless steel piping, piping components, and piping 

elements exposed to treated water greater than 60° C (140 °F), which will be managed for 

cracking caused by SCC and IGSCC. For this AMR item, the GALL Report recommends using 

GALL Report AMP XI.M2, “Water Chemistry,” and GALL Report AMP XI.M7, “BWR Stress 

Corrosion Cracking.” GALL Report AMP XI.M2 includes water chemistry control to manage 

aging by limiting the concentrations of chemical species known to cause SCC and IGSCC and 

controlling dissolved oxygen levels to minimize the environmental effect on the aging effect. 

GALL Report AMP XI.M7 includes volumetric examinations of the welds of stainless steel and

nickel alloy components to detect and manage cracking caused by SCC and IGSCC. 

For the AMR item that addresses stainless steel valve bodies (LRA Table 3.1.2-1) with generic 

note E, the LRA credits the Water Chemistry program and ASME Code Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD program to manage the aging effect of these 

components. The Water Chemistry program proposes to manage the aging of the components 

through periodic monitoring and control of the water chemistry to mitigate environmental effect 

on SCC and IGSCC. The ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD program includes visual, surface, and volumetric examinations to manage aging in 

accordance with ASME Code, Section XI. 

The staff’s evaluations of the Water Chemistry and ASME Code Section XI Inservice Inspection,

Subsections IWB, IWC, and IWD programs are documented in SER Sections 3.0.3.1.2 and 

3.0.3.1.1, respectively. In its review of the stainless steel valve bodies associated with 

item 3.2.1-54, for which the applicant cited generic note E, the staff finds the applicant’s 

proposal to manage aging using the Water Chemistry program and ASME Code Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD program acceptable because (1) the 

Water Chemistry program limits the concentrations of chemical species known to cause SCC 

and IGSCC and controls the dissolved oxygen level to minimize the environmental effect on 

aging, and (2) the ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and 
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IWD program includes visual, surface, and volumetric examinations in accordance with ASME 

Code Section XI, which are adequate to detect and manage the aging effect.

The staff concludes that for LRA item 3.2.1-54, 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).

3.2.2.1.6 Conclusion

The staff evaluated the GALL Report AMR items that the applicant claimed were not applicable. 

On the basis of its review, the staff concludes that the AMR results that the applicant claimed 

were not applicable are not applicable to LGS Units 1 and 2.

As discussed in SER Section 3.0.2.2, for those AMRs that the applicant claimed consistency 

with the GALL Report, the staff evaluated the applicant’s claim of consistency. The staff also 

reviewed information pertaining to the applicant’s consideration of recent operating experience 

and proposals for managing aging effects. On the basis of its review, the staff concludes that 

the AMR results, which the applicant claimed to be consistent with the GALL Report, are 

consistent.

Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their 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 evaluates aging management, as recommended by 

the GALL Report, for the ESF systems components and provides information concerning how it 

will manage the following aging effects:

 • cumulative fatigue damage

 • loss of material caused by cladding breach

 • loss of material caused by pitting and crevice corrosion

 • loss of material caused by erosion

 • loss of material caused by general corrosion and fouling that leads to corrosion

 • cracking caused by SCC

 • QA for aging management of nonsafety-related components

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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3.2.2.2.1 Cumulative Fatigue Damage 

LRA Section 3.2.2.2.1 is associated with LRA Table 3.2.1 item 3.2.1-1 that addresses steel and 

stainless steel piping, piping components, and piping elements exposed to treated water in the 

ESF systems and are being managed for cumulative fatigue damage. 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 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 separately 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 

states that cumulative fatigue damage of steel and stainless steel piping, piping components, 

and piping elements in the ECCS is a TLAA, and that these TLAAs are to be evaluated in 

accordance with 10 CFR 54.21(c) and SRP-LR Section 4.3. The staff also reviewed the AMR

items associated with LRA Section 3.2.2.2.1, and found that the AMR results are consistent with 

the GALL Report and SRP-LR.

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.2.2.2.1 criteria. For those items that apply to LRA Section 3.2.2.2.1, the staff 

determined 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). SER Section 4.3 documents the staff’s review of the 

applicant’s evaluation of the TLAA for these components.

3.2.2.2.2 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 caused by cladding breach in PWR steel pump casings with stainless steel cladding 

exposed to treated borated water. The applicant stated that this item is not applicable because 

it is applicable to PWRs only. The staff confirmed that this item is associated only with PWR 

plants. Therefore, the staff finds the applicant’s determination acceptable.

3.2.2.2.3 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:

(1) LRA Section 3.2.2.2.3, item 1, associated with LRA Table 3.2.1, item 3.2.1-3, addresses 

loss of material caused by pitting and crevice corrosion in stainless steel 

partially-encased tanks with breached moisture barrier exposed to raw water. The 

applicant stated that this item is not applicable because the item is only applicable to 

PWR plants. The staff evaluated the applicant’s claim and finds it acceptable because 

item 3.2.1-3 is only applicable to PWRs and does not apply to LGS.

(2) LRA Section 3.2.2.2.3, item 2, associated with LRA Table 3.2.1, item 3.2.1-4, addresses 

stainless steel piping, piping components, piping elements, and tanks exposed to 

air-outdoor. The applicant stated that this item is not applicable because there are no 

ESF system components exposed to an outdoor air environment. The staff reviewed 

LRA Sections 2.3.2 and 3.2 and the UFSAR and finds that no stainless steel piping, 
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piping components, piping elements, and tanks exposed to outdoor air are within the 

scope of license renewal and present in the ESF systems.

3.2.2.2.4 Loss of Material Caused by Erosion

LRA Section 3.2.2.2.4, associated with LRA Table 3.2.1, item 3.2.1-5, addresses loss of 

material caused by erosion in stainless steel minimum flow recirculation orifices exposed to 

treated borated water for PWR high-pressure safety injection (HPSI) pumps. 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 is only applicable to PWRs 

and does not apply to LGS.

3.2.2.2.5 Loss of Material Caused by 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 caused by general corrosion and fouling that leads to corrosion in steel drywell and 

suppression chamber spray system nozzle and flow orifice internal surfaces exposed to 

air-indoor, uncontrolled. The applicant stated that this item is not applicable because there are 

no steel spray system flow orifices or nozzles in an uncontrolled indoor air environment in the 

ESF systems. The applicant also stated that the drywell and suppression chamber spray 

nozzles are brass. The staff reviewed LRA Sections 2.3.2 and 3.2 and the UFSAR and finds 

that no steel drywell and suppression chamber spray system nozzle and flow orifice internal 

surfaces exposed to air-indoor, uncontrolled are within the scope of license renewal and present 

in the ESF systems.

3.2.2.2.6 Cracking Caused by Stress Corrosion Cracking

LRA Section 3.2.2.2.6, associated with LRA Table 3.2.1, item 3.2.1-7, addresses stainless steel 

piping, piping components, piping elements, and tanks exposed to outdoor air. The applicant 

stated that this item is not applicable because there are no components in the ESF systems 

exposed to an outdoor air environment. The staff reviewed LRA Sections 2.3.2 and 3.2 and the 

UFSAR and finds that no stainless steel piping, piping components, piping elements, and tanks

exposed to outdoor air are within the scope of license renewal and present in the ESF systems.

3.2.2.2.7 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.

3.2.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

In LRA Tables 3.2.2-1 through 3.2.2-6, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with or not addressed 

in the GALL Report.

In LRA Tables 3.2.2-1 through 3.2.2-6, the applicant indicated, via 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 
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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.

3.2.2.3.1 Containment Atmosphere Control - 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 

containment atmosphere control system component groups. The staff’s review did not identify 

any items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for this system are consistent with the GALL Report.

3.2.2.3.2 Core Spray - 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 

CS component groups.

In LRA Table 3.2.2-2, the applicant stated that for polymeric piping, piping components, and 

piping elements exposed externally to uncontrolled indoor air and internally to lubricating oil 

there is no aging effect and no AMP is proposed. The AMR items cite generic note F. These 

items cite plant-specific note 4, which states that the component is butyrate plastic and this 

material has no aging effects when exposed externally to indoor air and internally to lubricating 

oil.

The staff reviewed the associated items in the LRA to confirm that no credible aging effects are 

applicable for this component, material, and environment combination. The staff finds the 

applicant’s proposal acceptable based on its review of Chemical Resistance of Plastics and 

Elastomers (4th Electronic Edition) by the Plastics Design Library Staff, Plastics Design Library

(PDL), which states that the appearance of the material was unchanged when exposed to 

environments such as lubricating oil, machining oils, transformer oils, water, etc. The staff 

noted that this document assigns a PDL rating that is a weighted value scale of test results 

when materials are exposed to specific environments. For a description of the PDL rating, see 

Fluorinated Coatings and Finishes Handbook – The Definitive Users Guide, Laurence McKeen, 

2006, Plastics Design Laboratory, Section 1.2. The scale ranges from 0, worst, to 9, best. The 

PDL rating for butyrate plastic ranged from 7-9. In addition, exposure to accelerated outdoor 

and accelerated weather resulted in an average PDL specimen rating of 5 for a range of 

exposures from one-half a year to 3 years. The indoor air environment will be less severe. A 

PDL rating of 5 yields some stress cracking, but the material remains pliable. Website vendor 

information, Tentite Plastics –Weathering of Tentite Butyrate, Eastman Publication PP104B, 

May 1999, http://www.eastman.com, states that butyrate compounds are resistant to the indoor 

air environment even when not augmented with heavy pigmentation to mitigate the impact of 

direct sunlight.
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In LRA Tables 3.2.2-2 and 3.3.2-14, the applicant stated that for zinc piping, piping components, 

and piping elements and valve bodies exposed to uncontrolled indoor air, there is no aging 

effect and no AMP is proposed. The AMR items cite generic note F. The items associated with 

zinc piping and valve bodies cite plant-specific note 5 (LRA Table 3.2.2-2) and note 2 

(Table 3.3.2-14), respectively, which state that the component is zinc die cast and has no aging 

effects in an indoor air environment.

The staff reviewed the associated items in the LRA to confirm that no credible aging effects are 

applicable for this component, material, and environment combination. The staff noted that LRA 

Table 3.0-2 states that humidity levels up to 100 percent are assumed in the uncontrolled indoor 

air environment and components may be wet. The staff also noted that the GALL Report

item III.B2.TP-6 states that zinc-coated steel should be managed for loss of material when 

exposed to potentially wet air environments. By letter dated January 17, 2012, the staff issued 

RAI 3.0.2-1 requesting the applicant to identify which AMR items in the LRA are exposed to an 

uncontrolled indoor air environment for which humidity, condensation, moisture, or contaminants 

are present and, for those exposed to potentially aggressive environments, determine the aging 

effects and select an appropriate AMP. The applicant’s response and the staff’s evaluation of 

that response are documented in SER Section 3.0.1.2. In the response, the applicant stated 

that the environment of uncontrolled indoor air does not contain humidity, condensation, 

moisture, or contaminants.

The staff finds the applicant’s AMR acceptable based on its review of the Metals Handbook, 

Desk Edition, 2nd Edition, which states zinc has a high degree of atmospheric corrosion 

resistance caused by the formation of carbonate films. Also, the GALL Report item VII.J.AP-13 

states that galvanized (zinc-coated) steel has no aging effect in an uncontrolled indoor air 

environment.

In LRA Table 3.2.2-2, the applicant stated that zinc piping, piping components, and piping 

elements exposed to lubricating oil will be managed for loss of material by the Lubricating Oil 

Analysis and One-Time Inspection programs. The AMR items cites generic note F, 5. Items 

associated with this material in Table 3.2.2-2 cite plant-specific note 5, which states that 

although NUREG-1801 does not provide a line for zinc piping components, they are susceptible 

to loss of material and are inspected per the Lubricating Oil Analysis program.

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 GALL Report does not address 

zinc piping, piping components, and piping elements exposed to lubricating oil and loss of 

material as the aging effect. However, the staff noted that the GALL Report does address 

copper-alloy components with 15 percent zinc or more exposed to lubricating oil and loss of 

material as the aging effect. Based on its review of the GALL Report and the ASM Handbook, 

both of which state that loss of material in the form of pitting and crevice corrosion may occur in 

this environment, 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 Lubricating Oil Analysis and One-Time Inspection programs is 

documented in SER Sections 3.0.3.1.17 and 3.0.3.1.14. The staff finds the applicant’s proposal 

to manage aging using the Lubricating Oil Analysis and One-Time Inspection programs 

acceptable because the Lubricating Oil Analysis program will be able to detect and minimize 
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contaminants in lubricating oil; and the staff confirmed that the One-Time Inspection program 

will be used to examine selected components at susceptible locations where contaminants such 

as water could accumulate, which is consistent with the GALL Report.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.2.2.3.3 High-Pressure Coolant Injection – Summary of Aging Management Review –

LRA Table 3.2.2-3

The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for the 

HPCI system component groups. The staff’s review did not identify any items with notes F 

through J, indicating that the combinations of component type, material, environment, and 

AERM for this system are consistent with the GALL Report.

3.2.2.3.4 Reactor Core Isolation Cooling – Summary of Aging Management Review –

LRA Table 3.2.2-4

The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for the 

reactor core isolation cooling system component groups. The staff’s review did not identify any 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for this system are consistent with the GALL Report.

3.2.2.3.5 Residual Heat Removal - Summary of Aging Management Review –

LRA Table 3.2.2-5

The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations for the 

RHR system component groups. The staff’s review did not identify any items with notes F 

through J, indicating that the combinations of component type, material, environment, and 

AERM for this system are consistent with the GALL Report.

3.2.2.3.6 Standby Gas Treatment – Summary of Aging Management Review –

LRA Table 3.2.2-6

The staff reviewed LRA Table 3.2.2-6, which summarizes the results of AMR evaluations for the 

Standby Gas Treatment component groups.

In LRA Table 3.2.2-6, the applicant stated that elastomer ducting and components, flexible 

connections exposed to air/gas – wetted (internal) will be managed for loss of material, 

hardening and loss of strength 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. The staff noted that the LRA Table 3.0-1 states that 

air/gas environments contain significant amounts of moisture where condensation or water 

pooling may occur. Based on its review of the GALL Report, which states that elastomers 
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exposed to a water environment (e.g., raw water, treated water, and closed cycle cooling water) 

are subject to loss of material and hardening and loss of strength, 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 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program is documented in SER Section 3.0.3.1.16. 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 program’s use of periodic opportunistic 

inspections during component surveillance, system inspections, and maintenance activities are 

effective measures for identifying and managing these aging effects.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.2.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the ESF system components within the scope of license renewal and 

subject to an AMR will be adequately managed so that the intended functions will remain 

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 SER section documents the staff’s review of the applicant’s AMR results for the auxiliary 

systems components and component groups of:

 • auxiliary steam

 • closed cooling water

 • compressed air

 • control enclosure ventilation

 • CRD

 • cranes and hoists

 • EDG enclosure ventilation

 • EDG

 • fire protection

 • fuel handling and storage

 • fuel pool cooling and cleanup

 • nonsafety-related service water

 • plant drainage
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 • primary containment instrument gas 

 • primary containment leak testing

 • primary containment ventilation

 • process radiation monitoring

 • process and post-accident sampling

 • radwaste

 • reactor enclosure ventilation

 • reactor water cleanup

 • safety-related service water

 • spray pond pump house ventilation

 • SLC

 • traversing in-core probe

 • water treatment and distribution

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 Programs for Auxiliary Systems 

Evaluated in Chapter VII of NUREG-1801,” is a summary comparison of the applicant’s AMRs 

with those evaluated in the GALL Report for the auxiliary systems 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.

3.3.2 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 review of AMRs to ensure the applicant’s claim that certain AMRs are 

consistent with the GALL Report. 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 was 

applicable and that the applicant identified the appropriate GALL Report AMRs. The staff’s 

evaluations of the AMPs are documented in SER Section 3.0.3.

During its review, the staff also selected AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 
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are consistent with the SRP-LR Section 3.3.2.2 acceptance criteria. The staff’s evaluations are 

documented in SER Section 3.3.2.2.

The staff also conducted a technical review of the remaining AMRs not consistent with or not 

addressed in the GALL Report. The technical review evaluated whether all plausible aging 

effects have been identified and whether the aging effects listed were appropriate for the 

material-environment combinations specified. The staff’s evaluations are documented in SER 

Section 3.3.2.3.

For SSCs that the applicant claimed were not applicable or required no aging management, the 

staff reviewed the AMR items and the plant’s operating experience to verify the applicant’s 

claims.

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.

Table 3.3-1 Staff Evaluation for Auxiliary Systems Components in the GALL Report

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

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 

caused by

fatigue

Fatigue is a TLAA to 

be evaluated for the 

period of extended 

operation for 

structural girders of 

cranes that fall within 

the scope of 

10 CFR Part 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 

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 

caused by

fatigue

Fatigue is a 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)
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Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel heat 

exchanger 

components, 

non-regenerative 

exposed to treated 

borated water >60 °C 

(>140 °F) (3.3.1-3)

Cracking caused 

by stress 

corrosion 

cracking; cyclic 

loading

Chapter XI.M2, 

“Water Chemistry”

The AMP is to be 

augmented by 

verifying the absence 

of cracking caused 

by 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.

No NA 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 caused 

by stress 

corrosion 

cracking

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with 

GALL Report (see 

Section 3.3.2.2.3)

Steel (with stainless 

steel or nickel-alloy 

cladding) pump 

casings exposed to 

treated borated water 

(3.3.1-5)

Loss of material 

caused by

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.”

No NA 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 

caused by pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes External Surfaces 

Monitoring of 

Mechanical 

Components and 

Buried and 

Underground 

Piping and Tanks

Consistent with the 

GALL Report (see 

Section 3.3.2.2.5)

Stainless steel 

high-pressure pump, 

casing exposed to 

treated borated water 

(3.3.1-7)

Cracking caused 

by cyclic loading

Chapter XI.M1, 

“ASME Code 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD”

No NA Not applicable to 

BWRs (see SER 

Section 3.3.2.1.1)
3-259

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel heat 

exchanger 

components and 

tubes exposed to 

treated borated water 

>60 °C (>140 °F) 

(3.3.1-8)

Cracking caused 

by cyclic loading

Chapter XI.M1, 

“ASME Code 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD”

No NA 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 

caused by boric 

acid corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No NA 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 caused 

by stress 

corrosion 

cracking; cyclic 

loading

Chapter XI.M18, 

“Bolting Integrity”

No NA Not applicable to 

LGS (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 caused 

by stress 

corrosion 

cracking; cyclic 

loading

Chapter XI.M18, 

“Bolting Integrity”

No NA Not applicable to 

BWRs (see SER 

Section 3.3.2.1.1)

Steel; stainless steel 

closure bolting, 

bolting exposed to 

condensation, 

air-indoor, 

uncontrolled 

(external), 

air-outdoor (external) 

(3.3.1-12)

Loss of material 

caused by

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity 

and Buried and 

Underground 

Piping and Tanks

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.2)

Steel closure bolting 

exposed to air with 

steam or water 

leakage (3.3.1-13)

Loss of material 

caused by

general 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No NA Not applicable to 

LGS (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
3-260

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

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 

caused by

thermal effects, 

gasket creep, 

and 

self-loosening

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water >60 °C 

(>140 °F) (3.3.1-16)

Cracking caused 

by stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M25, 

“BWR Reactor Water 

Cleanup System”

No Water Chemistry 

and BWR 

Reactor Water 

Cleanup System

Consistent with the 

GALL Report

Stainless steel heat 

exchanger tubes 

exposed to treated 

water (3.3.1-17)

Reduction of 

heat transfer 

caused by

fouling

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No NA Not applicable to 

LGS (see SER 

Section 3.3.2.1.1)

Stainless steel 

high-pressure 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 caused 

by stress 

corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No NA Not applicable to 

LGS (see SER 

Section 3.3.2.1.1)

Stainless steel 

regenerative heat 

exchanger 

components exposed 

to treated water 

>60 °C (>140 °F) 

(3.3.1-19)

Cracking caused 

by stress 

corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

and One-Time 

Inspection

Consistent with the 

GALL Report
3-261

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

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 heat 

exchanger 

components exposed 

to treated borated 

water >60 °C 

(>140 °F), treated 

water >60 °C 

(>140 °F) (3.3.1-20)

Cracking caused 

by stress 

corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

and One-Time 

Inspection

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to treated 

water (3.3.1-21)

Loss of material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

and One-Time 

Inspection

Consistent with the 

GALL Report

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.3.1-22)

Loss of material 

caused by

general, pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

and One-Time 

Inspection

Consistent with the 

GALL Report

Aluminum piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.3.1-23)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No NA Not applicable to 

LGS (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 

caused by pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No NA Not applicable to 

LGS (See SER 

Section 3.3.2.1.1)

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 

caused by pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry, 

One-Time 

Inspection, 

Bolting Integrity, 

and Inspection of 

Overhead Heavy 

Load and Light 

Load (Related to 

Refueling) 

Handling 

Systems

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.3)

Steel (with elastomer 

lining), steel (with 

elastomer lining or 

stainless steel 

cladding) piping, 

piping components, 

and piping elements 

exposed to treated

water (3.3.1-26)

Loss of material 

caused by pitting 

and crevice 

corrosion (only 

for steel after 

lining/cladding 

degradation)

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No NA Not applicable to 

LGS (see SER 

Section 3.3.2.1.1)
3-262

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel heat 

exchanger tubes 

exposed to treated 

water (3.3.1-27)

Reduction of 

heat transfer 

caused by

fouling

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No NA Not applicable to 

LGS (see SER 

Section 3.3.2.1.1)

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, 

piping, piping 

components, and 

piping elements; 

tanks exposed 

treated water >60 °C 

(>140 °F), treated 

borated water >60 °C 

(>140 °F) (3.3.1-28)

Cracking caused 

by stress 

corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry”

No NA Not applicable to 

LGS (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 

(3.3.1-29)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry”

No NA Not applicable to 

LGS (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 

caused by

aggressive 

chemical attack

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No NA Not applicable to 

LGS (See SER 

Section 3.3.2.1.1)

Fiberglass, HDPE 

Piping, piping 

components, and 

piping elements 

exposed to Raw 

water (internal) 

3.3.1-30x)

Cracking, 

blistering, 

change in color 

caused by water 

absorption

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

LGS (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 

caused by

settling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No NA Not applicable to 

LGS (See SER 

Section 3.3.2.1.1)
3-263

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

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 raw water 

(3.3.1-32)

Cracking caused 

by aggressive 

chemical attack 

and leaching; 

changes in 

material 

properties 

caused by

aggressive 

chemical attack

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No NA Not applicable to 

LGS (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 

caused by

elastomer 

degradation; 

loss of material 

caused by

erosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report

Concrete; 

cementitious material 

piping, piping 

components, and 

piping elements 

exposed to raw water 

(3.3.1-33)

Loss of material 

caused by

abrasion, 

cavitation, 

aggressive 

chemical attack, 

and leaching

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Fire Water 

System

Consistent with 

SRP-LR (see SER 

Section 3.3.2.1.4)

Nickel alloy, 

copper-alloy piping, 

piping components, 

and piping elements 

exposed to raw water 

(3.3.1-34)

Loss of material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No NA Not applicable to 

LGS (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 

caused by

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No NA Not applicable to 

LGS (See SER 

Section 3.3.2.1.1)

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to raw water 

(3.3.1-36)

Loss of material 

caused by

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
3-264

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel (with coating or 

lining) piping, piping 

components, and 

piping elements 

exposed to raw water 

(3.3.1-37)

Loss of material 

caused by

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion; 

lining/coating 

degradation

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No NA Not applicable to 

LGS (See SER 

Section 3.3.2.1.1)

Copper alloy, steel 

heat exchanger 

components exposed 

to raw water 

(3.3.1-38)

Loss of material 

caused by

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 

caused by pitting 

and crevice 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No NA Not applicable to 

LGS (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 

caused by 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

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw water 

(3.3.1-41)

Loss of material 

caused by

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Structures 

Monitoring 

Program and 

RG 1.127, 

“Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants”

Consistent with 

SRP-LR (see SER 

Section 3.3.2.1.5)

Copper alloy, 

titanium, stainless 

steel heat exchanger 

tubes exposed to raw 

water (3.3.1-42)

Reduction of 

heat transfer 

caused by

fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report
3-265

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

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 

closed-cycle cooling 

water >60 °C 

(>140 °F) (3.3.1-43)

Cracking caused 

by stress 

corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (see SER 

Section 3.3.2.1.1)

Stainless steel; steel 

with stainless steel 

cladding heat 

exchanger 

components exposed 

to closed-cycle 

cooling water >60 °C 

(>140 °F) (3.3.1-44)

Cracking caused 

by stress 

corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (see SER 

Section 3.3.2.1.1)

Steel piping, piping 

components, and 

piping elements; 

tanks exposed to 

closed-cycle cooling 

water (3.3.1-45)

Loss of material 

caused by

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 

closed-cycle cooling 

water (3.3.1-46)

Loss of material 

caused by

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 closed-cycle 

cooling water 

(3.3.1-47)

Loss of material 

caused by

microbiologically

-influenced 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (See SER 

Section 3.3.2.1.1)

Aluminum piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water (3.3.1-48)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (see SER 

Section 3.3.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water (3.3.1-49)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report
3-266

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

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 

caused by

fouling

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water System

Consistent with the 

GALL Report

Boraflex 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 

neutron-absorbi

ng capacity 

caused by

Boraflex 

degradation

Chapter XI.M22, 

“Boraflex Monitoring”

No NA Not applicable to 

LGS (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 

caused by

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 

caused by 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 

caused by

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 

caused by

general and 

pitting corrosion

Chapter XI.M24, 

“Compressed Air 

Monitoring”

No Compressed Air 

Monitoring

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

condensation 

(internal) (3.3.1-56)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M24, 

“Compressed Air 

Monitoring”

No Compressed Air 

Monitoring and 

Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.6)
3-267

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Elastomers fire 

barrier penetration 

seals exposed to 

air-indoor, 

uncontrolled, 

air-outdoor (3.3.1-57)

Increased 

hardness; 

shrinkage; loss 

of strength 

caused by

weathering

Chapter XI.M26, 

“Fire Protection”

No Fire Protection 

and Structures 

Monitoring

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.7)

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 

caused by

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 

caused by 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 caused 

by 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 caused 

by 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 

caused by

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 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M27, 

“Fire Water System”

No Fire Water 

System

Consistent with the 

GALL Report
3-268

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

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 

caused by

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M27, 

“Fire Water System”

No Fire Water 

System, 

Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components, 

RG 1.127 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants, and 

Structures 

Monitoring

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.8)

Aluminum piping, 

piping components, 

and piping elements 

exposed to raw water 

(3.3.1-65)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M27, 

“Fire Water System”

No Fire Water 

System

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw water 

(3.3.1-66)

Loss of material 

caused by pitting 

and crevice 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M27, 

“Fire Water System”

No Fire Water 

System

Consistent with the 

GALL Report

Steel tanks exposed 

to air-outdoor 

(external) (3.3.1-67)

Loss of material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Aboveground 

Metallic Tanks 

and Buried and 

Underground 

Piping and Tanks

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.9)

Steel piping, piping 

components, and 

piping elements 

exposed to fuel oil 

(3.3.1-68)

Loss of material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M30, 

“Fuel Oil Chemistry”, 

and Chapter XI.M32, 

“One-Time 

Inspection”

No NA Not applicable to 

LGS (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 

caused by

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M30, 

“Fuel Oil Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Fuel Oil 

Chemistry, 

One-Time 

Inspection, and 

Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.10)
3-269

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

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 

caused by

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, 

One-Time 

Inspection, and 

Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.11)

Stainless steel, 

aluminum piping, 

piping components, 

and piping elements 

exposed to fuel oil 

(3.3.1-71)

Loss of material 

caused by

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 

(3.3.1-72)

Loss of material 

caused by

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 

caused by

aggressive 

chemical attack

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No NA Not applicable to 

LGS (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 

caused by

settling

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No NA Not applicable to 

LGS (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 caused 

by aggressive 

chemical attack 

and leaching; 

Changes in 

material 

properties 

caused by

aggressive 

chemical attack

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No NA Not applicable to 

LGS (see SER 

Section 3.3.2.1.1)
3-270

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

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 

caused by

elastomer 

degradation

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.12)

Concrete; 

cementitious material 

piping, piping 

components, and 

piping elements 

exposed to 

air-outdoor (3.3.1-77)

Loss of material 

caused by

abrasion, 

cavitation, 

aggressive 

chemical attack, 

and leaching

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No NA Not applicable to 

LGS (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 

caused by

general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External Surfaces 

Monitoring and 

Fire Protection

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.13)

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(external) (3.3.1-79)

Loss of material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No NA Not applicable to 

LGS (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 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External Surfaces 

Monitoring of 

Mechanical 

Components, 

Buried 

Underground 

Piping and Tanks, 

and Fire 

Protections

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.13 

and 3.3.2.1.14)
3-271

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Copper alloy, 

aluminum piping, 

piping components, 

and piping elements 

exposed to 

air-outdoor 

(external), 

air-outdoor (3.3.1-81)

Loss of material 

caused by 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

Elastomers, 

elastomer seals, and 

components exposed 

to air-indoor, 

uncontrolled 

(external) (3.3.1-82)

Loss of material 

caused by 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 caused 

by 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 closed-cycle 

cooling water 

(3.3.1-85)

Hardening and 

loss of strength 

caused by

elastomer 

degradation

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, linings, 

elastomer seals, and 

components exposed 

to treated borated 

water, treated water, 

raw water (3.3.1-86)

Hardening and 

loss of strength 

caused by

elastomer 

degradation

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 3.3.2.1.15)

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 

caused by

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 

caused by

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 and 

Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.16)
3-272

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

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 

caused by

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

Steel piping, piping 

components, and 

piping elements; 

tanks exposed to 

waste water 

(3.3.1-91)

Loss of material 

caused by

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 

caused by 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 and 

Compressed Air 

Monitoring

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.17)

Copper-alloy Piping, 

piping components, 

and piping elements 

exposed to Raw 

water (potable) 

(3.3.1-93)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No NA Not applicable to 

LGS (see SER 

Section 3.3.2.1.1)

Stainless steel 

ducting and 

components exposed 

to condensation 

(3.3.1-94)

Loss of material 

caused by 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 

caused by

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
3-273

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

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) (3.3.1-96)

Loss of material 

caused by wear

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No NA Not applicable to 

LGS (See SER 

Section 3.3.2.1.1)

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 

caused by

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 

caused by

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 

caused by 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 

caused by

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 

caused by

fouling

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No NA Not applicable to 

LGS (see SER 

Section 3.3.2.1.1)
3-274

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Boral®; boron steel, 

and other materials 

(excluding Boraflex) 

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 

neutron-absorbi

ng capacity; 

change in 

dimensions and 

loss of material 

caused by

effects of SFP 

environment

Chapter XI.M40, 

“Monitoring of 

Neutron-Absorbing 

Materials other than 

Boraflex”

No Monitoring of 

Neutron-Absorbin

g Materials Other 

Than Boraflex

Consistent with the 

GALL Report

Reinforced concrete, 

asbestos cement 

piping, piping 

components, and 

piping elements 

exposed to soil or 

concrete (3.3.1-103)

Cracking caused 

by aggressive 

chemical attack 

and leaching; 

Changes in 

material 

properties 

caused by

aggressive 

chemical attack

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No NA Not applicable to 

LGS (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 

caused by water 

absorption

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No NA Not applicable to 

LGS (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 caused by

exposure of 

rebar

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No NA Not applicable to 

LGS (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 

caused by

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Buried and 

Underground 

Piping and Tanks 

and Structures 

Monitoring

Consistent with the 

GALL Report (see 

SER 

Section 3.3.2.1.18)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to soil or 

concrete (3.3.1-107)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No NA Not applicable to 

LGS (See SER 

Section 3.3.2.1.1)
3-275

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Titanium, super 

austenitic, aluminum, 

copper alloy, 

stainless steel piping, 

piping components, 

and piping elements, 

bolting exposed to 

soil or concrete 

(3.3.1-108)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No NA Not applicable to 

LGS (See SER 

Section 3.3.2.1.1)

Steel bolting 

exposed to soil or 

concrete (3.3.1-109)

Loss of material 

caused by

general, pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Buried and 

Underground 

Piping and Tanks

Consistent with the 

GALL Report

Underground 

aluminum, copper 

alloy, stainless steel 

and steel piping, 

piping components, 

and piping elements 

(3.3.1-109x)

Loss of material 

caused by

general (steel 

only), pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No NA 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 caused 

by stress 

corrosion 

cracking

Chapter XI.M7, 

“BWR Stress 

Corrosion Cracking,”

and Chapter XI.M2, 

“Water Chemistry”

No NA See SER 

Section 3.3.2.1.1

Steel structural steel 

exposed to 

air-indoor, 

uncontrolled 

(external) (3.3.1-111)

Loss of material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No NA Not applicable to 

LGS (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.

NA Consistent with the 

GALL Report
3-276

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

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

NA 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

NA 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 (3.3.1-115)

None None NA – No 

AEM or 

AMP

NA 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

NA 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

NA Consistent with the 

GALL Report
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Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

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

NA 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

NA Consistent with the 

GALL Report

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

NA Consistent with the 

GALL Report

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

NA 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 

LGS (see SER 

Section 3.3.2.1.1)
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Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

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 

LGS (see SER 

Section 3.3.2.1.1)

The staff’s review of the auxiliary systems component groups followed any one of several 

approaches. One approach, documented in SER Section 3.3.2.1, reviewed AMR results for 

components that the applicant indicated are consistent with the GALL Report and require no 

further evaluation. Another approach, documented in SER Section 3.3.2.2, reviewed AMR 

results for components that the applicant indicated are consistent with the GALL Report and for 

which further evaluation is recommended. A third approach, documented in SER 

Section 3.3.2.3, reviewed AMR results for components that the applicant indicated are not 

consistent with, or not addressed in, the GALL Report. The staff’s review of AMPs credited to 

manage or monitor aging effects of the auxiliary systems components is documented in SER 

Section 3.0.3.

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:

 • aboveground metallic tanks

 • bolting integrity

 • buried and underground piping and tanks

 • BWR reactor water cleanup system

 • closed treated water systems

 • compressed air monitoring

 • external surfaces monitoring of mechanical components

 • fire protection

 • fire water systems

 • 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
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 • lubricating oil analysis

 • monitoring of neutron-absorbing materials other than Boraflex

 • one-time inspection

 • open-cycle cooling water system

 • selective leaching

 • structures monitoring

 • TLAA

 • water chemistry

LRA Tables 3.3.2-1 through 3.3.2-26 summarize AMRs for the auxiliary system components 

and indicate AMRs claimed to be consistent with the GALL Report.

The staff audited and reviewed the information in the LRA. 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 was applicable and that the applicant identified the appropriate GALL 

Report AMRs. The staff’s evaluation follows.

LRA Table 3.3.1, item 3.3.1-15 addresses steel, stainless steel, copper alloy, and nickel alloy 

closure bolting exposed to air-indoor, uncontrolled (external), any environment including, 

air-outdoor (external), raw water, treated borated water, fuel oil, and treated water. During its 

review of stainless steel bolting exposed to treated water (external) associated with 

item 3.3.1-15 for which the applicant cited generic note A, the staff noted that while LRA 

Section B.2.1.11, Bolting Integrity states that, “Inspection activities for bolting in a submerged 

environment are performed in conjunction with associated component maintenance activities,” it 

is not clear to the staff how the submerged bolted connections will be inspected and how often 

inspections will occur. By letter dated February 14, 2012, the staff issued RAI 3.2.2.1.1-1 

requesting the applicant to state the parameters that will be inspected for during opportunistic 

inspections of normally submerged bolting and the basis for why these parameters will be 

capable of assessing the condition of the bolting before loss of intended function occurs, and 

the minimum number of inspections that will be conducted during the period of extended 

operation.

In its response dated March 13, 2012, the applicant stated that the submerged bolts in the CS

system, HPCI system, RCIC system, and RHR system are visually inspected for loss of material 

and loss of preload at least once every 10-year ISI inspection interval. The applicant also stated 

that the submerged bolts in the condenser and air removal system are visually inspected for 

loss of material and loss of preload at least once every 12-year replacement interval. The 

applicant further stated that the submerged bolts in the fuel pool cooling and cleanup system, 

and the circulating water system are visually inspected for loss of material and loss of preload 

every refueling outage during planned maintenance. The applicant stated that in each 

application, the bolting is not high strength. The visual inspection checks for degradation 

including corrosion and missing or loose parts.

The staff finds the applicant’s response acceptable because the visual inspection techniques 

will be able to identify loss of material and loss of preload aging effects that enables assessment 

of the condition of the bolting before loss of intended function occurs, set inspection 
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frequencies, and provide opportunities to inspect the components for aging. The applicant’s 

program follows recommended industry bolting techniques including design, torquing, gasket 

compression, and lubrication that help to maintain preload and the possibility of 

lubrication-related corrosion. The condenser and air removal system is continuously monitored 

for system pressure, and the applicant’s CAP will provide additional opportunistic inspection 

opportunities for components. The staff’s concern described in RAI 3.2.2.1.1-1 is resolved.

The staff concludes that for LRA item 3.3.1-15, 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).

In the LRA AMR tables, there are several entries for copper alloy with 15-percent zinc or more 

or gray cast iron components internally exposed to “air/gas – wetted,” which will be managed for 

loss of material by the Inspection of Internal Surfaces of Miscellaneous Piping and Ducting 

program. According to the LRA, this program uses periodic and opportunistic inspections of the 

internal surfaces of components augmented by physical manipulation of flexible elastomers 

where appropriate.

The LRA defines “air/gas – wetted” as “air/gas environments containing significant amounts of 

moisture where condensation or water pooling may occur. This environment includes air with 

enough moisture to facilitate loss of material in steel caused by general, pitting, and crevice 

corrosion.”

Since selective leaching is known to occur in susceptible materials such as gray cast iron and 

uninhibited brasses with greater than 15-percent zinc when moisture or water an electrolyte is 

present, the staff was concerned that visual inspections alone may not be sufficient to detect 

selective leaching. Therefore, by letter dated February 14, 2012, the staff issued 

RAI 3.2.2.1.1-3 requesting the applicant to explain why copper alloy with 15-percent zinc or 

more or gray cast iron components internally exposed to air/gas – wetted are not being 

managed for selective leaching. If it is determined that selective leaching is an appropriate 

aging effect or mechanism to be managed, the applicant was requested to explain which AMP

and inspection method(s) will be used to manage the loss of material caused by selective 

leaching.

In its response dated March 13, 2012, as corrected by letter dated March 30, 2012, the 

applicant provided a listing of the copper alloy with 15-percent zinc or more and gray cast iron 

components exposed to an internal environment of air/gas – wetted. These included 

components and fittings in the control enclosure ventilation, SGTS, RHR, EDG, fire protection, 

PCIG, and HPCI systems. The applicant stated that it performed an evaluation of the design 

and operating conditions of each component to assess the potential for significant moisture to 

accumulate and water pooling to occur. 

The applicant found that in two instances–the EDG system dirty fuel oil drain tank level glass 

valves and the PCIG receiver drain traps–the components accumulate condensation and are 

exposed to significant moisture. The applicant stated that it revised LRA Table 3.3.2-8 to 

include loss of material caused by selective leaching for the EDG dirty fuel oil drain tank level 

glass valves, and LRA Table 3.3.2-14 and LRA Section 3.3.2.1.14 to include loss of material 

caused by selective leaching for the PCIG receiver drain traps. For the remaining components 

and fittings made of copper alloy with 15-percent zinc or more and gray cast iron components 
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and exposed to an internal environment of air/gas – wetted, the applicant stated that the design 

and operating characteristics of the components and fittings are such that they are normally dry 

and not subject to significant amounts of moisture or water pooling. Therefore, the applicant 

does not consider selective leaching to be an applicable aging effect,

The staff finds the applicant’s response acceptable because the applicant assessed the design 

and operating conditions to determine if the potential for significant water accumulation exists. 

In cases where the applicant determined that such a potential exists, it included the components 

within the Selective Leaching program, and will manage the aging of these components. The 

staff’s evaluation of the applicant’s revision to LRA Tables 3.3.2-8 and 3.3.2-14, as corrected by 

letter dated March 30, 2012, is documented in SER Sections 3.3.2.3.8 and 3.3.2.3.14, 

respectively. The staff’s evaluation of the Selective Leaching program is documented in SER 

Section 3.0.3.1.13. The staff’s concern described in RAI 3.2.2.1.1-3 is resolved.

3.3.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.3.1 items 3.3.1.10, 3.3.1-17, 3.3.1-18, 3.3.1-27, 3.3.1-28, 3.3.1-29, 3.3.1-30x, 

3.3.1-48, 3.3.1-51, 3.3.1-68, 3.3.1-73, 3.3.1-74, 3.3.1-75, 3.3.1.77, 3.3.1-93, 3.3.1-101,

3.3.1-103, 3.3.1-104, 3.3.1-105, 3.3.1-110, 3.3.1-111, 3.3.1-122, and 3.3.1-123, the applicant 

claimed that they were not applicable. The staff reviewed the LRA and UFSAR and confirmed 

that the applicant’s LRA does not have any AMR results that are applicable for these items.

For LRA Table 3.3.1 items 3.3.1-7, 3.3.1-8, 3.3.1-9, 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 these items only apply 

to PWRs, and finds these items are not applicable to LGS.

LRA Table 3.3.1, item 3.3.1-11 addresses steel high-strength high-pressure pump closure 

bolting exposed to air with steam or water leakage. The GALL Report recommends GALL 

Report AMP XI.M18, “Bolting Integrity,” to manage cracking caused by SCC and cyclic loading 

for this component group. The applicant stated that this item is not applicable because it only 

applies to PWR plants. The staff noted that the GALL Report, Table VII. E1, item AP-122,

addresses high-pressure pump closure bolting in a chemical volume and control system (PWR) 

and that the reactor water cleanup recirculation pump is equivalent to a charging pump at a 

PWR. The staff noted that in LRA Table 3.3.2-21, reactor water cleanup system, bolting is 

managed for loss of material and loss of preload, but not cracking caused by SCC and cyclic 

loading; however, based on a review of the UFSAR, the staff was able to confirm that the 

reactor water cleanup recirculation pumps do not use high-strength bolting and thus the bolts 

are not susceptible to SCC.

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 caused by 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 found it acceptable because all auxiliary system bolting exposed to air is being managed for 

loss of material by the Bolting Integrity program using item LRA Table 3.3.1, item 3.3.1-12, the 

External Surfaces Monitoring of Mechanical Components program using LRA Table 3.3.1, 

item 3.3.1-78, or the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) 

Handling Systems program using LRA Table 3.5.1, item 3.5.1-80. These programs conduct 
3-282

periodic visual inspections capable of detecting loss of material because of general corrosion in 

bolting, and the External Surfaces Monitoring of Mechanical Components and Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling System programs 

conduct the visual inspections on a frequency that meets or is more frequent than the Bolting 

Integrity program, or in the case of infrequently used cranes, bolting is inspected before use; 

therefore, use of these programs is consistent with the GALL Report.

LRA Table 3.3.1, items 3.3.1-23 and 3.3.1-24 address aluminum piping, piping components, 

and piping elements exposed to treated water. The GALL Report recommends GALL Report 

AMPs XI.M2, “Water Chemistry” and XI.M32, “One-Time Inspection” to manage loss of material 

caused by pitting and crevice corrosion for this component group. The applicant stated that this 

item is not applicable because this material-environment-aging effect combination is addressed 

with LRA item 3.3.1-25. The staff evaluated the applicant’s claim and found it acceptable 

because the staff confirmed that aluminum piping components exposed to treated water in the 

auxiliary systems reference LRA item 3.3.1-25, which manages for loss of material in a manner 

consistent with LRA items 3.3.1-23 and 3.3.1-24 and the GALL Report recommendations. 

LRA Table 3.3.1, item 3.3.1-26 addresses steel (with elastomer lining), steel (with elastomer 

lining or stainless steel cladding) piping, piping components, and piping elements exposed to 

treated water. The GALL Report recommends GALL Report AMPs XI.M2, “Water Chemistry,”

and XI.M32, “One-Time Inspection” to manage loss of material caused by pitting and crevice 

corrosion (only for steel after lining or cladding degradation) for this component group. The 

applicant stated that this item is not applicable because this item for the loss of material in lined

or clad steel exposed to treated water after elastomer lining or stainless steel cladding 

degradation was not used. Elastomer lining was not credited for preventing the loss of material 

aging effect in steel and stainless steel cladding was not assumed to fail because of

degradation. The staff evaluated the applicant’s claim and found it acceptable for elastomer 

lined piping because the applicant cited LRA Table 3.3.1, item 3.3.1-21 to manage all steel 

piping, piping components, and piping elements exposed to treated water, this item

recommends the same two programs to manage the components as LRA Table 3.3.1, 

item 3.3.1-26 (i.e., GALL Report AMPs XI.M2 and XI.32), and the staff confirmed that all steel 

piping, piping components, and piping elements within the scope of license renewal and 

exposed to treated water in the auxiliary systems are being managed for loss of material by 

GALL Report AMPs XI.M2 and XI.32 (i.e., LRA Tables 3.3.2-1, 3.3.2-5, 3.3.2-11 3.3.2-17 

3.3.2-18, 3.3.2-19, 3.3.2-21, 3.3.2-24, and 3.3.2-26). The staff evaluated the applicant’s claim 

and found it acceptable for stainless steel clad piping because the applicant cited LRA 

Table 3.3.1, item 3.3.1-25 to manage all stainless steel piping, piping components, and piping 

elements exposed to treated water, this item recommends the same two programs to manage 

the components as item 3.3.1-26 (i.e., GALL Report AMPs XI.M2 and XI.32), this item includes 

steel with stainless steel cladding materials, and the staff confirmed that all in-scope stainless 

steel piping, piping components, and piping elements exposed to treated water in the auxiliary 

systems are being managed for loss of material by GALL Report AMPs XI.M2 and XI.32 

(i.e., LRA Tables 3.3.2-1, 3.3.2-5, 3.3.2-11 3.3.2-17 3.3.2-18, 3.3.2-19, 3.3.2-21, 3.3.2-24, 

and 3.3.2-26).

LRA Table 3.3.1, items 3.3.1-30, 3.3.1-31, and 3.3.1-32 address concrete, reinforced concrete, 

and cementitious material piping components exposed to raw water. The GALL Report 

recommends GALL Report AMP XI.M20, “Open-Cycle Cooling Water System,” to manage 

changes in material properties and cracking caused by aggressive chemical attack and cracking 

caused by settling for these material groups. The applicant stated that these items are not 
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applicable because these aging effects do not apply to the associated components in the 

auxiliary systems. Since the applicant used item 3.3.1-33, which addresses concrete and 

cementitious piping components exposed to raw water for loss of material, it was not clear to the 

staff how the applicant concluded that changes in material properties and cracking did not need 

to be managed. By letter dated February 14, 2012, the staff issued RAI 3.3.1.30-1 requesting 

the applicant to provide its bases for claiming items 3.3.1-30, 3.3.1-31, and 3.3.1-32 were not 

applicable to LGS. 

In its response dated March 13, 2012, the applicant stated that the cement material included in 

item 3.3.1-33 is described in Note 5 of LRA Table 3.3.2-9 as the lining of piping used in the 

buried fire protection system, which is 12-inch cement lined cast iron pipe. The response also 

stated that the aging management of the cement lining was revised in response to 

RAI 3.3.1.33-1 to be part of the Fire Water System program. The response further stated there 

is no reinforced concrete or asbestos cement piping in scope for license renewal, so item

3.3.1-32 is not applicable. The applicant’s response was acceptable because the cement lining 

material, which is addressed in items 3.3.1-30 and 3.3.1-31, is being managed through the Fire 

Water System program, which includes flow testing, visual inspections, or volumetric 

examinations as well as preventive measures capable of managing the applicable aging effects. 

In addition, the response clarified that the there is no reinforced concrete or asbestos cement 

piping in scope for license renewal. Based on the above, the staff finds the applicant’s 

determination acceptable, and the staff’s concern described in RAI 3.3.1.30-1 is resolved.

LRA Table 3.3.1, items 3.3.1-34, 3.3.1-35, and 3.3.1-37 address copper-alloy and steel piping 

components exposed to raw water. The GALL Report recommends GALL Report AMP XI.M20, 

“Open-Cycle Cooling Water System” to manage loss of material caused by general, pitting, 

crevice, and MIC for this component group. The applicant stated that these items are not 

applicable because these component groups are addressed with LRA items 3.3.1-36 

and 3.3.1-38. The staff noted that LRA items 3.3.1-36 and 3.3.1-38 are similar to 

items 3.3.1-34, 3.3.1-35, and 3.3.1-37, but in some cases manage for the additional aging 

effects of galvanic corrosion and fouling that leads to corrosion. With respect to item 3.3.1-37, 

the applicant stated that coatings and linings in carbon steel piping are not credited for 

mitigating loss of material for license renewal and the staff did not identify any carbon steel 

piping components in auxiliary systems with either linings or coatings. The staff evaluated the 

applicant’s claim and found it acceptable because the staff confirmed that carbon steel and 

copper-alloy piping components exposed to raw water in the auxiliary systems reference either 

LRA item 3.3.1-36 or 3.3.1-38, which manage for loss of material in a manner consistent with 

LRA items 3.3.1-34, 3.3.1-35 and 3.3.1-37, and the GALL Report recommendations.

LRA Table 3.3.1, item 3.3.1-39 addresses stainless steel piping components exposed to raw 

water. The GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle Cooling Water 

System” to manage loss of material caused by pitting and crevice corrosion for this component 

group. The applicant stated that this item is not applicable because these component groups 

are addressed with LRA Table 3.3.1, item 3.3.1-40. The staff noted that LRA Table 3.3.1 

item 3.3.1-40 is similar to item 3.3.1-39, but also manages for the additional aging effects of 

fouling that leads to corrosion. The staff evaluated the applicant’s claim and found it acceptable 

because the staff confirmed that stainless steel piping components exposed to raw water in the 

auxiliary systems reference LRA item 3.3.1-40, which manage for loss of material in a manner 

consistent with LRA item 3.3.1-39 and the GALL Report recommendations.
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LRA Table 3.3.1, items 3.3.1-43 and 3.3.1-44 address stainless steel piping, piping 

components, and piping elements and stainless steel and steel with stainless steel cladding 

heat exchanger components exposed to closed-cycle cooling water greater than 60° C (greater 

than 140 °F). The GALL Report recommends GALL Report AMP XI.M21A, “Closed Treated 

Water Systems” to manage cracking caused by SCC for this component group. The applicant 

stated that this item is not applicable because there are no stainless steel or steel with stainless 

steel cladding piping and heat exchanger components exposed to closed-cycle cooling water 

greater than 60° C (greater than 140 °F) in the auxiliary systems. The staff’s review of the LRA 

and UFSAR was not able to verify the applicant’s claim of non-applicability. As documented in 

SER Section 3.0.3.2.5, the staff issued RAI B.2.1.13-1 requesting the applicant to clarify 

whether the temperatures of the closed-cycle cooling water environments are above or below 

the SCC threshold of 60° C (140 °F). In its response dated February 15, 2012, the applicant 

stated that stress corrosion cracking is not applicable, because the temperature of the 

closed-cycle cooling water environment is below 60° C (140 °F) for all of the systems managed 

by the Closed Treated Water Systems program. The staff finds the applicant’s claim of 

non-applicability acceptable because the applicant confirmed that the environment of 

closed-cycle cooling water greater than 60° C (greater than 140 °F) is not present at LGS.

LRA Table 3.3.1, item 3.3.1-47 addresses stainless steel and steel with stainless steel cladding 

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 caused by MIC for this component group. The applicant stated that this item is not 

applicable because this component group is addressed with LRA Table 3.3.1, item 3.3.1-49. 

The staff confirmed that the subject components reference LRA item 3.3.1-49, which addresses 

stainless steel piping, piping components, and piping elements exposed to closed-cycle cooling 

water and manages for loss of material caused by pitting and crevice corrosion with the Closed 

Treated Water Systems program. The staff noted that, although items 3.3.1-47 and 3.3.1-49 

cite different aging mechanisms, the loss of material aging effect and the AMP are identical. 

The staff also noted that the visual inspection activities in the Closed Treated Water Systems 

program are capable of, and appropriate for, the detection of pitting, crevice, and MIC before

loss of intended function. The staff further noted that EPRI Report 1007820, Closed Cooling 

Water Chemistry Guideline, Revision 1, states that the regions of heat exchangers most prone 

to pitting and crevice corrosion (lower tubes that may experience crud buildup) are also those 

areas where MIC may be expected to occur, and thus targeted inspection locations for pitting, 

crevice corrosion, and MIC are expected to be similar. The staff evaluated the applicant’s claim 

and finds it acceptable because the applicant’s selection of the alternative item 3.3.1-49 will 

manage for loss of material in a manner consistent with LRA item 3.3.1-47 and the GALL Report

recommendations. 

LRA Table 3.3.1, item 3.3.1-79 addresses copper-alloy piping, piping components, and piping 

elements exposed externally to condensation. The GALL Report recommends GALL Report 

AMP XI.M36 “External Surfaces Monitoring of Mechanical Components” to manage loss of 

material caused by general, pitting, and crevice corrosion for this component group. The LRA 

states that this item is not applicable because the only copper alloy components exposed to an 

external wetted environment are cooling coils in the ventilation system, which are inspected 

during the internal inspection of the cooler assembly. The LRA also states that management of 

the cooling coils is addressed by LRA Table 3.3.1, item 3.3.1-89, which is for copper alloy 

components exposed internally to condensation that are being managed for loss of material by 

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program. 

The staff evaluated the applicant’s claim and finds it acceptable because the Inspection of 
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Internal Surfaces in Miscellaneous Piping and Ducting Components and the External Surfaces 

Monitoring of Mechanical Components programs both propose to manage loss of material using 

visual inspections capable of detecting aging before loss of intended function.

LRA Table 3.3.1, item 3.3.1-96 addresses elastomers, elastomer seals, and components 

exposed internally to indoor, uncontrolled air. The GALL Report recommends GALL Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components” to manage loss of material caused by wear for this component group. The 

applicant stated that this item is not applicable because there are no elastomer seals or 

components exposed to indoor, uncontrolled air with a loss of material aging effect in the 

auxiliary systems. The GALL Report Section IX.F, states that there are three factors to consider 

that could cause age-related wear caused by the design of a elastomeric joint, including 

(1) relative motion between two surfaces under the influence of hard abrasive particles, 

(2) frequent manipulation, or (3) in clamped joints where relative motion is not intended but may 

occur caused by a loss of the clamping force. The staff noted that the applicant has many 

elastomeric components that are exposed to indoor, uncontrolled air or internally to wetted air or 

gas including hoses, ducting and components, flexible connections, and expansion joints. The 

staff found the applicant’s position acceptable for hoses and ducting and components because:

 • All components are being managed by the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components and External Surfaces Monitoring of 

Mechanical Components programs.

 • LRA Sections B.2.1.26, Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components, and B.2.1.25, External Surfaces Monitoring of Mechanical 

Components, state that elastomeric materials will be visually inspected and physically 

manipulated to detect hardening and loss of strength. 

 • Although loss of material caused by wear is not listed as an aging effect, the applicant is 

inspecting for hardening and loss of strength. The visual and physical manipulation 

inspections can detect loss of material caused by wear.

The staff found the applicant’s position acceptable for flexible connections because:

 • All components are being managed by the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components and External Surfaces Monitoring of 

Mechanical Components programs.

 • LRA Sections B.2.1.26, Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components and B.2.1.25, External Surfaces Monitoring of Mechanical 

Components state that elastomeric materials will be visually inspected and physically 

manipulated to detect hardening and loss of strength.

 • Loss of material is listed as an aging effect for both the internal and external surfaces, 

although item 3.3.1-96 is not used because the environment is wetted air or gas on 

internal surfaces, not indoor, uncontrolled air. For the wetted air or gas environment, the 

applicant did not reference an SRP-LR Table 1 item, but rather cited the item as being 

inconsistent and referenced generic note G. The staff’s evaluation of the applicant’s 

aging management for these components is documented in SER Section 3.3.2.3.3.
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The staff found the applicant’s position acceptable for the expansion joints (EDG HTX) 

because:

 • All components are being managed by the Open-Cycle Cooling Water System and 

External Surfaces Monitoring of Mechanical Components programs.

 • LRA Sections B.2.1.12, Open-Cycle Cooling Water System, and B.2.1.25, External 

Surfaces Monitoring of Mechanical Components, state that elastomeric materials will be 

visually inspected and physically manipulated to detect hardening and loss of strength. 

 • Although loss of material caused by wear is not listed as an aging effect, the applicant is 

inspecting for hardening and loss of strength. The visual and physical manipulation 

inspections can detect loss of material caused by wear.

LRA Table 3.3.1, item 3.3.1-107 addresses stainless steel piping, piping components and piping 

elements exposed to soil or concrete. The GALL Report recommends GALL Report 

AMP XI.M41 “Buried and Underground Piping and Tanks” program to manage loss of material 

caused by pitting and crevice corrosion for this component group. The applicant stated that this 

item is not applicable because there are no stainless steel piping, piping components, and 

piping elements exposed to soil in the auxiliary systems and stainless steel piping, piping 

components, and piping elements exposed to concrete are being managed for aging by 

item 3.3.1-120. The staff evaluated the applicant’s claim and found it acceptable because LRA

Tables 3.3.2-11 and 3.3.2-13 contain no stainless steel piping exposed to soil. During the audit, 

the staff reviewed several drawings and pictures and validated that the applicant has used 

fillcrete (a cementitious material) as backfill for buried piping, and 3.3.1-120 addresses stainless 

steel piping, piping components, and piping elements exposed to concrete and is, therefore, an 

acceptable item to manage this material.

LRA Table 3.3.1, item 3.3.1-108 addresses titanium, super austenitic, aluminum, copper-alloy, 

and stainless steel piping, piping components, piping elements, and bolting exposed to soil or 

concrete. The GALL Report recommends GALL Report AMP XI.M41 “Buried and Underground 

Piping and Tanks” program to manage loss of material caused by pitting and crevice corrosion 

for this component group. The applicant stated that this item is not applicable because there 

are no titanium, super austenitic, aluminum, or copper-alloy piping, piping components, piping 

elements, or bolting exposed to soil or concrete in the auxiliary systems. Furthermore, there are 

no stainless steel piping, piping components, and piping elements exposed to soil in the 

auxiliary systems, and stainless steel piping, piping components and piping elements exposed 

to concrete are being managed for aging by item 3.3.1-120. The staff evaluated the applicant’s 

claim and found it acceptable because a review of the UFSAR and LRA confirmed that there are 

no titanium, super austenitic, aluminum or copper-alloy piping, piping components, or piping 

elements exposed to soil or concrete within the scope of license renewal, and LRA

Tables 3.3.2-11 and 3.3.2-13 contain no stainless steel piping exposed to soil. During the audit, 

the staff reviewed several drawings and pictures and validated that the applicant has used 

fillcrete (a cementitious material) as backfill for buried piping, and 3.3.1-120 addresses stainless 

steel piping, piping components, and piping elements exposed to concrete and is, therefore, an 

acceptable item to manage this material.

LRA Table 3.3.1, item 3.3.1-109x addresses aluminum, copper-alloy, stainless steel, and steel 

piping, piping components, and piping elements exposed to an underground environment. The 

GALL Report recommends GALL Report AMP XI.M41 “Buried and Underground Piping and 

Tanks” program to manage loss of material caused by general (steel only), pitting and crevice 
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corrosion for this component group. The applicant stated that this item is not applicable 

because loss of material caused by general, pitting, and crevice corrosion of underground steel 

piping, piping components, and piping elements is addressed in LRA Table 3.3.1, item 3.3.1-80. 

The staff evaluated the applicant’s claim and found it acceptable because a review of the 

UFSAR and LRA confirmed that there are no in-scope aluminum, copper-alloy, and stainless 

steel piping, piping components, and piping elements exposed to the underground environment, 

and 3.3.1-80 addresses steel piping, piping components and piping elements exposed to indoor 

and outdoor air and uses the Buried and Underground Piping and Tanks program to manage 

loss of material as recommended by the GALL Report in item 3.3.1-109x.

3.3.2.1.2 Loss of Material

LRA Table 3.3.1, item 3.3.1-12 addresses steel and stainless steel closure bolting exposed 

externally to condensation and indoor, uncontrolled, and outdoor air that will be managed for

loss of material. For the AMR items that cite generic note E, the LRA credits the Buried and 

Underground Piping and Tanks program to manage the aging effect for carbon and low-alloy 

steel bolting exposed to outdoor air. The GALL Report recommends GALL Report AMP XI.M18 

“Bolting Integrity” to ensure that these aging effects are adequately managed. 

GALL Report AMP XI.M18 recommends using periodic inspections of bolting for indication of 

loss of material and preventive measures such as use of lubricants and proper torque values for 

installing bolting. The staff noted that the Buried and Underground Piping and Tanks program 

proposes to manage the aging of carbon and low-alloy steel bolting through the use of coatings 

as a preventive measure and periodic visual inspections. The staff also noted that in LRA

Tables 3.3.2-8 and 3.3.2-22, the carbon and low-alloy steel bolting that cites generic note E is 

also being managed by the Bolting Integrity program for loss of preload.

The staff’s evaluation of the Buried and Underground Piping and Tanks program is documented 

in SER Section 3.0.3.2.12. In its review of components associated with item 3.3.1-12 for which 

the applicant cited generic note E, the staff finds the applicant’s proposal to manage aging using 

the Buried and Underground Piping and Tanks program acceptable because the programs uses 

coatings as a preventive measure for mitigating external corrosion. Furthermore, periodic visual 

inspections are capable of detecting loss of material and the same bolting items are being 

managed by the Bolting Integrity program, which uses preventive measures such as use of 

lubricants and proper torque values for installing bolting, all of which is consistent with the GALL 

Report for managing aging of bolting.

The staff concludes that for LRA item 3.3.1-12, 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).

3.3.2.1.3 Loss of Material Caused by Pitting and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-25 addresses stainless steel, steel with stainless steel cladding, 

and aluminum piping, piping components, piping elements, and heat exchanger components 

exposed to treated water and sodium pentaborate solution that will be managed for loss of 

material caused by pitting and crevice corrosion. The staff noted that the applicant also applied 

this item to bolting, tanks, and crane/hoist components. 
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For the AMR items in LRA Table 3.3.2-10 that reference LRA Table 3.3.1, item 3.3.1-25 and cite 

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 components. The GALL Report recommends GALL Report 

AMP XI.M2 “Water Chemistry” and XI.M32 “One-Time Inspection” programs to ensure that 

these aging effects are adequately managed. 

GALL Report AMP XI.M32 recommends using a one-time visual or volumetric inspection of 

components to verify the effectiveness of water chemistry controls and confirm the 

insignificance of the aging effect. The staff noted that the Inspection of Overhead Heavy Load 

and Light Load (Related to Refueling) Handling Systems program proposes to manage the 

aging of the aluminum crane and hoist components through the use of periodic visual 

inspections in accordance with ASME Code, B30 standards (yearly for frequently used 

equipment, just before use for infrequently used equipment) to verify the effectiveness of water 

chemistry controls that mitigate aging.

The staff’s evaluations of the Water Chemistry and Inspection of Overhead Heavy Load and 

Light Load (Related to Refueling) Handling Systems programs are documented in SER 

Sections 3.0.3.1.2 and 3.0.3.2.6, respectively. In its review of components associated with 

item 3.3.1-25 in LRA Table 3.3.2-10 for which the applicant cited generic note E, the staff finds 

the applicant’s proposal to manage aging using the Water Chemistry and Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems programs

acceptable because the Water Chemistry program establishes the plant water chemistry control 

parameters and their limits to mitigate the potential for aging and identifies the actions required 

if the parameters exceed the limits. Furthermore, the Inspection of Overhead Heavy Load and 

Light Load (Related to Refueling) Handling Systems program prescribes appropriate periodic or 

before-use visual inspections capable of detecting pitting and crevice corrosion to verify the 

effectiveness of the water chemistry controls.

For the AMR items in LRA Table 3.3.2-11 that reference LRA Table 3.3.1, item 3.3.1-25 and cite 

generic note E, the LRA credits the Bolting Integrity program to manage the aging effect for 

stainless steel bolting. The GALL Report recommends GALL Report AMPs XI.M2, “Water 

Chemistry,” and XI.M32, “One-Time Inspection” to ensure that this aging effect is adequately 

managed. 

GALL Report AMPs XI.M2 and XI.M32 recommend using water chemistry controls and a 

one-time inspection to verify the effectiveness of those controls to manage aging. The staff 

noted that, while LRA Section B.2.1.11, Bolting Integrity states that “inspection activities for 

bolting in a submerged environment are performed in conjunction with associated component 

maintenance activities,” it is not clear how the submerged bolted connections will be inspected 

and how often inspections will occur. By letter dated February 14, 2012, the staff issued 

RAI 3.2.2.1.1-1 requesting the applicant to state the parameters that will be inspected during 

opportunistic inspections of normally submerged bolting, the basis for why these parameters will 

be capable of assessing the condition of the bolting before loss of intended function occurs, and 

the minimum number of inspections that will be conducted during the period of extended 

operation. The applicant’s response and the staff’s evaluation of that response are documented 

in SER Section 3.2.2.1. 

The staff’s evaluation of the Bolting Integrity program is documented in SER Section 3.0.3.2.3. 

The staff noted that the applicant will visually inspect submerged bolting for loss of material 
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during refueling outages in the fuel pool cooling and cleanup system. The staff also noted that 

the purity of the water in this system is maintained with filter demineralizers. In its review of 

components associated with item 3.3.1-25 for which the applicant credited the Bolting Integrity

program and cited generic note E, the staff finds the applicant’s proposal to manage aging 

acceptable because the water quality in the submerged environments is maintained to minimize 

contaminants that could promote corrosion and the periodic visual inspections in the Bolting 

Integrity program are capable of detecting loss of material before loss of intended function.

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(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.3.2.1.4 Loss of Material

LRA Table 3.3.1, item 3.3.1-33 addresses concrete and cementitious material piping, piping 

components, and piping elements exposed to raw water, which will be managed for loss of 

material due abrasion, cavitation, aggressive chemical attack, and leaching. For the AMR items 

that cite generic note E, the LRA credits the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components program to manage loss of material for cement piping, piping 

components, and piping elements exposed to raw water in the fire protection system. The AMR 

item in LRA Table 3.3.2-9 cites plant-specific note 5, which states that the cement lined piping is 

the buried fire main. 

The GALL Report recommends GALL Report AMP XI.M20, “Open Cycle Cooling Water,” to 

manage loss of material for concrete piping exposed to raw water; however, GALL Report 

AMP XI.M20 is for components exposed to open-cycle cooling water, not fire water. GALL 

Report AMP XI.M27, “Fire Water System,” manages aging for fire protection system 

components exposed to fire water and recommends using either flow testing, visual inspections, 

or volumetric examinations as well as preventive measures including periodic flushes and 

system performance testing to manage loss of material. System flow testing, flushes, 

performance testing, and inspections are performed in accordance with the applicable NFPA 

codes and standards. NFPA 25 includes requirements for flow testing of underground fire 

mains. The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

program proposes to use visual inspections to manage loss of material for cement components 

exposed to raw water and does not include any preventive measures. It is not clear to the staff 

how the visual inspections performed by the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components program are adequate to manage loss of material for the 

cement lined buried fire main, given that the program does not include preventive measures or 

flow testing as recommended by GALL Report AMP XI.M27. By letter dated January 18, 2012, 

the staff issued RAI 3.3.1.33-1 requesting the applicant to explain how the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components program is adequate to manage 

loss of material for components exposed to fire water.

In its response dated February 16, 2012, the applicant stated that it will use the Fire Water 

System program to manage aging for the internal surface of the concrete lining for the fire main. 

The applicant revised item 3.3.1-33 and the AMR item in LRA Table 3.3.2-9 to reference the 

Fire Water System program instead of the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components program. The staff’s evaluation of the Fire Water System 

program is documented in SER Section 3.0.3.2.8. The staff finds the applicant’s response and 
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its proposal to manage aging for the buried fire main using the Fire Water System program 

acceptable because the proposed program includes flow testing, visual inspections, or 

volumetric examinations as well as preventive measures capable of managing loss of material. 

The staff’s concern described in RAI 3.3.1.33-1 is resolved.

The staff concludes that for LRA Table 3.3.1, item 3.3.1-33, 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).

3.3.2.1.5 Loss of Material Because of Pitting, Crevice, and Microbiologically Influenced 

Corrosion

LRA Table 3.3.1, item 3.3.1-41 addresses stainless steel components exposed to raw water that 

will be managed for loss of material caused by pitting, crevice corrosion, and MIC. For the AMR 

items that cite generic note E, the LRA credits RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants program to manage the aging effects of stainless steel 

structural bolting, concrete anchors, and concrete embedments for structures and component 

supports in the spray pond and pump house. The LRA also credits the Structures Monitoring 

program to manage the aging effects of stainless steel sump liners and integral attachments for 

structures and component support in the radwaste, reactor, and control enclosures. For this 

AMR item, the GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle Cooling 

Water System,” to ensure these aging effects are adequately managed. 

GALL Report AMP XI.M20 recommends using periodic visual inspections, water chemistry 

controls, and heat transfer testing to manage aging. However, the staff noted that the 

applicant’s use of item 3.3.1-41 for the associated components may not be appropriate because 

GALL Report AMP XI.M20 implements the recommendations of GL 89-13 to manage aging of 

components that transfer heat from safety-related SSCs to the ultimate heat sink. The staff also 

noted that RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants program and the Structures Monitoring program propose to manage the aging of 

stainless steel components through the use of periodic visual inspections. 

The staff’s evaluations of the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants program and the Structures Monitoring program are documented in SER 

Section 3.0.3.2.18 and Section 3.0.3.2.17, respectively. In 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 aging using the above programs acceptable because both programs 

perform periodic visual inspections capable of detecting 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).

3.3.2.1.6 Loss of Material Caused by Pitting and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-56 addresses stainless steel piping components exposed internally 

to condensation that will be managed for loss of material caused by pitting and crevice 

corrosion. For the AMR items that cite generic note E, the LRA credits the Open-Cycle Cooling 
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Water System program to manage loss of material for stainless steel piping components 

exposed to wetted air or gas in the safety-related SW system. The GALL Report recommends 

GALL Report AMP XI.M24, “Compressed Air Monitoring,” to ensure that these aging effects are 

adequately managed. 

GALL Report AMP XI.M24 recommends maintaining moisture and other corrosive contaminants 

below acceptable limits by periodic sampling and testing to mitigate loss of material. 

Additionally, GALL Report AMP recommends periodic and opportunistic visual inspections of 

accessible internal surfaces to detect signs of loss of material caused by corrosion. 

The staff’s evaluation of the Open-Cycle Cooling Water System program is documented in SER 

Section 3.0.3.2.4. This program manages loss of material, reduction of heat transfer, and 

hardening and loss of strength of elastomers in heat exchangers and piping components in 

safety-related and nonsafety-related raw water systems exposed to a raw water or wetted air or 

gas environments. The staff noted that the associated components addressed by item 3.3.1-56

and credit the Open-Cycle Cooling Water System program are stainless steel spray nozzles in 

the safety-related SW system, which are not part of a compressed air system and do not 

contain or use compressed air or gas. The staff also noted that these nozzles provide cooling 

for the emergency SW and RHR SW systems, which are the open-cycle cooling water systems. 

In its review of components associated with item 3.3.1-56, for which the applicant cited generic 

note E, the staff finds the applicant’s proposal to manage aging using the Open-Cycle Cooling 

Water System program acceptable because the program includes visual inspections and 

nondestructive examinations, which are capable of detecting loss of material caused by pitting 

and crevice corrosion.

The staff concludes that for LRA Table 3.3.1, item 3.3.1-56, 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).

3.3.2.1.7 Increased Hardness, Shrinkage, Loss of Strength Because of Weathering

LRA Table 3.3.1, item 3.3.1-57 addresses elastomer fire barrier penetration seals exposed to 

indoor uncontrolled or outdoor air that will be managed for increased hardness, shrinkage, and 

loss of strength. For the AMR items that cite generic note E, the LRA credits the Structures 

Monitoring program to manage the aging effect for elastomer seismic gap fillers and expansion 

joints. The GALL Report recommends GALL Report AMP XI.M26, “Fire Protection,” to ensure 

that these aging effects are adequately managed.

GALL Report AMP XI.M26 recommends performing visual inspections of at least 10 percent of 

each type of penetration seal every refueling cycle to manage aging for elastomer fire barrier 

seals. However, GALL Report AMP XI.M26 is only applicable to fire protection system 

components, and the program activities and inspection frequencies are not applicable for 

components in other systems. The staff noted that GALL Report AMP XI.S6, “Structures 

Monitoring,” includes aging management of vibration isolators and structural sealants using 

visual inspections. The staff also noted that the Structures Monitoring program proposes to 

manage aging of elastomer seals by performing visual inspections of all accessible areas at 

least once every 10 years.
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The staff’s evaluation of the Structures Monitoring program is documented in SER 

Section 3.0.3.2.17. In its review of components associated with item 3.3.1-57 for which the 

applicant cited generic note E, the staff finds the applicant’s proposal to manage aging using the 

Structures Monitoring program acceptable because it includes visual inspections that are 

capable of detecting hardness, shrinkage, and loss of strength for seismic gap fillers and 

expansion joints.

The staff concludes that for LRA item 3.3.1-57, 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).

3.3.2.1.8 Loss of Material

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 caused 

by general, pitting, crevice corrosion, and MIC; and fouling that leads to corrosion. For the AMR 

items that cite generic note E, the LRA credits the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program to manage loss of material for carbon 

steel piping, piping components, piping elements, tanks, and valve bodies exposed to raw water 

in the EDG. The LRA also credits RG 1.127, Inspection of Water-Control Structures Associated 

with Nuclear Power Plants program to manage loss of material for ductile cast iron and carbon 

steel concrete embedments exposed to raw water in the spray pond pump house. The LRA 

further credits the Structures Monitoring program to manage loss of material for carbon steel 

sump liners, liner anchors, and integral attachments in the turbine enclosure. The GALL Report 

recommends GALL Report AMP XI.M27, “Fire Water System,” to ensure that these aging 

effects are adequately managed. 

GALL Report AMP XI.M27 recommends using either flow testing, visual inspections, or 

volumetric examinations to manage loss of material for fire protection components exposed to 

raw water. However, GALL Report AMP XI.M27 is only applicable to fire protection system 

components, and the program activities and inspection frequencies are not applicable for 

components exposed to raw water in other systems. The Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program, RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants program, and Structures Monitoring program 

propose visual inspections to manage loss of material for carbon steel and ductile cast iron 

components exposed to raw water. 

The staff’s evaluation of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components, RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants, and Structures Monitoring programs are documented in SER Sections 3.0.3.1.16, 

3.0.3.2.18, and 3.0.3.2.17, respectively. In its review of components associated with 

item 3.3.1-64 for which the applicant cited generic note E, the staff finds the applicant’s proposal 

to manage aging using Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program, RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants program, or Structures Monitoring program acceptable because each 

program includes visual inspections capable of detecting loss of material in steel components 

exposed to raw water.
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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 

be maintained consistent with the CLB during the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.3.2.1.9 Loss of Material Caused by General, Pitting, and Crevice Corrosion

LRA Table 3.3.1 item 3.3.1-67 addresses steel tanks exposed externally to outdoor air that will 

be managed for loss of material caused by general, pitting, and crevice corrosion. For the AMR 

item that cites generic note E, the LRA credits the Buried and Underground Piping and Tanks

program to manage the aging effect for steel tanks. The GALL Report recommends GALL 

Report AMP XI.M29, “Aboveground Metallic Tanks,” to ensure that these aging effects are 

adequately managed.

GALL Report AMP XI.M29 recommends using periodic visual inspections of the external 

surfaces of the component and coatings as a preventive action to manage aging. The staff 

noted that the Buried and Underground Piping and Tanks program proposes to manage the 

aging of steel tanks through the use of periodic visual inspections of the external surfaces of the 

component and coatings as a preventive action.

The staff’s evaluation of the Buried and Underground Piping and Tanks program is documented 

in SER Section 3.0.3.2.12. The staff noted that the applicant cited plant-specific note 1, which 

states that the fuel oil storage tanks are located underground in the diesel oil storage tank 

structures in an outdoor air environment. The staff also noted that, based on a review of the 

UFSAR and drawings during the audit, the enclosures are not routinely exposed to rain or other 

forms of moisture despite the stated outdoor air environment given that they are within an 

enclosed structure. The staff further noted that the inspection interval for the LRA Buried and 

Underground Piping and Tanks program is once every 10 years and the interval for GALL 

Report AMP XI.M29, “Aboveground Metallic Tanks,” is once a refueling outage; however, given 

that the tanks are in an underground vault and not exposed to rain or other moisture, the staff 

finds the inspection interval acceptable. In its review of components associated with item

3.3.1-67 for which the applicant cited generic note E, the staff finds the applicant’s proposal to 

manage aging using the Buried and Underground Piping and Tanks program acceptable 

because the tanks are coated as a preventive action and the program includes periodic visual 

inspections that can detect loss of material.

The staff concludes that for LRA item 3.3.1-67 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).

3.3.2.1.10 Loss of Material Caused by General, Pitting, and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-69 addresses copper-alloy piping, piping components, and piping 

elements exposed to fuel oil, which will be managed for loss of material caused by general, 

pitting, crevice, and microbiologically-influenced corrosion. For the AMR item that cites generic 

note E, the LRA credits the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program to manage the aging effect for copper alloy valves. The SRL-LR 

recommends GALL Report AMP XI.M30, “Fuel Oil Chemistry,” and XI.M32, “One-Time 

Inspection,” to ensure that these aging effects are adequately managed. 
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The staff’s evaluation of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program is documented in SER Section 3.0.3.1.16. The staff noted that in its 

response to RAI B.2.1.26-2, dated February 15, 2012, the applicant stated, the environment 

associated with these components is dirty fuel oil, which has similar attributes to the waste 

water environment, which is monitored by the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components program. GALL Report Section IX.D states that the waste 

water environment contains contaminants, including oil and boric acid In its review of 

components associated with item 3.3.1-69 for which the applicant cited generic note E, 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 applicant has 

appropriately associated the fuel oil dirty drains as a waste water environment in that both oil 

and water are present in this piping, and GALL Report item AP-281 recommends that steel 

exposed to waste water be managed by the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components program for loss of material.

3.3.2.1.11 Loss of Material Caused by General, Pitting, and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-70 addresses copper-alloy piping, piping components, and piping 

elements exposed to fuel oil, which will be managed for loss of material caused by general, 

pitting, crevice, and microbiologically-influenced corrosion. For the AMR item that cites generic 

note E, the LRA credits the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program to manage the aging effect for copper alloy valves. The SRL-LR 

recommends GALL Report AMP XI.M30, “Fuel Oil Chemistry,” and XI.M32, “One-Time 

Inspection,” to ensure that these aging effects are adequately managed.

The staff noted that although the SRP-LR recommends the use of GALL Report AMP XI.M30, 

the staff evaluated the acceptability of not using the mitigative and condition monitoring aspect 

of this program because the components are associated with the dirty fuel oil drain piping in the 

emergency diesel generator system. This evaluation is documented in SER Section 3.0.3.1.16. 

The staff’s evaluation of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program is documented in SER Section 3.0.3.1.16. The staff noted that in its 

response to RAI B.2.1.26-2, dated February 15, 2012, the applicant stated that the environment 

associated with these components is dirty fuel oil, which has similar attributes to the waste 

water environment, which is monitored by the Internal Surfaces in Miscellaneous Piping and 

Ducting Components program. GALL Report Section IX.D states that the waste water 

environment contains contaminants, including oil and boric acid. In its review of components 

associated with item 3.3.1-70 for which the applicant cited generic note E, 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: (a) the applicant has 

appropriately associated the fuel oil dirty drains as a waste water environment in that both oil 

and water are present in this piping, and (b) GALL Report item AP-281 recommends that steel 

exposed to waste water be managed by the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components program for loss of material.

3.3.2.1.12 Hardening and Loss of Strength Because of Elastomer Degradation

LRA Table 3.3.1 item 3.3.1-76 addresses elastomers, elastomer seals, and components 

exposed to indoor, uncontrolled air that will be managed for hardening and loss of strength 
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caused by elastomer degradation. For the AMR item that cites generic note E, the LRA credits 

the Structures Monitoring program to manage the aging effect. The GALL Report recommends 

GALL Report AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” to 

ensure that these aging effects are adequately managed. 

GALL Report AMP XI.M36 recommends using periodic, not to exceed one refueling cycle, visual 

and physical manipulation inspection techniques to manage aging. The staff noted that the 

Structures Monitoring program proposes to manage the aging of elastomers, elastomer seals,

and components through the use of visual inspection techniques on a not to exceed 5-year 

inspection frequency. The staff also noted that plant procedures will be enhanced 

(Enhancement No. 9) to include physical manipulation to detect hardening when a vibration 

isolation function is suspect; however, it does not state that structural seal inspections will be 

augmented with physical manipulation.

In its review of components associated with item 3.3.1-76 for which the applicant cited generic 

note E, the staff lacked sufficient information to complete its evaluation. The inspection interval 

stated in the Structures Monitoring program is not to exceed 5 years; however, GALL Report 

AMP XI.M36 recommends that inspections occur on a frequency not to exceed one refueling 

cycle. In addition, Enhancement No. 9 does not include physical manipulation of structural 

seals. By letter dated January 18, 2012, the staff issued RAI 3.3.2.1.13-1 requesting the 

applicant to state the basis for why inspections conducted on a not to exceed 5-year interval will 

be sufficient to detect hardening and loss of strength in compressible joints and seals (including 

inflatable pool seals and gate seals) and state whether physical manipulation of elastomeric 

compressible joints and seals is included in the Structures Monitoring program, or state the 

basis for how hardening and loss of strength will be detected without physical manipulation.

In its response, dated February 16, 2012, the applicant stated that the elastomeric components 

referenced in the RAI include inflatable pool seals and gate seals consisting of the equipment pit 

stop log seals, cask pit gate seals, reactor cavity seals, and fuel pool gate and stop log seals, 

each of which is periodically replaced as a scheduled preventive maintenance activity. These 

seals will continue to be replaced on a scheduled basis throughout the period of extended 

operation and are considered to be within the scope of license renewal. They are short-lived 

components, however, and are, not subject to an AMR. The applicant also revised LRA 

Table 3.3.1, item 3.3.1-76 and LRA Table 3.5.2-13 to show that the components have been 

removed from AMR.

The staff finds the applicant’s response acceptable because given that the items are periodically 

replaced as a scheduled preventive maintenance activity, they are not considered to be 

long-lived and, therefore, are not required to be managed for aging. The staff’s concern 

described in RAI 3.3.2.1.13-1 is resolved.

The staff concludes that for LRA Table 3.3.1, item 3.3.1-76, 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).

3.3.2.1.13 Loss of Material

LRA Table 3.3.1, item 3.3.1-78 and 3.3.1-80 addresses carbon steel fire barrier doors and fire 

barrier penetration seals exposed externally to indoor, uncontrolled, and outdoor air that will be 
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managed for loss of material. The LRA credits the Fire Protection program, and cites generic 

note E, to manage the aging effect for carbon steel fire barrier doors and penetration seal. The 

GALL Report recommends GALL Report AMP XI.M36, “External Surfaces Monitoring of 

Mechanical Components,” program to ensure that these aging effects are adequately managed. 

GALL Report AMP XI.M36 recommends using visual inspections and walkdowns to manage 

aging.

The staff’s evaluation of the Fire Protection program is documented in SER 3.0.3.2.7. The staff 

noted that the Fire Protection program proposes to manage the aging of carbon steel fire barrier 

doors and fire barrier penetration seals through the use of periodic visual inspections and 

functional testing. In its review of components associated with item 3.3.1-78 and 3.3.1-80 for 

which the applicant credits the Fire Protection program, and cites generic note E, the staff finds 

the applicant’s proposal to manage aging acceptable because the frequency of monitoring and 

visual inspections is adequate to prevent significant degradation.

The staff concludes that for LRA Table 3.3.1, items 3.3.1-78 and 3.3.1-80 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).

3.3.2.1.14 Loss of Material

LRA Table 3.3.1, item 3.3.1-80 addresses steel heat exchange components, piping and piping 

components, and piping elements exposed externally to indoor, uncontrolled, and outdoor air. 

The LRA credits the Buried and Underground Piping and Tanks program to manage the aging 

effects for carbon steel and gray cast iron valve body, pump casing, piping, piping components, 

and piping elements located in underground vaults and cites note E for these AMR items. The 

GALL Report recommends GALL Report AMP XI.M36, “External Surfaces Monitoring of 

Mechanical Components,” program to ensure that these aging effects are adequately managed.

GALL Report AMP XI.M36 recommends using visual inspections and walkdowns to manage 

aging.

The staff’s evaluation of the Buried and Underground Piping and Tanks program is documented 

in SER Section 3.0.3.2.12. The staff noted that the Buried and Underground Piping and Tanks 

program proposes to manage the aging of carbon steel and gray cast iron valve body, pump 

casing, piping, piping components, and piping elements through the use of external coatings for 

external corrosion control, and inspections of the external surface of the components. In its 

review of components associated with LRA Table 3.3.1, item 3.3.1-80, for which the applicant 

cited generic note E, the staff finds the applicant’s proposal to manage aging using the Buried 

and Underground Piping and Tanks acceptable because the opportunistic visual inspections 

and inspection activities exceed the recommendations of GALL Report AMP XI.M36.

3.3.2.1.15 Hardening and Loss of Strength Caused by Elastomer Degradation

LRA Table 3.3.1, item 3.3.1-86 addresses elastomers, elastomer linings, elastomer seals, and 

components exposed to treated borated water, treated water, and raw water that will be 

managed for hardening and loss of strength caused by elastomer degradation. For the AMR 

item that cites generic note E, the LRA credits the Structures Monitoring program to manage the 

aging effect. The GALL Report recommends GALL Report AMP XI.M38, “Inspection of Internal 
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Surfaces in Miscellaneous Piping and Ducting Components,” to ensure that these aging effects 

are adequately managed. 

GALL Report AMP XI.M38 recommends using periodic opportunistic visual and physical 

manipulation inspection techniques to manage aging. The staff noted that the Structures 

Monitoring program proposes to manage the aging of elastomers, elastomer seals, and 

components through the use of visual inspection techniques on a not to exceed 5-year 

inspection frequency. The staff also noted that plant procedures will be enhanced 

(Enhancement No. 9) to include physical manipulation to detect hardening when a vibration 

isolation function is suspect; however, it does not state that structural seal inspections will be 

augmented with physical manipulation.

In its review of components associated with item 3.3.1-86 for which the applicant cited generic 

note E, the staff lacked sufficient information to complete its evaluation. The staff noted that 

Enhancement No. 9 does not include physical manipulation of structural seals. By letter dated 

January 18, 2012, the staff issued RAI 3.3.2.1.13-1 requesting the applicant to state whether 

physical manipulation of elastomeric compressible joints and seals is included in the Structures 

Monitoring program, or state the basis for how hardening and loss of strength will be detected 

without physical manipulation.

In its response, dated February 16, 2012, the applicant stated that the elastomeric components 

referenced in the RAI include inflatable pool seals and gate seals consisting of the equipment pit 

stop log seals, cask pit gate seals, reactor cavity seals, and fuel pool gate and stop log seals, 

each of which is periodically replaced as a scheduled preventive maintenance activity. These 

seals will continue to be replaced on a scheduled basis throughout the period of extended 

operation and are considered to be in-scope but short-lived components and, therefore, not 

subject to an AMR. The applicant also revised LRA Table 3.3.1, item 3.3.1-86 and LRA 

Table 3.5.2-13 to show that the components have been removed from AMR.

The staff finds the applicant’s response acceptable because given that the items are periodically 

replaced as a scheduled preventive maintenance activity, they are not considered to be 

long-lived and not required to be managed for aging. The staff’s concern described in 

RAI 3.3.2.1.13-1 is resolved.

The staff concludes that for LRA item 3.3.1-86, 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).

3.3.2.1.16 Loss of Material Caused by General, Pitting and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-89 addresses carbon steel piping, piping components, and pump 

casing exposed internally to wetted air or gas that will be managed for loss of material caused 

by general, 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 carbon 

steel piping, piping components, and pump casing. The GALL Report recommends GALL 

Report AMP Chapter XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components,” to ensure that these aging effects are adequately managed.
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GALL Report AMP XI.M38 recommends using visual inspections during periodic system and 

component surveillances, or maintenance activities when the surfaces are made accessible. 

The program uses standardized monitoring and trending activities to track degradation and 

identifies any abnormal surface condition as an indication of an aging effect for metals. The 

staff noted that the Open-Cycle Cooling Water System program proposes to manage the aging 

of piping, piping elements, and piping components of components in nonsafety-related raw 

water systems through the use of periodic inspections consistent with GL 89-13 in raw water 

cooling systems. The staff also noted that this program uses condition monitoring to manage 

the aging effect of loss of material. 

The staff’s evaluation of the Open-Cycle Cooling Water System program is documented in SER 

Section 3.0.3.2.4. In its review of components associated with item 3.3.1-89, for which the 

applicant cited generic note E, the staff finds the applicant’s proposal to manage aging using the 

Open-Cycle Cooling Water System program acceptable because the program includes visual 

periodic inspections and NDEs that are capable of detecting loss of material caused by general, 

pitting, and crevice corrosion. 

The staff concludes that for LRA item 3.3.1-89, 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).

3.3.2.1.17 Loss of Material Caused by Pitting and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-92 addresses aluminum piping, piping components, and piping 

elements exposed internally to condensation that will be managed for loss of material caused by

pitting and crevice corrosion. For the AMR items that cite generic note E, the LRA credits the 

Compressed Air Monitoring program to manage the aging effect for aluminum alloy piping, 

piping components, and piping elements exposed to wetter air or gas in the primary 

containment instrument gas system. The GALL Report recommends GALL Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,” to ensure that these aging effects are adequately managed. 

GALL Report AMP XI.M38 recommends using periodic opportunistic visual inspections of the 

internal surfaces to manage aging. The staff noted that the Compressed Air Monitoring 

program includes testing and inspection of the compressed air, primary containment instrument 

gas, and traversing in-core probe systems within the scope of license renewal and that the 

effects of corrosion and presence of contaminants are detected during system manager 

walkdowns, weekly surveillances, and preventive maintenance inspections of compressors, 

filters, accumulators, receivers, and drain traps. Additionally, the Compressed Air Monitoring 

program specifies maintaining moisture and other corrosive contaminants below acceptable 

limits through periodic samples and testing to mitigate loss of material.

The staff’s evaluation of the Compressed Air Monitoring program is documented in SER 

Section 3.0.3.1.9. In its review of components associated with item 3.3.1-92, for which the 

applicant cited generic note E, the staff did not have sufficient information to determine whether 

any of the preventive maintenance inspections of the Compressed Air Monitoring program will 

be conducted on aluminum alloy piping, piping components, and piping elements exposed to 

wetted air or gas. By letter dated January 18, 2012, the staff issued RAI 3.3.2.1.14-1 requesting 

the applicant to state whether any of the preventive maintenance inspections of the 
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Compressed Air Monitoring program will be conducted on aluminum alloy piping, piping 

components, and piping elements exposed internally to wetted air or gas, and, if not, to justify 

the use of the program for managing loss of materials for these aluminum items.

In its response, dated February 16, 2012, the applicant stated that preventative maintenance 

inspections are conducted on aluminum alloy piping, piping components, and piping elements 

exposed internally to wetted air or gas as part of the Compressed Air Monitoring program. The 

applicant further stated that the Compressed Air Monitoring program will perform periodic and 

opportunistic visual inspections of internal surfaces of components for signs of corrosion and 

abnormal corrosion products that indicate a loss of material. 

The staff finds the applicant’s response acceptable because the Compressed Air Monitoring 

program includes periodic and opportunistic visual inspections consistent with GALL Report 

AMP XI.M38 and these inspections are capable of detecting loss of material caused by pitting 

and crevice corrosion. The staff’s concern described in RAI 3.3.2.1.14-1 is resolved.

The staff concludes that for LRA item 3.3.1-92, 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).

3.3.2.1.18 Loss of Material Caused by General, Pitting, Crevice, and Microbiologically

Influenced Corrosion

LRA Table 3.3.1 item 3.3.1-106 addresses steel (with coating or wrapping) piping, piping 

components, and piping elements exposed to soil or concrete that will be managed for loss of 

material caused by general, pitting, crevice corrosion, and MIC. For the AMR items that cite 

generic note E, the LRA credits the Structures Monitoring program to manage the aging effect 

for steel (with coating or wrapping) piping, piping components, and piping elements. The GALL 

Report recommends GALL Report AMP XI.M41, “Buried and Underground Piping and Tanks,”

program to ensure that these aging effects are adequately managed. The staff noted that the 

applicant stated that the Structures Monitoring program will be used to manage the aging of the 

carbon steel and galvanized penetration sleeves in the diesel oil storage tank structures.

GALL Report AMP XI.M41 recommends using protective coatings, cathodic protection and 

backfill that is not deleterious to the pipe or pipe coatings to manage aging. GALL Report 

AMP XI.M41, Table 4a, footnote 6 states, “No inspections are necessary if all the piping 

constructed from the material under consideration is fully backfilled using controlled low strength 

material.” Based on review of plant drawings and specifications during the audit, and the 

UFSAR, the penetration sleeves are cathodically protected, coated, and backfilled with fillcrete, 

a cementitious controlled low-strength material; therefore, no inspections are required by GALL 

Report AMP XI.M41. The staff noted that the Structures Monitoring program proposes to 

manage the aging of carbon steel and galvanized penetration sleeves in the diesel oil storage 

tank structures, as documented in Enhancement No. 11, through the use of opportunistic 

inspections if excavations occur. 

The staff’s evaluation of the Structures Monitoring program is documented in SER 

Section 3.0.3.2.17. In its review of components associated with item 3.3.1-106, for which the 

applicant cited generic note E, the staff finds the applicant’s proposal to manage aging using the 

Structures Monitoring program acceptable because the opportunistic visual inspections exceed 
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the recommendations of GALL Report AMP XI.M41. Furthermore, the sleeves are coated, 

cathodically protected, and backfilled with acceptable material. 

The staff concludes that for LRA item 3.3.1-106, 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).

3.3.2.1.19 Conclusion

The staff evaluated the GALL Report AMR items that the applicant claimed were not applicable. 

On the basis of its review, the staff concludes that the AMR results that the applicant claimed 

were not applicable are not applicable to LGS Units 1 and 2.

As discussed in SER Section 3.0.2.2, for those AMRs that the applicant claimed consistency 

with the GALL Report, the staff evaluated the applicant’s claim of consistency. The staff also 

reviewed information pertaining to the applicant’s consideration of recent operating experience 

and proposals for managing aging effects. On the basis of its review, the staff concludes that 

the AMR results, which the applicant claimed to be consistent with the GALL Report, are 

consistent.

Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their 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 evaluates aging management, as recommended by 

the GALL Report, for the auxiliary system components and provides information concerning how 

it will manage the following aging effects:

 • cumulative fatigue damage

 • cracking caused by SCC and cyclic loading

 • cracking caused by SCC

 • loss of material caused by cladding breach

 • loss of material caused by pitting and crevice corrosion

 • QA for aging management of nonsafety-related components

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.
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3.3.2.2.1 Cumulative Fatigue Damage 

LRA Section 3.3.2.2.1, which is associated with LRA Table 3.3.1, items 3.3.1-1 and 3.3.1-2, 

addresses how steel cranes structural girders exposed to indoor, uncontrolled air, and steel and 

stainless steel piping, piping components, piping elements, and heat exchanger components 

exposed to indoor, uncontrolled air, treated borated water or treated water are being managed 

for cumulative fatigue damage. 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, and are required to be 

evaluated in accordance with 10 CFR 54.21(c). The applicant stated that fatigue TLAA 

identified for Class 2 and 3 piping are discussed in LRA Section 4.3, and the evaluation of crane 

load cycles as a TLAA for cranes is discussed in LRA Section 4.6.

The staff reviewed LRA Section 3.3.2.2.1 against the criteria in SRP-LR Section 3.3.2.2.1, which 

states that fatigue of these auxiliary system components is a TLAA as defined in 10 CFR 54.3, 

and that these TLAAs are to be evaluated in accordance with 10 CFR 54.21(c)(1) and SRP-LR 

Sections 4.3 and 4.7. The staff also reviewed the AMRs items associated with LRA 

Section 3.3.2.2.1 and found that the AMR results are consistent with the GALL Report and 

SRP-LR.

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.3.2.2.1 criteria. For those items that apply to LRA Section 3.3.2.2.1, the staff 

determined 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). SER Sections 4.3 and 4.6 document the staff’s review of 

the applicant’s evaluation of the TLAA for these components.

3.3.2.2.2 Cracking Caused by 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 

stainless steel heat exchanger components exposed to treated borated water. The applicant 

stated that this item is not applicable because item 3.3.1-3 applies to PWRs. The staff 

evaluated the applicant’s claim and finds it acceptable because treated borated water only 

applies to PWRs and the applicant is managing cracking of stainless steel heat exchanger 

components exposed to treated water through item 3.3.1-20, which applies to BWRs.

3.3.2.2.3 Cracking Caused by Stress Corrosion Cracking 

LRA Section 3.3.2.2.3, associated with LRA Table 3.3.1, item 3.3.1-4 addresses stainless steel 

piping, piping components, piping elements, and tanks exposed to outdoor air, which will be 

managed for stress corrosion cracking. The criteria in the SRP-LR states that either the 

applicant justifies that the aging effect is not applicable by describing the outdoor air 

environment present at the plant and demonstrating that stress corrosion cracking is not 

expected, or GALL Report AMP XI.M36, “External Surfaces Monitoring of Mechanical 

Components,” is used to manage cracking caused by SCC for this component group. The 

applicant addressed the further evaluation criteria of the SRP-LR by stating that, “SCC of 

stainless steels exposed to outdoor air and contaminants is considered plausible only if the 

material temperature is above 140 °F. For the Auxiliary Systems, the outdoor stainless steel 

components are less than 140 °F.” 
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In its review of components associated with item 3.3.1-4, the staff noted that the environment is 

periodically subject to wetting (e.g., condensation, rain) which could introduce halides 

(e.g., cooling tower drift), which are known to contribute to SCC. LRA Section 2.4.7 further 

states that two circulating water chlorine and acid feed enclosures are used to maintain the 

chemical properties of the cooling tower basins, which can also contribute to halides in 

condensation. By letter dated January 17, 2012, the staff issued RAI B.2.1.25-1, requesting that 

the applicant provide technical justification as to why the LRA AMP does not consider SCC to 

be an aging effect requiring management for the stainless steel components in the auxiliary 

systems that are subjected to wet external environments.

In its response dated February 15, 2012, the applicant stated that although chlorine, as sodium 

hypochlorite, is added to the water in the cooling towers, prevailing wind direction is such that 

the cooling tower plume is directed away from the plant, a review of plant operating experience 

has revealed no occurrences of cracking in outdoor stainless steel components, and recent 

inspections performed on the external surfaces of large outdoor stainless steel components 

have revealed that these components are in good material condition. The applicant revised its 

response to the further evaluation criteria of the SRP-LR by stating that this item is not 

applicable because LGS is located more than 80 miles from the Atlantic coast and major 

transportation routes near the site are at least a mile away.

The staff does not find the response to RAI B.2.1.25-1 to be acceptable because experimental 

studies and industry operating experience in chloride-containing (coastal) environments have 

shown that stainless steels exposed to an outdoor air environment can crack at temperatures as 

low as 104 to 120 °F, depending on humidity, component surface temperature, and contaminant 

concentration and composition. The staff noted that while the experimental studies 

demonstrated that cracking can occur in 4 to 52 weeks, the industry operating experience 

failures did not necessarily occur early in plant life and therefore, the staff cannot conclude that 

recent inspections are sufficient to demonstrate an aging effect will not occur during the period 

of extended operation. By letter dated June 12, 2012, the staff issued followup RAI B.2.1.25-1.1 

requesting that the applicant state the basis for why the chemical compounds in the cooling 

tower plume cannot result in SCC if plume fallout (regardless of prevailing wind direction) 

accumulates on the external surfaces of stainless steel piping within the scope of license 

renewal and why chloride contamination is not expected to accumulate on stainless steel

components within the scope of license renewal from the soil or nearby agricultural and 

industrial sources.

In its response dated June 19, 2012, the applicant stated that SCC is not likely to occur because 

local temperatures have not exceeded 104 °F and only exceeded 100 °F on 2 days in the last 

10 years. In addition, the applicant stated that they were not in a coastal environment. The 

applicant did not respond to the potential for chloride contamination arising from agricultural or 

industrial sources; however, it revised the External Surfaces Monitoring of Mechanical 

Components program to manage stainless steel components in an outdoor air environment for 

SCC. The applicant stated that components that are jacketed or located in underground vaults 

would not be managed for SCC because they are shielded from accumulation of contaminants 

in the atmosphere. The applicant revised LRA Sections A.2.1.25, B.2.1.25, 3.3.2.1.22, 

3.3.2.2.3, and LRA Tables 3.3.1 (item 3.3.1-4), 3.3.2-8, and 3.3.2-22 accordingly.

The staff finds the applicant’s response to RAI B.2.1.25-1.1 acceptable because the applicant 

will manage SCC of stainless steel components exposed to outdoor air using the External 

Surfaces Monitoring of Mechanical Components program, components that are jacketed or in 
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underground vaults would not be exposed to sufficient quantities of atmospheric chlorides to 

cause SCC because they are protected from direct fallout by the intervening materials, the 

visual inspections of this program are capable of detecting SCC, and managing the aging of 

these AMR items in this manner is consistent with the GALL Report.

3.3.2.2.4 Loss of Material Caused by 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 caused by 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; therefore, the staff finds the applicant’s determination acceptable.

3.3.2.2.5 Loss of Material Caused by Pitting and Crevice Corrosion

LRA Section 3.3.2.2.5, associated with LRA Table 3.3.1, item 3.3.1-6, addresses stainless steel 

piping, piping components, piping elements, and tanks exposed to outdoor air that will be 

managed for loss of material caused by pitting and crevice corrosion by the External Surfaces 

Monitoring of Mechanical Components and the Buried and Underground Piping and Tanks

programs. The criterion in SRP-LR Section 3.3.2.2.5 item 1 states that loss of material caused 

by pitting and crevice corrosion could occur for stainless steel piping, piping components, piping 

elements, and tanks exposed to outdoor air. The applicant addressed the further evaluation 

criteria of the SRP-LR by stating that any visible evidence of loss of material will be evaluated 

and entered into the CAP. Additionally, the Buried and Underground Piping and Tanks program 

will be used to manage the loss of material in stainless steel valve bodies located underground 

in vaults in the safety-related SW system.

The staff’s evaluation of the External Surfaces Monitoring of Mechanical Components program 

is documented in SER Section 3.0.3.1.15 and Underground Piping and Tanks program is 

documented in SER Section 3.0.3.2.12. The staff finds that the applicant has met the further 

evaluation criteria, and the applicant’s proposal to manage aging using the External Surfaces 

Monitoring of Mechanical Components program is acceptable because it provides for 

management of aging effects through periodic visual inspection of external surfaces for 

evidence of loss of material. Furthermore, the staff noted that the Buried and Underground 

Piping and Tanks program proposes to manage aging through the use of external coatings for 

external corrosion control, the application of cathodic protection, and the quality of backfill 

used. The staff finds the applicant’s proposal to manage aging of stainless steel valve bodies 

located underground in vaults using the Buried and Underground Piping and Tanks program is 

acceptable because the opportunistic visual inspections and inspection activities exceed the 

recommendations of GALL Report AMP XI.M36.

3.3.2.2.6 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.

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

For LRA Tables 3.3.2-1 through 3.3.2-26, the staff reviewed additional details of the AMR 

results for material, environment, AERM, and AMP combinations not consistent with or not 

addressed in the GALL Report.
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In LRA Tables 3.3.2-1 through 3.3.2-26, the applicant, by notes F through J, indicated 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.

3.3.2.3.1 Auxiliary Steam – 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 

auxiliary steam system component groups. The staff’s review did not identify any items with 

notes F through J, indicating that the combinations of component type, material, environment,

and AERM for this system are consistent with the GALL Report.

3.3.2.3.2 Closed Cooling Water – 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 

closed cooling water system component groups.

In LRA Table 3.3.2-2, the applicant stated that the carbon steel piping components internally 

exposed to closed cycle cooling water will be managed for loss of material caused by cavitation 

erosion by the Closed Treated Water Systems program. The AMR item cites generic note H 

and plant-specific note 1, which states the loss of material caused by cavitation erosion has 

been identified in the reactor enclosure cooling water piping. This item was added by letter,

dated February 15, 2012, in response to RAI B.2.1.13-2. The plant-specific note also states that 

the Closed Treated Water Systems program has been enhanced to include periodic NDE to 

manage this aging mechanism.

The staff noted that this material and environment combination is identified in the GALL Report, 

that addresses carbon steel piping exposed to closed cycle cooling water and recommends the 

Closed Treated Water Systems program to manage loss of material; however, the applicant has 

identified this additional aging effect caused by this unique aging mechanism that requires 

monitoring activities beyond those in the GALL Report AMP. The applicant addressed the 

GALL Report identified aging effects for this component, material, and environment combination 

in AMR items in LRA Table 3.3.2-2.

The staff’s evaluation of the Closed Treated Water Systems program is documented in SER 

Section 3.0.3.2.5. The staff finds the applicant’s proposal to manage aging using the above 
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program acceptable because, as discussed in SER Section 3.0.3.2.5, the applicant enhanced 

the program to include periodic NDE, which is capable of trending loss of material associated 

with cavitation erosion.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.3.2.3.3 Compressed Air – 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 component groups.

In LRA Tables 3.3.2-3, 3.3.2-4, 3.3.2-7, 3.3.2-8, 3.3.2-16, 3.3.2-20, and 3.3.2-23, the applicant 

stated that elastomer hoses, ducting and components, and flexible connections exposed 

internally to wetted air or gas will be managed for loss of material and hardening and loss of 

strength 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. The staff noted that the LRA Table 3.0-1 states that 

air/gas environments contain significant amounts of moisture where condensation or water 

pooling may occur. Based on its review of the GALL Report, which states that elastomers 

exposed to a water environment (e.g., raw water, treated water, and closed cycle cooling water) 

are subject to loss of material and hardening and loss of strength, 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 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program is documented in SER Section 3.0.3.1.16. 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 program uses periodic opportunistic 

visual inspections in conjunction with manual or physical manipulation of at least 10 percent of 

the available surface area, which is an appropriate and effective technique for determining aging 

effects of elastomers.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.3.2.3.4 Control Enclosure Ventilation - 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 enclosure ventilation system component groups.
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The staff’s evaluation for elastomer hoses, ducting and components, and flexible connections 

exposed internally to wetted air or gas that will be managed for loss of material and hardening 

and loss of strength by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program and that cite generic note G, is documented in 3.3.2.3.3.

In LRA Tables 3.3.2-4, 3.3.2-8, and 3.3.2-20, the applicant stated that copper, aluminum, and 

copper alloy with less than 15 percent zinc, heat exchanger components exposed externally to 

wetted air or gas 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 H.

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 LRA Table 3.0-1 states that air or 

gas environments contain significant amounts of moisture where condensation or water pooling 

may occur. The staff also noted that the applicant also addressed loss of material for this 

component, material, and environment combination in AMR items in LRA Tables 3.2.2-3, 

3.2.2-4, and 3.2.2-5; LRA Tables 3.3.2-1, 3.3.2.-2, 3.3.2-4, 3.3.2-8, 3.3.2-12, 3.3.2-16, 3.3.2-20, 

and 3.3.2-22; and LRA Table 3.4.2-3. Based on its review of the GALL Report, which states 

that copper and copper alloy heat exchanger components exposed to water (e.g., closed-cycle 

cooling water, raw water, and treated water) are subject to the aging effects of loss of heat 

transfer and loss of material and that aluminum exposed to condensation is subject to 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 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program is documented in SER Section 3.0.3.1.16. The staff lacked sufficient 

information to conclude that the applicant’s program is adequate to manage these material, 

environment, and aging combinations because loss of heat transfer is not included within the 

applicant’s AMP. By letter dated January 17, 2012, the staff issued RAI B.2.1.26-1 requesting 

the applicant to revise the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program to include the program’s aging effects of loss of fracture toughness, 

reduction of heat transfer, and cracking. The applicant is also requested to including the 

appropriate details such as parameters to be monitored, acceptance criteria, and detection of 

aging effect elements necessary to support this program’s additional aging effects.

In its response, dated February 15, 2012, the applicant stated that LRA AMP B.2.1.26 and LRA 

UFSAR supplement Section A.2.1.26 were revised (per Enclosure B of the letter) and loss of 

fracture toughness, reduction of heat transfer, and cracking were added to those LRA Sections. 

The applicant also stated that loss of fracture toughness is applied to the ASME Class 3, B and 

C RWCU pump casings that are not applicable to the requirements of GALL Report 

AMP XI.M12, “Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS),”

because GALL Report AMP XI.M12 only applies to ASME Code, Class 1 components. The 

applicant also stated that the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components program will use visual inspections for these components to monitor for 

cracking, which follows the inspection and monitoring guidelines found to manage this aging 

effect in GALL Report AMP XI.M12. The applicant also stated that reduction of heat transfer 

aging effects will be managed for the reactor enclosure and control enclosure ventilation system 

coolers, and the EDG system combustion air coolers using visual inspections. The applicant 
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also stated that cracking will be managed for stainless steel components in the waste water 

greater than 140 °F environment. The applicant also stated that these components are in a 

more aggressive environment than environments addressed by GALL Report AMP XI.M32, 

One-Time Inspection program; therefore, the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components program and visual inspections will be used to manage the 

aging effect. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.3.2.3.5 Control Rod Drive – 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 

CRD system component groups. The staff’s review did not identify any items with notes F 

through J, indicating that the combinations of component type, material, environment, and 

AERM for this system are consistent with the GALL Report.

3.3.2.3.6 Cranes and Hoists – 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 and hoists component groups. The staff’s review did not identify any items with 

notes F through J, indicating that the combinations of component type, material, environment, 

and AERM for this system are consistent with the GALL Report.

3.3.2.3.7 Emergency Diesel Generator Enclosure Ventilation – 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 

Emergency Diesel Generator Enclosure Ventilation component groups.

The staff’s evaluation for elastomer hoses, ducting and components, and flexible connections 

exposed internally to wetted air or gas that will be managed for loss of material and hardening 

and loss of strength by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program and cite generic note G, is documented in 3.3.2.3.3.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.3.2.3.8 Emergency Diesel Generator - 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 

EDG component groups.
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The staff’s evaluation for copper, aluminum, and copper alloy less than 15 percent zinc heat 

exchanger components exposed externally to wetted air or gas that will be managed for 

reduction of heat transfer by the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components program and cite generic note H, is documented in 3.3.2.3.4.

The staff’s evaluation for elastomer hoses, ducting and components, and flexible connections 

exposed internally to wetted air or gas that will be managed for loss of material and hardening 

and loss of strength by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program and cite generic note G, is documented in 3.3.2.3.3.

In LRA Table 3.3.2-8, the applicant stated that elastomer hoses exposed internally to lubricating 

oil will be managed for hardening and loss of strength by the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program. The AMR item cites 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. The staff noted that the LRA Table 3.0-1 states that air 

or gas environments contain significant amounts of moisture where condensation or water 

pooling may occur. Based on its review of the GALL Report Section IX.C, which states that 

hardening and loss of strength for elastomers can be induced by elevated temperatures over 

about 95 °F (35° C), 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 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program is documented in SER Section 3.0.3.1.16. 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 program includes visual inspections 

supplemented with physical and manual manipulation of elastomers, which is a technique that 

adequately identify if this aging effect is occurring. 

In LRA Table 3.3.2-8, the applicant stated there is a TLAA for carbon steel piping, piping 

components, and piping elements exposed to diesel exhaust that cites generic note H. The 

staff confirmed that there is a TLAA, as documented in LRA Section 4.3.2, for these 

components and material. The staff’s evaluation of the fatigue TLAA for ASME Code Section III 

Class 2 and 3 and ANSI B31.1 components is documented in SER Section 4.3.2.

By letter dated February 15, 2012, LRA Tables 3.3.2-8 and 3.3.2-22 were amended and the 

applicant stated that for stainless steel piping, piping components, piping elements, spray 

nozzles, and valve body exposed to outdoor air no AERM or AMP is proposed. The AMR items 

cite generic note I. Items associated with 3.3.2-8 and 3.3.2-22 cite plant-specific note 6 and 3,

which state that based on plant-specific environmental conditions and operating experience,

cracking is not an applicable aging effect since outdoor environments are not conducive to SCC. 

The staff reviewed the associated items in the LRA to confirm that no aging effect is applicable 

for this component, material, and environmental combination. The staff’s evaluation is 

documented in SER Section 3.3.2.2.3.

By letter dated March 13, 2012, the applicant revised LRA Table 3.3.2-8 to include copper alloy 

with 15-percent zinc or more valve bodies internally exposed to wetted air or gas that will be 

managed for loss of material by the Selective Leaching program. The AMR items cites generic 
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note H and plant-specific note 7, which states, in part, that the component is exposed to an 

environment containing significant amounts of moisture where condensation or water pooling 

may occur, resulting in the loss of material caused by selective leaching.

The staff reviewed the associated item in the LRA and considered whether the aging effect 

proposed by the applicant constitutes all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant also addressed loss of 

material (caused by general, pitting, and crevice corrosion) for this component, material, and 

environment combination in AMR items in LRA Table 3.3.2-8 and proposed the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components program. The staff’s 

evaluation of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program is documented in SER Section 3.0.3.1.16. Based on its review of the 

GALL Report, which states that copper alloy with 15-percent zinc or more is vulnerable to loss 

of material caused by general, pitting, or crevice corrosion in moist air environments, and is also 

susceptible to selective leaching in a raw water environment, 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 Selective Leaching program is documented in SER 

Section 3.0.3.1.13. The staff finds the applicant’s proposal to manage aging using the Selective 

Leaching program acceptable because the program will use a one-time inspection, comprising 

both visual and mechanical techniques of a sample of components to identify and confirm 

existence of the loss of material because of selective leaching.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.3.2.3.9 Fire Protection – 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 

Fire Protection component groups.

In LRA Table 3.3.2-9, the applicant stated that the soil (asphalt covered) dikes exposed 

externally to outdoor air will be managed for loss of material or loss of form by the Structures 

Monitoring program. The AMR item cites generic note F and plant-specific note 1. 

Plant-specific note 1 states that this component is a soil dike covered with asphalt, intended to 

contain oil spills. The aging effects are similar to those in the GALL Report item III.A6.T-22 for 

earthen water-control structures. The Structures Monitoring program is credited for managing 

the aging effects for this component.

The staff noted that this material and environment combination are similar to that identified in 

the GALL Report item III.A6.T-22, which addresses earthen water-control structures exposed to 

water flowing or standing and recommends GALL Report AMP XI.S7, “Regulatory Guide 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants,” or the Federal 

Emergency Regulatory Commission (FERC) US Army Corps of Engineers dam inspections and 

maintenance programs to manage these aging effects. Based on its review of the GALL 

Report, which identified aging effects for this component, material, and environment 
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combination, 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 Structures Monitoring program is documented in SER 

Section 3.0.3.2.17. The staff noted that under the Structures Monitoring program structures and 

structural components are inspected by qualified personnel in accordance with station 

procedures that will be enhanced for consistency with ACI 349.3R-02. The staff also noted that 

the structures and structural components are inspected for indications of deterioration and 

distress, including evidence of leaching, loss of material, cracking, and loss of bond as identified 

in ACI 201.1R, “Guide for Making a Condition Survey of Existing Buildings.” The staff further 

noted that the Structures Monitoring program addresses environments of uncontrolled indoor 

and outdoor air, treated water, raw water, water-flowing, and ground water and soil, and 

inspections are performed at a frequency not to exceed 5 years. The staff finds the applicant’s 

proposal to manage aging using the Structures Monitoring program acceptable because the soil 

(asphalt covered) dikes will be managed for loss of material or loss of form through inspections 

by qualified personnel, at inspection intervals not to exceed 5 years, in accordance with station 

procedures that have been enhanced for consistency with ACI 349.3R-02.

In LRA Table 3.3.2-9, the applicant stated that Darrmatt, Thermolag, and Cafecote fire barriers 

exposed externally to uncontrolled indoor air will be managed for loss of material and cracking 

by the Fire Protection program. The AMR items cite generic note F.

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 Darmatt, Thermolag, and Cafecote 

are typical fire-resistant materials used to provide fire protection for equipment and structures. 

NUREG-1924 describes Darmatt as a flexible insulating board hydrate fire barrier and 

Thermolag as an ablative water-based fire barrier that can be a prefabricated board or spray-on 

fireproofing material. During the audit, the applicant clarified that the Cafecote material 

referenced in the LRA is also called Cafco. Cafco is a cementitious spray-on fire resistant 

material (www.isolatek.com/datasheets.asp). Although Darmatt, Thermolag, and Cafco are not 

specifically mentioned in the GALL Report, AMP XI.M26, “Fire Protection,” does state that the 

program includes management of loss of material and cracking for fire barrier walls, ceilings, 

floors, and other fire resistant materials, such as flamastic, 3M firewrapping, and spray-on and 

intumescent coatings. Based on its review of GALL Report AMP XI.M26, NUREG-1924, and 

industry guidance, the staff finds that the applicant has identified all credible aging effects for 

this component, material, and environment combination because Darmatt, Thermolag, and 

Cafco have a similar form, function, and composition as the fire-resistant coatings listed in the 

GALL Report AMP, and, therefore, are subject to the same aging effects.

The staff’s evaluation of the Fire Protection program is documented in SER Section 3.0.3.2.7. 

The staff finds the applicant’s proposal to manage aging using the Fire Protection program 

acceptable because it includes periodic visual inspections that are capable of detecting loss of 

material and cracking in various fire barrier materials.

In LRA Table 3.3.2-9, the applicant stated there is a TLAA for carbon steel piping, piping 

components, and piping elements exposed to diesel exhaust that cites generic note H. The 

staff confirmed that there is a TLAA, as documented in LRA Section 4.3.2, for these 

components and material. The staff’s evaluation of the fatigue TLAA for ASME Code Section III 

Class 2 and 3 and ANSI B31.1 components is documented in SER Section 4.3.2.
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By letter dated February 15, 2012, the applicant amended LRA Table 3.3.2-9 to include alumina 

silica and gypsum fire barriers exposed externally to uncontrolled indoor air that will be 

managed for cracking by the Fire Protection program. The AMR items cite generic note F.

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 alumina silica and gypsum are 

typical fire-resistant materials used to provide fire protection for equipment and structures. 

Although these materials are not specifically mentioned in the GALL Report, AMP XI.M26, “Fire 

Protection,” does state that the program includes management of loss of material and cracking 

for fire barrier walls, ceilings, floors, and other fire-resistant materials, such as flamastic, 3M 

firewrapping, and spray-on and intumescent coatings. Based on its review of GALL Report 

AMP XI.M26, the staff noted that the applicant could have also identified loss of material as an 

applicable aging effect for this component, material, and environment combination because 

alumina silica and gypsum have a similar form, function, and composition as the fire-resistant 

coatings listed in the GALL Report AMP, and, therefore, are subject to the same aging effects. 

However, the staff also noted that loss of material in alumina silica and gypsum materials would 

not be caused by the same mechanisms as for metallic components and could be identified 

using the same inspection methods used to identify cracking.

The staff’s evaluation of the Fire Protection program is documented in SER Section 3.0.3.2.7. 

The staff noted that the Fire Protection program uses visual inspections to identify cracking and 

that any loss of material would be identified during these visual inspections. The staff finds the 

applicant’s proposal to manage aging using the Fire Protection program acceptable because the 

program includes periodic visual inspections capable of detecting loss of material and cracking 

in various fire barrier materials.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.3.2.3.10 Fuel Handling and Storage - 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 fuel handling and storage component groups. The staff’s review did not identify any items 

with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for this system are consistent with the GALL Report.

3.3.2.3.11 Fuel Pool Cooling and Cleanup – 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 Fuel Pool Cooling and Cleanup component groups.
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In LRA Table 3.3.2-11, the applicant stated that nickel alloy expansion joints exposed internally 

to treated water will be managed for loss of material by the Water Chemistry and One-Time 

Inspection programs. 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 Metals Handbook, 

Volume 13, “Corrosion,” which states that nickel alloy materials are not susceptible to cracking 

at temperatures associated with the spent fuel pool cooling (approximately 140 °F), the staff 

finds the applicant has identified all credible aging effects for this component, material, and

environment combination. 

The staff’s evaluations of the Water Chemistry and One-Time Inspection programs are 

documented in SER Sections 3.0.3.1.2 and 3.0.3.1.12, respectively. The staff finds the 

applicant’s proposal to manage aging using the above programs acceptable, because the Water 

Chemistry program maintains contaminants at levels to minimize loss of material caused by

corrosion, and the One-Time Inspection program will verify the effectiveness of the Water 

Chemistry program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.3.2.3.12 Nonsafety-Related Service Water – 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 nonsafety-related SW system component groups. The staff’s review did not identify any 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for this system are consistent with the GALL Report.

3.3.2.3.13 Plant Drainage – 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 Plant Drainage component groups.

In LRA Table 3.3.2-13, the applicant stated that stainless steel bolting exposed to wetted air or 

gas will be managed for loss of preload by the Bolting Integrity program. The AMR item cites 

generic note H. This item cites plant-specific note 1, which states that the bolting is in the 

airspace of the reactor enclosure sumps.

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 also addressed loss of 

material for this component, material, and environment combination in AMR items in LRA 

Table 3.3.2-13. The staff notes that GALL Report item EP-120 states that loss of preload is an 

appropriate aging effect for stainless steel bolting exposed to treated water, an environment 

similar to wetted air or gas from a preload perspective, and there are no bolting items for loss of 
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material in a wetted air or gas environment identified in the GALL Report. However, for 

exposure to soil, an environment that can include moisture, loss of material is listed as an aging 

effect in the GALL Report. Therefore, 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 Bolting Integrity program is documented in SER Section 3.0.3.2.3. 

The staff finds the applicant’s proposal to manage aging using the Bolting Integrity program

acceptable because the program includes periodic inspections of bolting for loss of preload and 

preventive measures such as the use of lubricants and proper torque values for installing bolting 

so that an appropriate preload can be maintained.

In LRA Table 3.3.2-13, the applicant stated that gray cast iron piping, piping components, and 

piping elements internally exposed to waste water will be managed for loss of material by the 

Selective Leaching program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and considered whether the aging effect 

proposed by the applicant constitutes all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant also addressed loss of 

material (caused by general, pitting, crevice, and MIC) for this component, material, and 

environment combination in AMR items in LRA Table 3.3.2-13 and proposed the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components program. The staff’s 

evaluation of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components is documented in SER Section 3.0.3.1.16. Based on its review of the GALL 

Report, which states that in certain environments gray cast iron is vulnerable to loss of material 

caused by general, pitting crevice corrosion, and MIC, and is also susceptible to selective 

leaching, 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 Selective Leaching program is documented in SER 

Section 3.0.3.1.13. The staff finds the applicant’s proposal to manage aging using the Selective 

Leaching program acceptable because the program will use a one-time inspection, comprising 

both visual and mechanical techniques of a sample of components to identify and confirm 

existence of the loss of material caused by selective leaching.

In LRA Table 3.3.2-13, the applicant stated that stainless steel piping, piping components, 

piping elements and valve bodies exposed externally to wetted air or gas will be managed for 

loss of material by the External Surfaces Monitoring of Mechanical 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 stainless steel components exposed to wetted air or gas 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 External Surface Monitoring of Mechanical Components program is 

documented in SER Section 3.0.3.1.15. The staff finds the applicant’s proposal to manage 

aging using the External Surfaces Monitoring of Mechanical Components program acceptable 
3-314

because the program includes visual inspections capable of detecting loss of material in 

stainless components exposed externally to wetted air or gas.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.3.2.3.14 Primary Containment Instrument Gas – 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 Primary Containment Instrument Gas component groups.

The staff’s evaluation for zinc valve bodies exposed to uncontrolled indoor air, which has no 

aging effect and for which no AMP is proposed, is documented in SER Section 3.2.2.3.2.

In LRA Table 3.3.2-14, the applicant stated that there is no aging effect for zinc valve bodies 

exposed internally to dry air or gas and no AMP is proposed. The AMR items cite generic 

note F and plant-specific note 2, which states that zinc die cast has no aging effects in a dry air 

or gas environment.

The staff reviewed the associated items in the LRA to confirm that no credible aging effects are 

applicable for this component, material, and environment combination. The staff finds the 

applicant’s proposal acceptable based on its review of the Metals Handbook, Desk Edition, 2nd 

Edition, which states zinc has a high degree of atmospheric corrosion resistance because of the 

formation of carbonate films. Also, the GALL Report item V.F.EP-14 states that galvanized 

(zinc-coated) steel has no aging effect in a controlled indoor air environment, which, like the 

air/gas-dry environment, is controlled to low humidity levels. 

By letter dated March 13, 2012, the applicant revised LRA Table 3.3.2-14 to include gray cast 

iron piping, piping components, and piping elements internally exposed to wetted air or gas that 

will be managed for loss of material by the Selective Leaching program. The AMR items cites 

generic note H and plant-specific note 3, which states, in part, that the component is exposed to 

an environment containing significant amounts of moisture where condensation or water pooling 

may occur, resulting in the loss of material caused by selective leaching.

The staff reviewed the associated item in the LRA and considered whether the aging effect 

proposed by the applicant constitutes all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant also addressed loss of 

material (caused by general, pitting, and crevice corrosion) for this component, material, and 

environment combination in AMR items in LRA Table 3.3.2-14 and proposed the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components program. The staff’s 

evaluation of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program is documented in SER Section 3.0.3.1.16. Based on its review of the 

GALL Report, which states that gray cast iron is vulnerable to loss of material caused by

general, pitting, and crevice corrosion in moist air environments, and is also susceptible to 

selective leaching in a raw water environment, the staff finds that the applicant has identified all 

credible aging effects for this component, material, and environment combination.
3-315

The staff’s evaluation of the Selective Leaching program is documented in SER 

Section 3.0.3.1.13. The staff finds the applicant’s proposal to manage aging using the Selective 

Leaching program acceptable because the program will use a one-time inspection, comprising 

both visual and mechanical techniques of a sample of components to identify and confirm 

existence of the loss of material caused by selective leaching.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.3.2.3.15 Primary Containment Leak Testing – 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 primary containment leak testing component groups. The staff’s review did not identify any 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for this system are consistent with the GALL Report.

3.3.2.3.16 Primary Containment Ventilation – 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 Primary Containment Ventilation component groups.

The staff’s evaluation for elastomer hoses, ducting and components, and flexible connections 

exposed internally to wetted air or gas, which will be managed for loss of material and 

hardening and loss of strength by the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components program and cites generic note G, is documented in 3.3.2.3.3.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.3.2.3.17 Process Radiation Monitoring – 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 process radiation monitoring component groups. The staff’s review did not identify any 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for this system are consistent with the GALL Report.
3-316

3.3.2.3.18 Process and Post-Accident Sampling - 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 and Post-Accident Sampling component groups. The staff’s review did not identify 

any items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for this system are consistent with the GALL Report.

3.3.2.3.19 Radwaste – 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 Radwaste component groups.

In LRA Table 3.3.2-19, the applicant stated that stainless steel piping, piping components and 

piping elements, tanks and valve body exposed internally to waste water greater than 140 °F

will be managed for cracking 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 stainless steel in water environments greater than 140 °F of closed-cycle cooling water, 

treated borated water, and treated water are subject to 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 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program is documented in SER Section 3.0.3.1.16. The staff lacked sufficient 

information to conclude that the applicant’s program is adequate to manage these materials, 

environment, and aging combinations because the LRA did not include cracking within the 

applicant’s AMP. By letter dated January 17, 2012, the staff issued RAI B.2.1.26-1 requesting 

the applicant to revise the LRA AMP to include the program’s aging effects of loss of fracture 

toughness, reduction of heat transfer, and cracking. The applicant is also requested to include 

the appropriate details such as parameters to be monitored, acceptance criteria, and detection 

of aging effect elements necessary to support this program’s additional aging effects.

In its response, dated February 15, 2012, the applicant stated that LRA AMP B.2.1.26 and LRA 

UFSAR supplement Section A.2.1.26 were revised (per Enclosure B of the letter) and loss of 

fracture toughness, reduction of heat transfer, and cracking were added to those sections of the 

LRA. The applicant also stated that loss of fracture toughness is applied to the ASME Code, 

Class 3, B and C RWCU pump casings that are not applicable to the requirements of GALL 

Report AMP XI.M12, “Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS),”

because GALL Report AMP XI.M12 only applies to ASME Code Class 1 components. The 

applicant also stated that the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components program will use visual inspections for these components to monitor for 

cracking that follows the inspection and monitoring guidelines found to manage this aging effect 

in GALL Report AMP XI.M12. The applicant also stated that reduction of heat transfer aging 

effect will be managed for the reactor enclosure and control enclosure ventilation system 

coolers, and the EDG system combustion air coolers using visual inspections. The applicant 

also stated that cracking will be managed for stainless steel components in the waste water 
3-317

greater than 140 °F environment. The applicant also stated that since these components are in 

a more aggressive environment than environments addressed by GALL Report AMP XI.M32, 

“One-Time Inspection” program, the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components program will be used and visual inspections will be used to manage the 

aging effect. 

The staff finds the applicant’s response acceptable because the applicant has identified all the 

aging effects that will be addressed by the program, including loss of fracture toughness, 

reduction of heat transfer, cracking, and the associated program inspections for these aging 

effects are adequate methods to manage these aging effects. The staff’s concern described in 

RAI B.2.1.26-1 is resolved.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.3.2.3.20 Reactor Enclosure Ventilation – 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 Reactor Enclosure Ventilation component groups.

The staff’s evaluation for elastomer hoses, ducting and components, and flexible connections 

exposed internally to wetted air or gas, which will be managed for loss of material and 

hardening and loss of strength by the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components program and that cite generic note G, is documented in 3.3.2.3.3.

The staff’s evaluation for copper, aluminum, and copper alloy less than 15 percent zinc, heat 

exchanger components exposed externally to wetted air or gas, which will be managed for 

reduction of heat transfer by the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components program and that cite generic note H, is documented in 3.3.2.3.4.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.3.2.3.21 Reactor Water Cleanup – 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 component groups. The staff’s review did not identify any items 

with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for this system are consistent with the GALL Report.
3-318

3.3.2.3.22 Safety-Related Service Water - 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 SW component groups.

By letter dated February 15, 2012, LRA Tables 3.3.2-8 and 3.3.2-22 were amended and the 

applicant stated that for stainless steel piping, piping components, piping elements, spray 

nozzles, and valve body exposed to outdoor air no AERM or AMP is proposed. The AMR items 

cite generic note I. Items associated with 3.3.2-8 and 3.3.2-22 cite plant-specific note 6 and 3,

which state that based on plant-specific environmental condition and operating experience,

cracking is not an applicable aging effect since outdoor environments are not conducive to SCC. 

The staff reviewed the associated items in the LRA to confirm that no aging effect is applicable 

for this component, material, and environmental combination. The staff evaluation is 

documented in SER Section 3.3.2.2.3.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.3.2.3.23 Spray Pond Pump House Ventilation – 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 Spray Pond Pump House Ventilation component groups.

The staff’s evaluation for elastomer hoses, ducting and components, and flexible connections 

exposed internally to wetted air or gas, which will be managed for loss of material and 

hardening and loss of strength by the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components program and that cite generic note G, is documented in 3.3.2.3.3.

The staff reviewed the associated items in the LRA to confirm that this aging effect is not 

applicable for this component, material, and environment combination. The staff’s evaluation is 

documented in SER Section 3.3.2.2.3.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.3.2.3.24 Standby Liquid Control - 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 SLC component groups. The staff’s review did not identify any items with notes F through J, 
3-319

indicating that the combinations of component type, material, environment, and AERM for this 

system are consistent with the GALL Report.

3.3.2.3.25 Traversing In-core Probe - 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 in-core probe component groups. The staff’s review did not identify any items 

with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for this system are consistent with the GALL Report.

3.3.2.3.26 Water Treatment and Distribution - Summary of Aging Management Review –

LRA Table 3.3.2-26

The staff reviewed LRA Table 3.3.2-26, which summarizes the results of AMR evaluations for 

the Water Treatment and Distribution component groups. The staff’s review did not identify any 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for this system 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 Systems

This SER Section documents the staff’s review of the applicant’s AMR results for the steam and 

power conversion systems components and component groups of:

 • circulating water system

 • condensate

 • condenser and air removal system

 • extraction steam system

 • feedwater system

 • main steam system

 • main turbine

3.4.1 Summary of Technical Information in the Application 

LRA Section 3.4 provides AMR results for the steam and power conversion systems 

components and component groups. LRA Table 3.4.1, “Summary of Aging Management 

Programs for Steam and Power Conversion Systems Evaluated in Chapter VIII of 
3-320

NUREG-1801,” is a summary comparison of the applicant’s AMRs with those evaluated in the 

GALL Report for the steam and power conversion systems 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 it was issued.

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 

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 AMRs to ensure the applicant’s claim that certain AMRs were 

consistent with the GALL Report. 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 was 

applicable and that the applicant identified the appropriate GALL Report AMRs. The staff’s 

evaluations of the AMPs are documented in SER Section 3.0.3.

During its review, the staff also selected AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

were consistent with the SRP-LR Section 3.4.2.2 acceptance criteria. The staff’s evaluations 

are documented in SER Section 3.4.2.2.

The staff also conducted a technical review of the remaining AMRs not consistent with or not 

addressed in the GALL Report. The technical review evaluated whether all plausible aging 

effects have been identified and whether the aging effects listed were appropriate for the 

material-environment combinations specified. The staff’s evaluations are documented in SER 

Section 3.4.2.3.

For SSCs that the applicant claimed were not applicable or required no aging management, the 

staff reviewed the AMR items and the plant’s operating experience to verify the applicant’s 

claims.

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.
3-321

Table 3.4-1 Staff Evaluation for Steam and Power Conversion Systems Components in 

the GALL Report

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

Report

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 

caused by

fatigue

Fatigue is a 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 caused 

by stress 

corrosion 

cracking

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes External 

Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with 

GALL Report (See 

SER subsection 

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 

caused by 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 subsection 

3.4.2.2.3)

Steel external 

surfaces, bolting 

exposed to air with 

borated water 

leakage (3.4.1-4)

Loss of material 

caused by boric 

acid corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No NA 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 

caused by

flow-accelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Flow-Accelerate

d Corrosion

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 NA Not applicable to 

LGS (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 caused 

by cyclic 

loading, stress 

corrosion 

cracking

Chapter XI.M18, 

“Bolting Integrity”

No NA Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)

Steel; stainless steel 

bolting, closure 

bolting exposed to 

air-outdoor 

(external), air-indoor, 

uncontrolled 

(external) (3.4.1-8)

Loss of material 

caused by

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report
3-322

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel closure bolting 

exposed to air with 

steam or water 

leakage (3.4.1-9)

Loss of material 

caused by

general 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No NA Not applicable to 

LGS (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 

caused by

thermal effects, 

gasket creep, 

and 

self-loosening

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 caused 

by stress 

corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

and One-Time 

Inspection

Consistent with the 

GALL Report (see 

SER Section 

(3.4.2.1)

Steel; stainless steel 

tanks exposed to 

treated water 

(3.4.1-12)

Loss of material 

caused by

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

and One-Time 

Inspection

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to treated 

water (3.4.1-13)

Loss of material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No NA 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 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

and One-Time 

Inspection

Consistent with the 

GALL Report

Steel heat exchanger 

components exposed 

to treated water 

(3.4.1-15)

Loss of material 

caused by

general, pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

and One-Time 

Inspection

Consistent with the 

GALL Report
3-323

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

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 

caused by pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

and One-Time 

Inspection

Consistent with the 

GALL Report

Copper alloy heat 

exchanger tubes 

exposed to treated 

water (3.4.1-17)

Reduction of 

heat transfer 

caused by

fouling

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No NA 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 

caused by

fouling

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

and One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel, steel 

heat exchanger 

components exposed 

to raw water 

(3.4.1-19)

Loss of material 

caused by

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

Copper alloy, 

stainless steel piping, 

piping components, 

and piping elements 

exposed to raw water 

(3.4.1-20)

Loss of material 

caused by

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No NA Not applicable to 

LGS (See SER 

Section 3.4.2.1.1)

Stainless steel heat 

exchanger 

components exposed 

to raw water 

(3.4.1-21)

Loss of material 

caused by

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Open-Cycle 

Cooling Water 

and Bolting 

Integrity

Consistent with the 

GALL Report (see 

SER 

Section 3.4.2.1.2)
3-324

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel, 

copper alloy, steel 

heat exchanger 

tubes, heat 

exchanger 

components exposed 

to raw water 

(3.4.1-22)

Reduction of 

heat transfer 

caused by

fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No NA Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water >60 °C 

(>140 °F) (3.4.1-23)

Cracking caused 

by stress 

corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)

Steel heat exchanger 

components exposed 

to closed-cycle 

cooling water 

(3.4.1-24)

Loss of material 

caused by

general, pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)

Steel heat exchanger 

components exposed 

to closed-cycle 

cooling water 

(3.4.1-25)

Loss of material 

caused by

general, pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)

Stainless steel heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water (3.4.1-26)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water (3.4.1-27)

Loss of material 

caused by

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)

Steel, stainless steel, 

copper alloy heat 

exchanger 

components and 

tubes, heat 

exchanger tubes 

exposed to 

closed-cycle cooling 

water (3.4.1-28)

Reduction of 

heat transfer 

caused by

fouling

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No NA Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)
3-325

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel tanks exposed 

to air-outdoor 

(external) (3.4.1-29)

Loss of material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No NA Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)

Steel, stainless steel, 

aluminum tanks 

exposed to soil or 

concrete, air-outdoor 

(external) (3.4.1-30)

Loss of material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Aboveground 

Metallic Tanks

Consistent with the 

GALL Report

Stainless steel, 

aluminum tanks 

exposed to soil or 

concrete (3.4.1-31)

Loss of material 

caused by

pitting, and 

crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No NA Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)

Gray cast iron piping, 

piping components, 

and piping elements 

exposed to soil 

(3.4.1-32)

Loss of material 

caused by

selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No NA Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)

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 

caused by

selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No NA Not applicable to 

LGS (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 

caused by

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 

caused by pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No NA Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)

Steel piping, piping 

components, and

piping elements 

exposed to 

air-outdoor (internal) 

(3.4.1-36)

Loss of material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.M38, 

"Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components"

No NA Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1)
3-326

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to 

condensation 

(internal) (3.4.1-37)

Loss of material 

caused by

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 

caused by

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 NA Not applicable to 

LGS (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 

caused by 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 

(3.4.1-40)

Loss of material 

caused by

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 

(3.4.1-41)

Loss of material 

caused by

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No NA 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 

caused by pitting 

and crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No NA 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 

caused by pitting 

and crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)
3-327

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel 

piping, piping 

components, and 

piping elements, heat 

exchanger 

components exposed 

to lubricating oil 

(3.4.1-44)

Loss of material 

caused by

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 

components and 

tubes exposed to 

lubricating oil 

(3.4.1-45)

Reduction of 

heat transfer 

caused by

fouling

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No NA 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 

caused by

fouling

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No NA Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Steel (with coating or 

wrapping) piping, 

piping components, 

and piping elements; 

tanks exposed to soil 

or concrete 

(3.4.1-47)

Loss of material 

caused by

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Buried Piping 

and 

Underground 

Piping and 

Tanks

Consistent with the 

GALL Report

Stainless steel 

bolting exposed to 

soil (3.4.1-48)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No NA Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to soil or 

concrete (3.4.1-49)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No NA Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)

Steel bolting 

exposed to soil 

(3.4.1-50)

Loss of material 

caused by

general, pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No NA Not applicable to 

LGS (see SER 

Section 3.4.2.1.1)

Underground 

stainless steel and 

steel piping, piping 

components, and 

piping elements 

(3.4.1-50x)

Loss of material 

caused by

general (steel 

only), pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No NA Not applicable to 

LGS (See SER 

Section 3.4.2.1.1)
3-328

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

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.

NA Not applicable to 

LGS (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

NA Consistent with 

SRP-LR

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

NA Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

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

NA Consistent with 

SRP-LR

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

NA Consistent with 

SRP-LR
3-329

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in SRP-LR

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

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

NA Not applicable to 

LGS (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

NA Not applicable to 

LGS (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

NA Consistent with 

SRP-LR

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

NA Consistent with 

SRP-LR

The staff’s review of the steam and power conversion systems component groups followed any 

one of several approaches. One approach, documented in SER Section 3.4.2.1, reviewed AMR 

results for components that the applicant indicated are consistent with the GALL Report and 

require no further evaluation. Another approach, documented in SER Section 3.4.2.2, reviewed 

AMR results for components that the applicant indicated are consistent with the GALL Report 

and for which further evaluation is recommended. A third approach, documented in SER 

Section 3.4.2.3, reviewed AMR results for components that the applicant indicated are not 

consistent with, or not addressed in, the GALL Report. The staff’s review of AMPs credited to 

manage or monitor aging effects of the steam and power conversion systems components is 

documented in SER Section 3.0.3.

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 systems components:
3-330

 • bolting integrity

 • buried and underground piping and tanks

 • external surfaces monitoring of mechanical components

 • flow-accelerated corrosion

 • inspection of internal surfaces in miscellaneous piping and ducting components

 • lube oil analysis

 • one-time inspection

 • open-cycle cooling water system

 • TLAA

 • water chemistry

LRA Tables 3.4.2-1 through 3.4.2-7 summarize AMRs for the steam and power conversion 

systems components and indicate AMRs claimed to be consistent with the GALL Report.

The staff audited and reviewed the information in the LRA. 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 was applicable and that the applicant identified the appropriate GALL 

Report AMRs. The staff’s evaluation follows.

LRA Table 3.4.1, item 3.4.1-11 addresses stainless steel or stainless-steel clad steel piping, 

piping components, piping elements, and tanks exposed to treated water greater than 60 °C 

(140 °F), which will be managed for cracking caused by SCC. LRA item 3.4.1-11 indicates that 

this aging effect is managed by the Water Chemistry and One-Time Inspection programs. 

During its review of components associated with LRA item 3.4.1-11, for which the applicant 

cited generic note A, the staff noted that LRA Table 3.1.2-1 addresses stainless steel reactor 

coolant pressure boundary (RCPB) piping, piping components, and piping elements exposed to 

steam (internal). LRA Table 3.1.2-1 indicates that these components are related to LRA item 

3.4.1-11 and cracking caused by SCC of these components are managed by the Water 

Chemistry and One-Time Inspection programs. In comparison, GALL Report item IV.C1.R-20 

and SRP-LR Table 3.1-1, ID 97 address aging management for cracking caused by SCC of 

stainless steel piping, piping components, and piping elements greater than or equal to NPS 4 

exposed to reactor coolant. The GALL Report and SRP-LR recommend GALL Report AMP 

XI.M2, “Water Chemistry,” and GALL Report AMP XI.M7, “BWR Stress Corrosion Cracking” to 

manage the aging effect of the stainless steel components.

Therefore, the staff needed to clarify whether any of the applicant’s stainless steel components 

addressed in LRA Table 3.1.2-1 is included in the scope of the BWR Stress Corrosion Cracking 

program or the ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

program, which performs periodic inspections. The staff also needed clarification as to the 

adequacy of the One-Time Inspection program that the applicant proposed to manage the aging 

effect. 

By letter dated February 16, 2012, the staff issued RAI 3.4.1.11-1 requesting that the applicant 

clarify why any of these stainless steel components exposed to steam are not included in the 
3-331

scope of the BWR Stress Corrosion Cracking program or the ASME Code Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD program. The staff also requested that the 

applicant justify why the One-Time Inspection program, which does not include periodic 

inspections, is adequate to manage cracking caused by SCC of these stainless steel 

components. In addition, the staff requested that the applicant clarify whether SCC has been 

observed in these components in order to demonstrate that the plant-specific operating 

experience supports the adequacy of the One-Time Inspection program to manage the aging 

effect.

In its response dated March 13, 2012, the applicant stated that the reactor core isolation cooling 

(RCIC) steam supply flow elements are the only stainless steel piping, piping components, and 

piping elements exposed internally to steam within the RCPB, which are addressed in LRA 

Table 3.1.2-1. The applicant also stated that these stainless steel flow elements are welded into 

the 4-inch carbon steel portion of the ASME Code Class 1 RCIC steam supply piping. The 

applicant further stated that the piping-to-flow-element welds are currently within the scope of 

the components managed by the BWR Stress Corrosion Cracking program, which is an 

augmented program within the ASME Code Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD program. 

In addition, the applicant confirmed that based on its response to RAI 3.4.1.11-1, the One-Time 

Inspection program is not used to manage cracking caused by SCC of these stainless steel 

components, and the BWR Stress Corrosion Cracking program provides for periodic inspections 

to manage the aging effect of these components. The applicant also clarified that LRA item 

3.1.1-97 is used to manage cracking of the RCIC stainless steel steam supply flow elements. 

The applicant provided the revisions to LRA Table 3.1.2-1, consistent with its response. The 

staff finds the applicant’s response acceptable because the applicant confirmed that the BWR 

Stress Corrosion Cracking program is used to manage cracking caused by SCC of the stainless 

steel RCPB piping components, consistent with the GALL Report. 

The staff’s evaluations of the Water Chemistry, One-Time Inspection and the BWR Stress 

Corrosion Cracking programs are documented in SER Sections 3.0.3.1.2, 3.0.3.1.12, and 

3.0.3.1.6, respectively. In its review of the non-RCPB components associated with LRA item 

3.4.1-11, the staff finds the applicant’s proposal to manage aging, using the Water Chemistry 

and One-Time Inspection programs, acceptable because the Water Chemistry program limits 

the concentrations of chemical species known to cause SCC and controls the dissolved oxygen 

level to minimize the environmental effect on SCC, and the One-Time Inspection program 

includes a one-time inspection of selected components to confirm the effectiveness of the Water 

Chemistry program. In its review of the RCPB components associated with LRA item 3.1.1-97, 

the staff finds the applicant’s proposal to manage aging using the Water Chemistry and BWR 

Stress Corrosion Cracking programs acceptable because the Water Chemistry program controls 

and minimizes the environmental effect on SCC as described above, and the BWR Stress 

Corrosion Cracking program includes periodic volumetric inspections that can adequately detect 

and manage SCC of these components.

The staff concludes that for LRA items 3.4.1-11 and 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).
3-332

LRA Table 3.4.2-7 addresses stainless steel electro-hydraulic control (EHC) drain tanks

exposed internally to an environment of wetted air or gas and lubricating oil, which will be 

managed for loss of material. This component cites LRA items 3.4.1-39 and 3.4.1-44 and 

generic notes C and A, respectively, and credits the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components, Lubricating Oil Analysis and One-Time 

Inspection programs to manage this aging effect. During its review, the staff was not able to 

verify the material of construction for the EHC drain tank. By letter dated January 17, 2012, the 

staff issued RAI 3.4.2.7-1 requesting that the applicant verify the materials used for the 

fabrication of the EHC drain tank, and if necessary, provide the results of an updated aging 

management review, in accordance with 10 CFR 54.21(a)(1). 

In its response dated February 15, 2012, the applicant stated that the EHC drain tank is an 

in-line piping component that is manufactured from stainless steel. The applicant also stated 

that the manufacturer of the component has provided information confirming that the EHC drain 

tank is fabricated from two stainless steel materials: Type 347 (columbium stabilized chromium 

nickel steel) and Type 309S stainless steel. The applicant further stated that these materials 

are consistent with the stainless steel material selection for the aging management review 

identified in LRA Table 3.4.2-7, and, therefore, no update to the aging management review is 

required.

Based on its review, the staff finds the applicant’s response to RAI 3.4.2.7-1 acceptable 

because the applicant was able to confirm that the EHC drain tank was fabricated from stainless 

steel alloys; therefore, the staff’s concern described in RAI 3.4.2.7-1 is resolved. The staff’s 

evaluation of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components, Lubricating Oil Analysis, and One-Time Inspection programs are documented in 

SER Section 3.0.3.1.16, 3.0.3.1.17, and 3.0.3.1.12, respectively. In its review of this component 

associated with LRA item 3.4.1-39 and 3.4.1-44, the staff finds the applicant’s proposal to 

manage aging, using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components, Lubricating Oil Analysis, and One-Time Inspection programs, acceptable because 

the visual inspections conducted by the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components and One-Time Inspection programs are capable of detecting loss of 

material and between the two programs, both a one-time inspection will occur before the period 

of extended operation and opportunistic inspections will occur during the period of extended 

operation. Also, the Lubricating Oil Analysis program’s preventive actions ensure that the 

quality of oil is sufficient to minimize the potential for loss of material to occur.

The staff concludes that for the stainless steel EHC drain tank, which cites LRA Items 3.4.1-39 

and 3.4.1-44, the applicant has demonstrated that the effects of aging for these components will 

be adequately managed so that the intended functions(s) will be maintained consistent with the 

CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.4.1 items 3.4.1-6, 3.4.1-22 through 3.4.1-29, 3.4.1-31, 3.4.1.32, 3.4.1.33, 

3.4.1.35, 3.4.1-43, 3.4.1-48, 3.4.1-49, 3.4.1-51, 3.4.1-56, and 3.4.1-57, the applicant claimed 

that they were not applicable. 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 3.4.1 items 3.4.1-4, 3.4.1-13, 3.4.1-17, 3.4.1-36, 3.4.1-41, 3.4.1-42, 3.4.1-45, 

3.4.1-46, and 3.4.1-53, the applicant claimed that the corresponding AMR items in the GALL 
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Report are not applicable because the associated items are only applicable to PWRs. The staff 

reviewed the SRP-LR, confirmed these items only apply to PWRs, and finds these items are not 

applicable to LGS.

LRA Table 3.4.1, item 3.4.1-7 addresses high-strength steel closure bolting exposed to air with 

steam or water leakage. The GALL Report recommends GALL Report AMP XI.M18, “Bolting 

Integrity,” to manage cracking caused by cyclic loading and SCC for this component group. The 

applicant stated that this item is not applicable because there is no steel high-strength bolting 

exposed to air with steam or water leakage in the steam and power conversion systems. The 

staff evaluated the applicant’s claim and found it acceptable because a search of the UFSAR 

did not reveal any details on high-strength bolting, and given the lack of specificity in Chapter 10 

of the UFSAR in relation to bolting materials, the staff reviewed the seven most recent BWR 

LRAs (i.e., Grand Gulf, Hope Creek, Columbia, Vermont Yankee, Pilgrim, Duane Arnold Energy 

Center, Cooper) for item 3.4.1-7 (Revision 2) and 3.4.1-21 (Revision 1), all of which identified 

the item as not applicable.

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 caused by 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 systems. The staff evaluated 

the applicant’s claim and found it acceptable because all steam and power conversion system 

bolting exposed to air is being managed for loss of material by the Bolting Integrity program 

using item 3.4.1-08. This program conducts periodic visual inspections capable of detecting 

loss of material caused by general corrosion in bolting, and use of this program is consistent 

with the GALL Report.

LRA Table 3.4.1, item 3.4.1-20, addresses copper-alloy and stainless steel piping components 

exposed to raw water. The GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle 

Cooling Water System,” to manage loss of material caused by pitting, crevice, and MIC for this 

component group. The applicant stated that this item is not applicable because there are no 

copper-alloy piping components exposed to raw water in the steam and power conversion 

systems, and that the stainless steel piping components in these systems are being addressed 

through LRA item 3.4.1-21. The staff noted that LRA item 3.4.1-21 is similar to item 3.4.1-20, 

but also manages for the additional aging effect of fouling that leads to corrosion. The staff 

evaluated the applicant’s claim and found it acceptable because the staff confirmed that there 

are no copper-alloy piping components exposed to raw water in the steam and power 

conversion systems and that stainless steel piping components exposed to raw water in the 

steam and power conversion systems reference LRA item 3.4.1-21, which manages for loss of 

material in a manner consistent with LRA Table 3.4.1, item 3.4.1-20, and the GALL Report 

recommendations.

LRA Table 3.4.1, item 3.4.1-38, addresses steel piping, piping components, and piping 

elements exposed to raw water. The GALL Report recommends GALL Report AMP XI.M38, 

“Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,” to manage 

loss of material caused by general, pitting, crevice, galvanic, and MIC, and fouling that leads to 

corrosion, for this component group. The applicant stated that this item is not applicable 

because it is applicable to PWRs only. The staff evaluated the applicant’s claim and found it 

acceptable because, although the LRA contains this material-environment-aging effect 

combination, the applicant chose to reference LRA item 3.4.1-19, which manages aging in a 
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manner consistent with other GALL Report recommendations for steel piping exposed to raw 

water (e.g., the GALL Report item V.C.E-22). The staff noted that LRA item 3.4.1-19 uses the 

Open-Cycle Cooling Water System program to manage for loss of material caused by general, 

pitting, crevice, galvanic, and MIC, and fouling that leads to corrosion. The staff also noted that 

the visual examinations, nondestructive evaluations, and water chemistry treatments in the 

Open-Cycle Cooling Water System program are capable of mitigating and detecting loss of 

material and fouling before loss of intended function(s).

LRA Table 3.4.1, item 3.4.1-50, addresses steel bolting exposed to soil. The GALL Report 

recommends AMP XI.M41 “Buried and Underground Piping and Tanks” to manage loss of 

material caused by general, pitting and crevice corrosion for this component group. The 

applicant stated that this item is not applicable because there is no steel bolting exposed to soil 

in the steam and power conversion systems. The staff evaluated the applicant’s claim and 

found it acceptable because based on a review of LRA Section 3.4 and, during the audit, site 

drawings, the staff confirmed that there are no flanged joints, and therefore, no steel bolting in 

the portion of the circulating water system within the scope of license renewal.

LRA Table 3.4.1, item 3.4.1-50x, addresses stainless steel and steel piping, piping components, 

and piping elements exposed to an underground environment. The GALL Report recommends 

AMP XI.M41 “Buried and Underground Piping and Tanks” program to manage loss of material 

caused by general (steel only), pitting and crevice corrosion for this component group. The 

applicant stated that this item is not applicable because it will use item 3.4.1-47 to manage the 

aging of these components. The staff evaluated the applicant’s claim and found it acceptable 

because although 3.4.1-47 is for a soil or concrete environment, both items manage the same 

aging effects and use the same program to manage the aging.

3.4.2.1.2 Loss of Material Caused by Pitting, Crevice, And Microbiologically-Influenced 

Corrosion; Fouling that Leads to Corrosion

LRA Table 3.4.1, item 3.4.1-21, addresses stainless steel heat exchanger components exposed 

to raw water, which will be managed for loss of material caused by pitting, crevice, and MIC and 

fouling that leads to corrosion. For the AMR items that cite generic note E, the LRA credits the 

Bolting Integrity program to manage loss of material for stainless steel bolting exposed to raw 

water in the certain components in the circulating water system. The GALL Report 

recommends GALL Report AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure these 

aging effects are adequately managed.

The staff noted that the items are associated with the cooling tower basin removable screens, 

and that the Bolting Integrity program proposes to manage loss of material by performing 

periodic visual inspections. The staff’s evaluation of the Bolting Integrity program is 

documented in SER Section 3.0.3.2.3. In its review of components associated with 

item 3.4.1-21, for which the applicant cited generic note E, the staff finds the applicant’s 

proposal to manage aging using the above program acceptable because the Bolting Integrity 

program performs periodic inspections to identify loss of material for bolts and it is the 

appropriate AMP to manage aging of stainless steel bolting in raw water environments.

The staff concludes that for LRA item 3.4.1-21, 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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3.4.2.1.3 Conclusion

The staff evaluated the GALL Report AMR items that the applicant claimed were not applicable. 

On the basis of its review, the staff concludes that the AMR results that the applicant claimed 

were not applicable are not applicable to LGS Units 1 and 2.

As discussed in SER Section 3.0.2.2, for those AMRs that the applicant claimed consistency 

with the GALL Report, the staff evaluated the applicant’s claim of consistency. The staff also 

reviewed information pertaining to the applicant’s consideration of recent operating experience 

and proposals for managing aging effects. On the basis of its review, the staff concludes that 

the AMR results, which the applicant claimed to be consistent with the GALL Report, are 

consistent.

Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their 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).

3.4.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended 

In LRA Section 3.4.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the steam and power conversion systems components and provides 

information concerning how it will manage the following aging effects:

 • cumulative fatigue damage

 • cracking caused by SCC

 • loss of material caused by pitting and crevice corrosion

 • QA for aging management of nonsafety-related components

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.

3.4.2.2.1 Cumulative Fatigue Damage 

LRA Section 3.4.2.2.1, which is associated with LRA Table 3.4.1 item 3.4.1-1, addresses steel 

piping, piping components, and piping elements exposed to steam or treated water in the steam 

and power conversion system and are being managed for cumulative fatigue damage. 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, and is required to be evaluated in accordance with 

10 CFR 54.21(c). The applicant stated that the TLAA identified for the steam and power 

conversion systems is addressed separately 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 

states that fatigue of steam and power conversion system components is a TLAA as defined in 
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10 CFR 54.3, and that these TLAAs are to be evaluated in accordance with 10 CFR 54.21(c)(1) 

and SRP-LR Section 4.3. The staff also reviewed the AMRs items associated with LRA 

Section 3.4.2.2.1, and found that the AMR results are consistent with the GALL Report and 

SRP-LR.

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.4.2.2.1 criteria. For those items that apply to LRA Section 3.4.2.2.1, the staff 

determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that it will adequately manage the effects of aging 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). SER Section 4.3 documents the staff’s review of the applicant’s 

evaluation of the TLAA for these components.

3.4.2.2.2 Cracking Caused by Stress Corrosion Cracking

LRA Section 3.4.2.2.2, associated with LRA Table 3.4.1, item 3.4.1-2 addresses stainless steel 

piping, piping components, piping elements and tanks exposed to outdoor air. The criteria in 

the SRP-LR states that either the applicant justifies that the aging effect is not applicable by 

describing the outdoor air environment present at the plant and demonstrating that stress 

corrosion cracking is not expected, or GALL Report AMP XI.M36, “External Surfaces Monitoring 

of Mechanical Components,” is used to manage cracking caused by SCC for this component 

group. The applicant addressed the further evaluation criteria of the SRP-LR by stating that, 

“SCC of stainless steels exposed to outdoor air and contaminants is considered plausible only if 

the material temperature is above 140 °F. For the Steam and Power Conversion systems, the 

outdoor stainless steel components are less than 140 °F.” 

In its review of components associated with item 3.3.1-4, the staff noted that the environment is 

periodically subject to wetting (e.g., condensation, rain) which could introduce halides (e.g., 

cooling tower drift), which are known to contribute to SCC. LRA Section 2.4.7 further states that 

two circulating water chlorine and acid feed enclosures are used to maintain the chemical 

properties of the cooling tower basins, which can also contribute to halides in condensation. By 

letter dated January 17, 2012, the staff issued RAI B.2.1.25-1, requesting that the applicant 

provide technical justification as to why the LRA AMP does not consider SCC to be an aging 

effect requiring management for the stainless steel components in the auxiliary systems that are 

subjected to wet external environments.

In its response dated February 15, 2012, the applicant stated that although chlorine, as sodium 

hypochlorite, is added to the water in the cooling towers, prevailing wind direction is such that 

the cooling tower plume is directed away from the plant, a review of plant operating experience 

has revealed no occurrences of cracking in outdoor stainless steel components, and recent 

inspections performed on the external surfaces of large outdoor stainless steel components 

have revealed that these components are in good material condition (recent inspections reveal 

no occurrences of cracking). The applicant revised its response to the further evaluation criteria 

of the SRP-LR by stating that this item is not applicable because LGS is located more than 80 

miles from the Atlantic coast and major transportation routes near the site are at least a mile 

away. 

The staff does not find the response to RAI B.2.1.25-1 to be acceptable because experimental 

studies and industry operating experience in chloride-containing (coastal) environments have 

shown that stainless steels exposed to an outdoor air environment can crack at temperatures as 
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low as 104 to 120 °F, depending on humidity, component surface temperature, and contaminant 

concentration and composition. The staff noted that while the experimental studies 

demonstrated that cracking can occur in 4 to 52 weeks, the industry operating experience 

failures did not necessarily occur early in plant life; therefore, the staff cannot conclude that 

recent inspections are sufficient to demonstrate an aging effect will not occur during the period 

of extended operation. By letter dated June 12, 2012, the staff issued RAI B.2.1.25-1.1 

requesting that the applicant state the basis for why the chemical compounds in the cooling 

tower plume cannot result in SCC if plume fallout (regardless of prevailing wind direction) 

accumulates on the external surfaces of stainless steel piping within the scope of license 

renewal and why chloride contamination is not expected to accumulate on stainless steel 

components within the scope of license renewal from the soil or nearby agricultural and 

industrial sources.

In its response dated June 19, 2012, the applicant stated that SCC is not likely to occur because 

local temperatures have not exceeded 104 °F and only exceeded 100 °F on two days in the last 

10 years. In addition, the applicant stated that they were not in a coastal environment. The 

applicant did not respond to the potential for chloride contamination arising from agricultural or 

industrial sources; however, it revised the External Surfaces Monitoring of Mechanical 

Components program to manage stainless steel components in an outdoor air environment for 

SCC. The applicant stated that components that are jacketed or located in underground vaults 

would not be managed for SCC because they are shielded from accumulation of contaminants 

in the atmosphere. The applicant revised LRA Sections A.2.1.25, B.2.1.25, 3.4.2.1.1, 3.4.2.2.2, 

and LRA Tables 3.4.1 (item 3.4.1-2), 3.4.2-1 and 3.4.2-2 accordingly.

The staff finds the applicant’s response to RAI B.2.1.25-1.1 acceptable because the applicant 

will manage SCC of stainless steel components exposed to outdoor air using the External 

Surfaces Monitoring of Mechanical Components program, components that are jacketed or in 

underground vaults would not be exposed to sufficient quantities of atmospheric chlorides to 

cause SCC because they are protected from direct fallout by the intervening materials, the 

visual inspections of this program are capable of detecting SCC, and managing the aging of 

these AMR items in this manner is consistent with the GALL Report.

3.4.2.2.3 Loss of Material Caused by Pitting and Crevice Corrosion

LRA Section 3.4.2.2.3 associated with LRA Table 3.4.1 item 3.4.1-3, addresses stainless steel 

piping, piping components, piping elements, and tanks exposed to outdoor air that will be 

managed for loss of material caused by pitting and crevice corrosion by the External Surfaces 

Monitoring of Mechanical Components program. The recommendations in SRP-LR

Section 3.4.2.2.3 state that loss of material caused by pitting and crevice corrosion could occur 

for stainless steel piping, piping components, piping elements, and tanks exposed to outdoor 

air. The applicant addressed the further evaluation criteria of the SRP-LR by stating that any 

visible evidence of loss of material will be evaluated and entered into the CAP. 

The staff’s evaluation of the External Surfaces Monitoring of Mechanical Components program 

is documented in SER Section 3.0.3.1.15. The staff finds that the applicant has met the further 

evaluation criteria, and the applicant’s proposal to manage aging using the External Surfaces 

Monitoring of Mechanical Components program is acceptable because the AMP provides for 

management of aging effects through periodic visual inspection of external surfaces for 

evidence of loss of material.
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3.4.2.2.4 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.

3.4.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

In LRA Tables 3.4.2-1 through 3.4.2-7, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with or not addressed 

in the GALL Report.

In LRA Tables 3.4.2-1 through 3.4.2-7, the applicant, by notes F through J, indicated 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.

3.4.2.3.1 Circulating Water 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 

circulating water system component groups.

In LRA Table 3.4.2-1, the applicant stated that there is no aging effect for polymeric strainer 

elements exposed externally to outdoor air and raw water and no AMP is proposed. The AMR 

items cite generic note G. These items cite plant-specific note 3, which states that the 

component is constructed of fiber-reinforced plastic. 

The staff reviewed the associated items in the LRA to confirm that no credible aging effects are 

applicable for this component, material, and environment combination. The staff finds the 

applicant’s proposal acceptable for the internal raw water environment based on its review of 

The Corrosion Resistant Materials Handbook, by D. J. De Renzo and Ibert Mellan, 4th Edition, 

which states that fiberglass reinforced pipe is acceptable for use in raw water environments up 

to 200 °F, which is higher than the design rating of the circulating water system. The staff lacks 

sufficient information to conclude that no aging management is required for exposure to the 

outdoor air environment because the type of fiber reinforced material (e.g., epoxy resin, 

reinforced vinyl ester resin) could influence the impact of exposure to outdoor ultraviolet (UV)

light. By letter dated January 18, 2012, the staff issued RAI 3.4.2.3.1-1 requesting the applicant 

to state the specific specification/grade of fiber-reinforced material used in the polymeric strainer 
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element components within the scope of license renewal and the basis for why exposure to 

outdoor UV does not require age managing of these components.

In its response, dated February 16, 2012, the applicant stated that the material used for the 

strainer element is not known and upon further review, the strainer elements made of 

fiber-reinforced polymeric material have been determined to be submerged during normal 

cooling tower operation and are covered by at least 2 feet of water; therefore, the external 

outdoor air environment for the strainer element as identified in LRA Table 3.4.2-1 is not 

applicable. The applicant also revised LRA Table 3.4.2-1 to reflect the deletion of the outdoor 

air environment.

The staff finds the applicant’s response acceptable because the component is underwater and,

therefore, not significantly exposed to outdoor UV. The staff’s concern described in 

RAI 3.4.2.3.1-1 is resolved.

By letter dated February 15, 2012, LRA Tables 3.4.2-1 and 3.4.2-2 added stainless steel 

strainer (element) and valve body exposed externally to outdoor air, and no AERM or AMP is 

proposed. The AMR items cite generic note I. Items associated with Table 3.4.2-1 and 3.4.2-2 

cite plant-specific notes 4 and 1, which state that based on plant-specific environmental 

condition and operating experience, cracking is not an applicable aging effect since outdoor 

environments are not conducive to SCC.

The staff reviewed the associated items in the LRA to confirm that this aging effect(s) is not 

applicable for this component, material, and environment combination. The staff evaluation is 

documented in SER Section 3.4.2.2.2.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.4.2.4.2 Condensate 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 

condensate component groups.

By letter dated February 15, 2012, LRA Tables 3.4.2-1 and 3.4.2-2 added stainless steel 

strainer (element) and valve body exposed externally to outdoor air, and no AERM or AMP is 

proposed. The staff’s evaluation of these items is documented in 3.3.2.3.3.

In LRA Table 3.4.2-2, the applicant stated that for valve bodies exposed externally to outdoor air

no AERM or AMP is proposed. The AMR item cites generic note I and plant-specific note 1, 

which states that these components are jacketed and not directly exposed to the outdoor air 

environment and, therefore, not susceptible to SCC.

The staff reviewed the associated items in the LRA to confirm that this aging effect is not 

applicable for this component, material, and environment combination. The staff’s evaluation is 

documented in SER Section 3.4.2.2.2.
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On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.4.2.4.3 Condenser and Air Removal 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 

condenser and air removal system component groups.

In LRA Table 3.4.2-3, the applicant stated that carbon steel heat exchanger components 

exposed internally to treated water will be managed for loss of material by the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components program. The AMR 

item cites generic note H. 

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 steel heat exchanger components exposed to treated water are subject to a loss of material 

aging effect, 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 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program is documented in SER Section 3.0.3.1.16. 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 program uses visual inspections during 

periodic surveillances, maintenance activities, and during scheduled outages, which is an 

adequate technique for identify this aging effect.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.4.2.4.4 Extraction Steam 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 

extraction steam component groups. The staff’s review did not identify any items with notes F 

through J, indicating that the combinations of component type, material, environment, and 

AERM for this system are consistent with the GALL Report.

3.4.2.4.5 Feedwater 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 

feedwater system component groups. The staff’s review did not identify any items with notes F 
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through J, indicating that the combinations of component type, material, environment, and 

AERM for this system are consistent with the GALL Report.

3.4.2.4.6 Main Steam 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 

main steam system component groups. The staff’s review did not identify any items with 

notes F through J, indicating that the combinations of component type, material, environment, 

and AERM for this system are consistent with the GALL Report.

3.4.2.4.7 Main Turbine 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 

feedwater system component groups. The staff’s review did not identify any items with 

notes F through J, indicating that the combinations of component type, material, environment, 

and AERM for this system 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 

functions will remain 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 SER Section documents the staff’s review of the applicant’s AMR results for the structures 

and component supports groups of:

 • 220 and 500 kV substations

 • admin building shop and warehouse

 • auxiliary boiler and lube oil storage enclosure

 • circulating water pump house

 • component supports commodities group

 • control enclosure

 • cooling towers

 • diesel oil storage tank structures

 • EDG enclosure

 • piping and component insulation commodity group

 • primary containment

 • radwaste enclosure

 • reactor enclosure

 • SW pipe tunnel
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 • spray pond and pump house

 • turbine enclosure

 • yard facilities

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 Programs for 

Structures and Component Supports Evaluated in Chapters II and III of NUREG-1801,” 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 AMRs to ensure the applicant’s claim that certain AMRs are 

consistent with the GALL Report. 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 was 

applicable and that the applicant identified the appropriate GALL Report AMRs. The staff’s 

evaluations of the AMPs are documented in SER Section 3.0.3.

During its review, the staff also selected 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 3.5.2.2 acceptance criteria. The staff’s evaluations are 

documented in SER Section 3.5.2.2.

The staff also conducted a technical review of the remaining AMRs not consistent with or not 

addressed in the GALL Report. The technical review evaluated whether all plausible aging 

effects have been identified and whether the aging effects listed were appropriate for the 

material-environment combinations specified. The staff’s evaluations are documented in SER 

Section 3.5.2.3.

For SSCs the applicant claimed were not applicable or required no aging management, the staff 

reviewed the AMR items and the plant’s operating experience to verify the applicant’s claims.

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.
3-343

Table 3.5-1 Staff Evaluation for Structures and Component Supports Components in the 

GALL Report

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

BWR Concrete and Steel (Mark I, II, and III) Containments

Concrete: dome; 

wall; basemat; ring 

girders; buttresses, 

concrete elements, 

all (3.5.1-1)

Cracking and 

distortion 

caused by

increased 

stress levels 

from settlement

Chapter XI.S2, 

“ASME Code 

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 

NA Not applicable to 

LGS (see SER 

Section 3.5.2.2.1.1)

Concrete: 

foundation; 

subfoundation 

(3.5.1-2)

Reduction of 

foundation 

strength and 

cracking 

caused by

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 

NA Not applicable to 

LGS (see SER 

Section 3.5.2.2.1.1)

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 

caused by

elevated 

temperature 

(>150 °F 

general; 

>200 °F local)

A plant-specific aging 

management 

program is to be 

evaluated.

Yes, if 

temperature 

limits are 

exceeded 

NA Not applicable to 

LGS (see SER 

Section 3.5.2.2.1.2)

Steel elements 

(inaccessible 

areas): drywell 

shell; drywell head; 

and drywell shell 

(3.5.1-4)

Loss of 

material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

Yes, if 

corrosion is 

indicated from 

the IWE 

examinations 

NA Not applicable to 

LGS (see SER 

Section

3.5.2.2.1.3(1))
3-344

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

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 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE” and 

Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

Yes, if 

corrosion is 

indicated from 

the IWE 

examinations 

ASME Code 

Section XI, 

Subsection IWE 

and 

10 CFR Part 50, 

Appendix J

Consistent with 

GALL Report

(see SER Section

3.5.2.2.1.3(1))

Steel elements: 

torus shell (3.5.1-6)

Loss of 

material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Code 

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

. 

NA Not applicable to 

LGS (see

SER Section

3.5.2.2.1.3(2))

Steel elements: 

torus ring girders; 

downcomers; steel 

elements: 

suppression 

chamber shell 

(interior surface) 

(3.5.1-7)

Loss of 

material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE”

Yes, if 

corrosion is 

significant 

NA Not applicable to 

LGS (see

SER Section

3.5.2.2.1.3(3))

Pre-stressing 

system: tendons 

(3.5.1-8)

Loss of 

prestress 

caused by

relaxation; 

shrinkage; 

creep; elevated 

temperature

Yes, TLAA Yes NA Not applicable to 

LGS (see SER 

Section 3.5.2.2.1.4)

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 

caused by

fatigue (Only if 

CLB fatigue 

analysis exists)

Yes, TLAA Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.5.2.2.1.5)
3-345

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Penetration 

sleeves; penetration 

bellows (3.5.1-10)

Cracking 

caused by

stress 

corrosion 

cracking

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.2.1.6)

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 

caused by

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 NA Not applicable to 

LGS (see SER 

Section 3.5.2.2.1.7)

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 

caused by

expansion from 

reaction with 

aggregates

Further evaluation is 

required to determine 

if a plant-specific 

aging management 

program is needed.

Yes NA Not applicable to 

LGS (see SER

Section 3.5.2.2.1.8)

Concrete 

(inaccessible 

areas): basemat, 

concrete 

(inaccessible 

areas): dome; wall; 

basemat (3.5.1-13)

Increase in 

porosity and 

permeability; 

loss of strength 

caused by

leaching of 

calcium 

hydroxide and 

carbonation

Further evaluation is 

required to determine 

if a plant-specific 

aging management 

program is needed. 

Yes NA Not applicable to 

LGS (see SER

Section 3.5.2.2.1.9)

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 

caused by

leaching of 

calcium 

hydroxide and 

carbonation

Further evaluation is 

required to determine 

if a plant-specific 

aging management 

program is needed. 

Yes NA Not applicable to 

LGS (see SER

Section 3.5.2.2.1.9)
3-346

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Concrete 

(accessible areas): 

basemat (3.5.1-15)

Increase in 

porosity and 

permeability; 

loss of strength 

caused by

leaching of 

calcium 

hydroxide and 

carbonation

Chapter XI.S2, 

“ASME Code 

Section XI, 

Subsection IWL”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)

Concrete 

(accessible areas): 

basemat, concrete: 

containment; wall; 

basemat (3.5.1-16)

Increase in 

porosity and 

permeability; 

cracking; loss 

of material 

(spalling, 

scaling) caused 

by aggressive 

chemical attack

Chapter XI.S2, 

“ASME Code 

Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No NA Not applicable to 

LGS (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) caused 

by aggressive 

chemical attack

Chapter XI.S2, 

“ASME Code 

Section XI, 

Subsection IWL”

No NA Not applicable to 

LGS (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 

caused by

freeze-thaw

Chapter XI.S2, 

“ASME Code 

Section XI, 

Subsection IWL”

No NA Not applicable to 

LGS (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 

caused by

expansion from 

reaction with 

aggregates

Chapter XI.S2, 

“ASME Code 

Section XI, 

Subsection IWL”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)
3-347

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

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 

caused by

leaching of 

calcium 

hydroxide and 

carbonation

Chapter XI.S2, 

“ASME Code 

Section XI, 

Subsection IWL”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)

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) caused 

by corrosion of 

embedded 

steel

Chapter XI.S2, 

“ASME Code 

Section XI, 

Subsection IWL”

No ASME Code 

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) caused 

by 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) caused 

by corrosion of 

embedded 

steel

Chapter XI.S2, 

“ASME Code 

Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No NA Not applicable to 

LGS (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) caused 

by aggressive 

chemical attack

Chapter XI.S2, 

“ASME Code 

Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report
3-348

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

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) caused 

by corrosion of 

embedded 

steel

Chapter XI.S2, 

“ASME Code 

Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No NA 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 

caused by

wear, damage, 

erosion, tear, 

surface cracks, 

or other defects

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)

Penetration 

sleeves; penetration 

bellows, Steel 

elements: torus; 

vent line; vent 

header; vent line 

bellows; 

downcomers, 

suppression pool 

shell (3.5.1-27)

Cracking 

caused by

cyclic loading 

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)

Personnel airlock, 

equipment hatch, 

CRD hatch 

(3.5.1-28)

Loss of 

material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No ASME Code 

Section XI, 

Subsection IWE 

and 

10 CFR Part 50, 

Appendix J

Consistent with the 

GALL Report

Personnel airlock, 

equipment hatch, 

CRD hatch: locks, 

hinges, and closure 

mechanisms 

(3.5.1-29)

Loss of leak 

tightness 

caused by

mechanical 

wear of locks, 

hinges and 

closure 

mechanisms

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No ASME Code 

Section XI, 

Subsection IWE 

and 

10 CFR Part 50, 

Appendix J

Consistent with the 

GALL Report

Pressure-retaining 

bolting (3.5.1-30)

Loss of preload 

caused by

self-loosening

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No ASME Code 

Section XI, 

Subsection IWE 

and 

10 CFR Part 50, 

Appendix J

Consistent with the

GALL Report

Pressure-retaining 

bolting, steel 

elements: 

downcomer pipes 

(3.5.1-31)

Loss of 

material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE”

No ASME Code 

Section XI, 

Subsection IWE 

Consistent with the 

GALL Report
3-349

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Prestressing 

system: tendons; 

anchorage 

components 

(3.5.1-32)

Loss of 

material 

caused by

corrosion

Chapter XI.S2, 

“ASME Code 

Section XI, 

Subsection IWL”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)

Seals and gaskets 

(3.5.1-33)

Loss of sealing 

caused by

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 caused 

by blistering, 

cracking, 

flaking, peeling, 

or physical 

damage

Chapter XI.S8, 

“Protective Coating 

Monitoring and 

Maintenance”

No Protective 

Coating 

Monitoring and 

Maintenance

Consistent with the 

GALL Report

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 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No ASME Code 

Section XI, 

Subsection IWE 

and 

10 CFR Part 50, 

Appendix J

Consistent with the 

GALL Report

Steel elements: 

drywell head; 

downcomers 

(3.5.1-36)

Fretting or 

lockup caused 

by mechanical 

wear

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE”

No ASME Code 

Section XI, 

Subsection IWE

Consistent with the 

GALL Report

Steel elements: 

suppression 

chamber (torus) 

liner (interior 

surface) (3.5.1-37)

Loss of 

material 

caused by

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No ASME Code 

Section XI, 

Subsection IWE 

and 

10 CFR Part 50, 

Appendix J

Consistent with the 

GALL Report
3-350

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel elements: 

suppression 

chamber shell 

(interior surface) 

(3.5.1-38)

Cracking 

caused by

stress 

corrosion 

cracking

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)

Steel elements: 

vent line bellows 

(3.5.1-39)

Cracking 

caused by

stress 

corrosion 

cracking

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)

Unbraced 

downcomers, steel 

elements: vent 

header; 

downcomers 

(3.5.1-40)

Cracking 

caused by

cyclic loading 

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, 

“ASME Code 

Section XI, 

Subsection IWE”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)

Steel elements: 

drywell support 

skirt, steel elements 

(inaccessible 

areas): support skirt 

(3.5.1-41)

None None NA – No AEM 

or AMP

NA Consistent with the 

GALL Report

Safety-Related and Other Structures; and Component Supports

Groups 1-3, 5, 

7-9:concrete 

(inaccessible 

areas): foundation 

(3.5.1-42)

Loss of 

material 

(spalling, 

scaling) and 

cracking 

caused by

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

3.5.2.2.2.1(1))

All groups except 

group 6:concrete 

(inaccessible 

areas): all (3.5.1-43)

Cracking 

caused by

expansion from 

reaction with 

aggregates

Further evaluation is 

required to determine 

if a plant-specific 

aging management 

program is needed.

Yes NA Not applicable to 

LGS (see SER 

Section

3.5.2.2.2.1(2))

All groups: 

concrete: all 

(3.5.1-44)

Cracking and 

distortion 

caused by

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 

de-watering system 

through the period of 

extended operation.

Yes Structures 

Monitoring

Consistent with the 

GALL Report

(see SER Section

3.5.2.2.2.1(3))
3-351

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Groups 1-3, 5-9: 

concrete: 

foundation; 

subfoundation 

(3.5.1-45)

Reduction in 

foundation 

strength, 

cracking 

caused by

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 

de-watering system 

through the period of 

extended operation.

Yes NA Not applicable to 

LGS (see SER 

Section

3.5.2.2.2.1(3))

Groups 1-3, 5-9: 

concrete: 

foundation; 

subfoundation 

(3.5.1-46)

Reduction of 

foundation 

strength and 

cracking 

caused by

differential 

settlement and 

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 

de-watering system 

through the period of 

extended operation.

Yes NA Not applicable to 

LGS (see SER 

Section

3.5.2.2.2.1(3))

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 

caused by

leaching of 

calcium 

hydroxide and 

carbonation

Further evaluation is 

required to determine 

if a plant-specific 

aging management 

program is needed.

Yes, Structures 

Monitoring 

Consistent with the 

GALL Report (see 

SER Section

3.5.2.2.2.1(4))

Groups 1-5: 

concrete: all 

(3.5.1-48)

Reduction of 

strength and 

modulus

caused by

elevated 

temperature 

(>150 °F 

general; 

>200 °F local)

A plant-specific aging 

management 

program is to be 

evaluated.

Yes NA Not applicable to 

LGS (see SER 

Section 3.5.2.2.2.2)

Group 6 – concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation; interior 

slab (3.5.1-49)

Loss of 

material 

(spalling, 

scaling) and 

cracking 

caused by

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

3.5.2.2.2.3(1))

Group 6: concrete 

(inaccessible 

areas): all (3.5.1-50)

Cracking 

caused by

expansion from 

reaction with 

aggregates

Further evaluation is 

required to determine 

if a plant-specific 

aging management 

program is needed.

Yes NA Consistent with the 

GALL Report (see 

SER Section

3.5.2.2.2.3(2))
3-352

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Group 6: concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation; interior 

slab (3.5.1-51)

Increase in 

porosity and 

permeability; 

loss of strength 

caused by

leaching of 

calcium 

hydroxide and 

carbonation

Further evaluation is 

required to determine 

if a plant-specific 

aging management 

program is needed.

Yes RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report (see 

SER Section

3.5.2.2.2.3(3))

Groups 7, 8 - steel 

components: tank 

liner (3.5.1-52)

Cracking 

caused by

stress 

corrosion 

cracking; Loss 

of material 

caused by

pitting and 

crevice 

corrosion

A plant-specific aging 

management 

program is to be 

evaluated.

Yes NA Not applicable to 

LGS (see SER 

Section 3.5.2.2.2.4)

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-53)

Cumulative 

fatigue damage 

caused by

fatigue (Only if 

CLB fatigue 

analysis exists)

Yes, TLAA Yes, NA Not applicable to 

LGS (See SER 

subsection 

3.5.2.2.2.5)

All groups except 6: 

concrete 

(accessible areas): 

all (3.5.1-54)

Cracking 

caused by

expansion from 

reaction with 

aggregates

Chapter XI.S6, 

“Structures 

Monitoring”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)

Building concrete at 

locations of 

expansion and 

grouted anchors; 

grout pads for 

support base plates 

(3.5.1-55)

Reduction in 

concrete 

anchor capacity 

caused by 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 

below-grade; 

foundation; interior 

slab (3.5.1-56)

Loss of 

material 

caused by

abrasion; 

cavitation

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corps of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants and 

Structures 

Monitoring

Consistent with the 

GALL Report

(see SER 

Section 3.5.2.1.2)
3-353

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Constant and 

variable load spring 

hangers; guides; 

stops (3.5.1-57)

Loss of 

mechanical 

function caused 

by corrosion, 

distortion, dirt, 

overload, 

fatigue caused 

by vibratory 

and cyclic 

thermal loads

Chapter XI.S3, 

“ASME Code 

Section XI, 

Subsection IWF”

No ASME Code

Section XI, 

Subsection IWF

Consistent with the 

GALL Report

Earthen 

water-control 

structures: dams; 

embankments; 

reservoirs; 

channels; canals 

and ponds 

(3.5.1-58)

Loss of 

material; loss of 

form caused by

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 

Corps 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) caused 

by 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 

Corps 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 

caused by

freeze-thaw

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corps 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
3-354

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

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 

caused by

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 

Corps 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: Wooden 

Piles; sheeting 

(3.5.1-62)

Loss of 

material; 

change in 

material 

properties 

caused by

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 

Corps of Engineers 

dam inspections and 

maintenance 

programs.

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)

Groups 1-3, 5, 7-9: 

concrete 

(accessible areas): 

exterior above- and 

below-grade; 

foundation 

(3.5.1-63)

Increase in 

porosity and 

permeability; 

loss of strength 

caused by

leaching of 

calcium 

hydroxide and 

carbonation

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring 

Program

Consistent with the 

GALL Report

Groups 1-3, 5, 7-9: 

concrete 

(accessible areas): 

exterior above- and 

below-grade; 

foundation 

(3.5.1-64)

Loss of 

material 

(spalling, 

scaling) and 

cracking 

caused by

freeze-thaw

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring 

Program

Consistent with the 

GALL Report
3-355

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

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, 

Group 6: concrete 

(inaccessible 

areas): all (3.5.1-65)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) caused 

by 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) caused 

by corrosion of 

embedded 

steel

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

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) caused 

by 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 

caused by

stress 

corrosion 

cracking

Chapter XI.S3, 

“ASME Code Section 

XI, Subsection IWF”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)

High-strength 

structural bolting 

(3.5.1-69)

Cracking 

caused by

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 NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)

Masonry walls: all 

(3.5.1-70)

Cracking

caused by

restraint 

shrinkage, 

creep, and 

aggressive 

environment

Chapter XI.S5, 

“Masonry Walls”

No Masonry Walls Consistent with the 

GALL Report
3-356

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Masonry walls: all 

(3.5.1-71)

Loss of 

material 

(spalling, 

scaling) and 

cracking 

caused by

freeze-thaw

Chapter XI.S5, 

“Masonry Walls”

No Masonry Walls Consistent with the 

GALL Report

Seals; gasket; 

moisture barriers 

(caulking, flashing, 

and other sealants) 

(3.5.1-72)

Loss of sealing 

caused by

deterioration of 

seals, gaskets, 

and moisture 

barriers 

(caulking, 

flashing, and 

other sealants)

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Service Level I 

coatings (3.5.1-73)

Loss of coating 

integrity caused 

by blistering, 

cracking, 

flaking, peeling, 

physical 

damage

Chapter XI.S8, 

“Protective Coating 

Monitoring and 

Maintenance”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)

Sliding support 

bearings; sliding 

support surfaces 

(3.5.1-74)

Loss of 

mechanical 

function caused 

by 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 caused 

by corrosion, 

distortion, dirt, 

debris, 

overload, wear

Chapter XI.S3, 

“ASME Code 

Section XI, 

Subsection IWF”

No ASME Code 

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 caused 

by corrosion, 

distortion, dirt, 

overload, wear

Chapter XI.S6, 

“Structures 

Monitoring”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)

Steel components: 

all structural steel 

(3.5.1-77)

Loss of 

material 

caused by

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
3-357

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel components: 

fuel pool liner 

(3.5.1-78)

Cracking 

caused by

stress 

corrosion 

cracking; Loss 

of material 

caused by

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 Consistent with the 

GALL Report

Steel components: 

piles (3.5.1-79)

Loss of 

material 

caused by

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)

Structural bolting 

(3.5.1-80)

Loss of 

material 

caused by

general, pitting 

and crevice 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring and 

Inspection of 

Overhead Heavy 

and Light Load 

(Related to 

Refueling) 

Handling 

Systems

Consistent with the 

GALL Report

(see SER 

Section 3.5.2.1.3)

Structural bolting 

(3.5.1-81)

Loss of 

material 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.S3, 

“ASME Code 

Section XI, 

Subsection IWF”

No ASME Code 

Section XI, 

Subsection IWF

Consistent with the 

GALL Report

Structural bolting 

(3.5.1-82)

Loss of 

material 

caused by

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 

caused by

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 

Corps 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 

caused by

pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.S3, 

“ASME Code 

Section XI, 

Subsection IWF”

No NA Not applicable to 

LGS (see SER 

Section 3.5.2.1.1)
3-358

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Structural bolting 

(3.5.1-85)

Loss of 

material 

caused by

pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

for BWR water, and 

Chapter XI.S3, 

“ASME Code 

Section XI, 

Subsection IWF”

No Water 

Chemistry, 

ASME Code 

Section XI, 

Subsection IWF, 

and Inspection 

of Overhead 

Heavy and Light 

Load (Related to 

Refueling) 

Handling 

Systems

Consistent with the 

GALL Report

(see SER 

Section 3.5.2.1.4)

Structural bolting 

(3.5.1-86)

Loss of 

material 

caused by

pitting and 

crevice 

corrosion

Chapter XI.S3, 

“ASME Code 

Section XI, 

Subsection IWF”

No ASME Code 

Section XI, 

Subsection IWF

Consistent with the 

GALL Report

Structural bolting 

(3.5.1-87)

Loss of preload 

caused by

self-loosening

Chapter XI.S3, 

“ASME Code 

Section XI, 

Subsection IWF”

No ASME Code 

Section XI, 

Subsection IWF

Consistent with the 

GALL Report

Structural bolting 

(3.5.1-88)

Loss of preload 

caused by

self-loosening

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring and 

Inspection of 

Overhead Heavy 

and Light Load 

(Related to 

Refueling) 

Handling 

Systems

Consistent with the 

GALL Report

(see SER 

Section 3.5.2.1.3)

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-89)

Loss of 

material 

caused by boric 

acid corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No NA 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 

caused by

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

for BWR water, and 

Chapter XI.S3, 

“ASME Code 

Section XI, 

Subsection IWF”

No Water Chemistry 

and ASME Code 

Section XI, 

Subsection IWF

Consistent with the 

GALL Report

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-91)

Loss of 

material 

caused by

general and 

pitting 

corrosion

Chapter XI.S3, 

“ASME Code 

Section XI, 

Subsection IWF”

No ASME Code 

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 

caused by

general and 

pitting 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report
3-359

Component Group

(SRP-LR Item No.)

Aging Effect

or

Mechanism

AMP in SRP-LR Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-93)

Loss of 

material 

caused by

pitting and 

crevice 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring, 

RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants, and 

ASME Code 

Section XI, 

Subsection IWF

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 caused 

by radiation 

hardening, 

temperature, 

humidity, 

sustained 

vibratory 

loading

Chapter XI.S3, 

“ASME Code 

Section XI, 

Subsection IWF”

No Structures 

Monitoring

Consistent with the 

GALL Report

(see SER 

Section 3.5.2.1.6)

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

NA Consistent with the 

GALL Report

The staff’s review of the structures and component supports component groups followed any 

one of several approaches. One approach, documented in SER Section 3.5.2.1, reviewed AMR 

results for components that the applicant indicated are consistent with the GALL Report and 

require no further evaluation. Another approach, documented in SER Section 3.5.2.2, reviewed 

AMR results for components that the applicant indicated are consistent with the GALL Report 

and for which further evaluation is recommended. A third approach, documented in SER 

Section 3.5.2.3, reviewed AMR results for components that the applicant indicated are not 

consistent with, or not addressed in, the GALL Report. The staff’s review of AMPs credited to 

manage or monitor aging effects of the structures and component supports components is 

documented in SER Section 3.0.3.

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 
3-360

that manage aging effects for the structures and structural components and their commodity 

groups:

 • 10 CFR Part 50, Appendix J

 • aboveground metallic tanks

 • ASME Code Section XI, Subsection IWE

 • ASME Code Section XI, Subsection IWF

 • ASME Code Section XI, Subsection IWL

 • masonry walls

 • Protective Coating Monitoring and Maintenance program

 • RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants”

 • structures monitoring

 • TLAA

 • water chemistry

Although not identified directly in LRA Section 3.5.2.1, LRA Table 3.5.1 identifies the following 

additional program under the discussion column that manages aging effects for the structures 

and structural components and their commodity groups for specified conditions: Inspection of 

Overhead Heavy and Light Load (Related to Refueling) Handling Systems.

LRA Tables 3.5.2-1 through 3.5.2-17 summarize AMRs for the structures and component 

supports component groups and indicate AMRs claimed to be consistent with the GALL Report.

The staff audited and reviewed the information in the LRA. 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 was applicable and that the applicant identified the appropriate GALL 

Report AMRs. The staff’s evaluation follows.

LRA Table 3.5.1, item 3.5.1-78 addresses steel fuel pool liner components, which will be 

managed for cracking caused by stress corrosion cracking and loss of material caused by pitting 

and crevice corrosion with the Water Chemistry program and monitoring of the spent fuel pool 

water level. The staff noted that the applicant limited the applicable aging effect to loss of 

material and also monitors for changes in leakage in the leak chase channel drainage system. 

During its review of components associated with item 3.5.1-78 for which the applicant originally 

cited generic notes A or C, the staff noted that the applicant applied this item to components, 

such as debris screens, for which monitoring of the spent fuel pool water level and leak chase 

channel draining system may not be appropriate activities to verify the effectiveness of the 

Water Chemistry program. By letter dated January 16, 2012, the staff issued RAI 3.5.2.11-1 

requesting that the applicant propose an alternative activity to verify the effectiveness of the 

Water Chemistry program for those items that reference LRA item 3.5.1-78, for which 

monitoring of the spent fuel pool water level and leak chase channel draining system would not 

be expected to detect degradation. 

In its response dated March 13, 2012, the applicant removed the AMR items (all of the generic 

note C items and one of the generic note A items) for the stainless steel refueling bellows; 
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debris screens, grating and bars; and the reactor well, dryer and separator pool, and cask 

loading pit liners; and integral attachments exposed to the treated water environment. The 

applicant stated that these items are only exposed to treated water during refueling outages, 

and the uncontrolled indoor air environment is already identified for these components in LRA 

Tables 3.5.2-11 and 3.5.2-13. The staff noted that SRP-LR Section A.1.2.1 states that the 

aging effects to be considered should include those that result from plant shutdown, and thus 

aging management of the subject components exposed to treated water should be evaluated. 

However, the staff finds the applicant’s age management approach acceptable for the subject 

debris screens, grating, bars, liners, and integral attachments because (a) the capability to 

detect degradation of the refueling bellows and the reactor well, dryer and separator pool, and 

cask loading pit liners is maintained through monitoring of the water levels of the spent fuel pool 

and reactor well in accordance with technical specifications and (b) the applicant will be using 

the One-Time Inspection program to verify the effectiveness of the Water Chemistry program for 

stainless steel components in the fuel pool cooling and cleanup system that are continuously 

exposed to the spent fuel pool water environment, which bounds the components that originally 

referenced item 3.5.1-78 and are exposed to the spent fuel pool water environment only during 

refueling.

The staff lacked sufficient information to find the response acceptable for the refueling bellows 

because the staff did not have adequate assurance that the above activities would be sufficient 

to manage aging of the bellows, which, caused by their thin walls and high residual stresses, 

may be particularly susceptible to degradation. By letter dated May 18, 2012, the staff issued 

RAI 3.5.2.11-1.1 requesting that the applicant describe actions that will be taken to manage the 

aging effects for the refueling bellows in the treated water environment or provide the basis for 

not performing an aging management review.

In its response dated May 31, 2012, the applicant stated that potential aging effects of the 

refueling bellows caused by exposure to treated water do not warrant management because the 

bellows are only exposed to water for two weeks each operating cycle, the bellows are not in 

low-flow or stagnant areas since the area is drained upon completion of the refueling, the 

normal indoor air environment is inerted with nitrogen, and heat from the RPV causes rapid 

evaporation of any moisture remaining in the bellows. The applicant also stated that operating 

experience reviews have not identified any failures or leakage from the type of refueling bellows 

used at LGS and any such failures could be detected by monitoring of water level in the spent 

fuel pool and reactor cavity and bellows leakage detection instrumentation that alarms in the 

main control room. The staff finds the response acceptable because, even if degradation of the 

bellows were to occur during the limited exposure to treated water, the bellows leakage 

detection instrumentation and control room alarm (as described in UFSAR Section 9.1.3.5), the 

monitoring of spent fuel pool and reactor cavity water level, and the one-time inspection of 

bounding stainless steel components continuously exposed to the spent fuel pool environment 

are capable of ensuring that degradation of the refueling bellows will be detected before loss of 

intended functions. The staff’s concerns described in RAIs 3.5.2.11-1 and 3.5.2.11-1.1 are 

resolved.

The applicant stated that for item 3.5.1-78, the applicability is limited to the aging effect of loss 

of material. The staff noted that UFSAR Section 9.1.3 states the normal spent fuel pool design 

maximum temperature is 140 °F, but may exceed this temperature for 2.5 days to a peak 

temperature of 143 °F during refueling. The staff also noted that GALL Report Section IX.D 

states that stainless steel is subject to cracking caused by stress corrosion cracking at 

temperatures above 60 °C (140 °F). The staff further noted that, although not stated as an 
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aging effect in AMR items in LRA Tables 3.5.2-11 and 3.5.2-13, cracking caused by stress 

corrosion cracking is effectively being managed by the aging management activities for loss of 

material in a manner consistent with GALL Report recommendations, which includes the use of 

the Water Chemistry program and monitoring of spent fuel pool water level and the leak chase 

channel drainage system. Therefore, the staff finds the applicant’s determination acceptable.

The staff’s evaluation of the Water Chemistry program is documented in SER Section 3.0.3.1.2. 

Based on its review of components associated with item 3.5.1-78 the staff finds the applicant’s 

proposal to manage loss of material using the Water Chemistry program and monitoring of the 

spent fuel pool water level and leak chase channel drainage system acceptable because the 

Water Chemistry program establishes the plant water chemistry control parameters and their 

limits to mitigate the potential for aging and identifies the actions required if the parameters 

exceed the limits. Also, monitoring of the spent fuel pool water level and the leak chase 

channels is capable of verifying the effectiveness of water chemistry controls by detecting fuel 

pool liner and gate component degradation before loss of intended function. 

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).

3.5.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.5.1 items 3.5.1-15 through 3.5.1-20, 3.5.1-23, 3.5.1-26, 3.5.1-27, 3.5.1-32, 

3.5.1-38, 3.5.1-39, 3.5.1-40, 3.5.1-43, 3.5.1-45, 3.5.1-46, 3.5.1-48, 3.5.1-50, 3.5.1-52 through 

3.5.1-54, 3.5.1-62, 3.5.1-69, 3.5.1-73, 3.5.1-76, 3.5.1-79, and 3.5.1-84, the applicant claimed 

that they were not applicable. The staff reviewed the LRA and UFSAR and confirmed that the 

applicant’s LRA does not have any AMR results applicable to these items.

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 these items only apply to 

PWRs, and finds these items are not applicable to LGS.

LRA Table 3.5.1, item 3.5.1-68 addresses high-strength structural bolting. The GALL Report 

recommends GALL Report AMP XI.S3, “ASME Code Section XI, Subsection IWF,” to manage 

cracking caused by SCC for this component group. The applicant stated that this item is not 

applicable because it does not use high-strength structural bolts subject to SCC in this 

application. The staff lacked sufficient information to evaluate the applicant’s claim because a 

review of UFSAR Sections 3.8.3.1.2, “Reactor Pedestal,” 3.8.6.2.1, “Structural Steel Materials,”

and 3A.7.1.2.2.1, “Downcomer Bracing System” state that high-strength structural steel bolting 

is used. The staff noted that RG 1.65, issued April 2010, states that when stud materials do not 

exceed 170 ksi, they are relatively immune to SCC. By letter dated January 18, 2012, the staff 

issued RAI 3.5.2.1.1-1 requesting the applicant to state whether any of the components 

described in the above three referenced UFSAR sections are within the scope of license 

renewal and whether the bolting tensile strength exceeds 170 ksi.

In its response, dated February 16, 2012, the applicant stated that the bolting discussed in

UFSAR Section 3.8.3.1.2, is ring girder bolting constructed of ASME SA-540 Grade B23, 

Class 5 material having a specified tensile strength of 120 ksi, and UFSAR Section 3.8.4.6.2.1 
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lists A325 or A490 as the high-strength bolts used for structural steel, and SRP-LR Table 3.5-1, 

item 3.5.1-69 states that, “ASTM A 325, F1852, 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.” The 

applicant also stated that UFSAR Section 3A.7.1.2.2.1 bolting is constructed of ASME SA 564, 

Type 630 with H1075 tempering heat treatment material having a specified tensile strength of 

145 ksi.

The staff finds the applicant’s response acceptable because bolting material cited in the 

RAI either does not exceed a tensile strength of 150 ksi, or the conservative tensile strength of 

150 ksi, or the staff has stated that the material is not prone to SCC. The staff’s concern 

described in RAI 3.5.2.1.1-1 is resolved.

3.5.2.1.2 Loss of Material (Spalling, Scaling) 

LRA Table 3.5.1, item 3.5.1-56 addresses reinforced concrete exposed to water-flowing, which 

will be managed for loss of material (abrasion, cavitation and spalling, scaling). For the AMR 

item that cites generic note E, the LRA credits the Structures Monitoring program to manage the 

aging effect for reinforced concrete in the cooling tower basin. The GALL Report recommends 

GALL Report AMP XI.S7, “Regulatory Guide 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants,” or FERC/US Army Corps of Engineers Dam Inspections 

and Maintenance Programs to ensure that this aging effect is adequately managed. 

GALL Report AMP XI.S7 recommends using visual inspection by qualified engineers at intervals 

not to exceed 5 years to monitor for indications of concrete cracking, movements 

(e.g., settlement, heaving, and deflection), conditions at junctions with abutments and 

embankments, loss of material, increase in porosity and permeability, seepage, and leakage to 

manage aging. The staff noted that the Structures Monitoring program will manage the aging of 

reinforced concrete in the cooling tower structures subjected to water-flowing for indications of 

deterioration and distress, including evidence of leaching, loss of material, cracking, and loss of 

bond through visual inspections by qualified personnel, at inspection intervals not to exceed 

5 years, in accordance with station procedures that have been enhanced for consistency with 

ACI 349.3R-02. 

The staff’s evaluation of the Structures Monitoring program is documented in SER 

Section 3.0.3.2.17. In its review of components associated with item 3.5.1-56 for which the 

applicant cited note E, the staff finds the applicant’s proposal to manage aging using the 

Structures Monitoring program acceptable because loss of material (abrasion, cavitation and 

spalling, scaling) will be managed through visual inspections conducted by qualified personnel 

at intervals not to exceed 5 years in accordance with recommendations in ACI 349.3R-02. 

3.5.2.1.3 Loss of Preload and Loss of Material

LRA Table 3.5.1, items 3.5.1-80 and 3.5.1-88 address carbon, low-alloy, and stainless steel 

bolting exposed externally to either uncontrolled indoor air or treated water that will be managed 

for loss of preload because of self-loosening and loss of material caused by general, pitting, and 

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 these aging effects for carbon, low-alloy, and stainless steel bolting. The GALL Report 

recommends GALL Report AMP XI.S6 “Structures Monitoring” program to ensure that these 

aging effects are adequately managed.
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GALL Report AMP XI.S6 recommends using periodic visual inspections, at a frequency not to 

exceed 5 years, to monitor structural bolting for loose bolts, missing or loose nuts, and other 

conditions indicative of loss of preload to ensure that there is no loss of intended function 

between inspections. The staff noted that the Inspection of Overhead Heavy Load and Light 

Load (Related to Refueling) Handling Systems program proposes to manage loss of preload 

and loss of material in carbon, low-alloy, and stainless steel bolting through annual visual 

inspections in accordance with ASME Code B30, which addresses construction, installation, 

operation, inspection, testing, and maintenance of cranes and related equipment. Structural 

components and bolting will be monitored for loss of material caused by corrosion, and bolted 

connections will be monitored for loss of preload. 

The staff’s evaluation of the Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems program is documented in SER Sections 3.0.3.2.6. In its review 

of components associated with items 3.5.1-80 and 3.5.1-88, for which the applicant cited 

generic note E, the staff finds the applicant’s proposal to manage aging using the Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems program 

acceptable because the bolting associated with cranes, hoists, and fuel handling and storage 

equipment will be inspected annually for indications of loss of preload and loss of material.

3.5.2.1.4 Loss of Material Caused by Pitting and Crevice Corrosion

LRA Table 3.5.1, item 3.5.1-85 addresses stainless steel bolting exposed to treated water 

(external) that will be managed for loss of material caused by 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 to manage the aging effect for 

stainless steel bolting for portions of the fuel preparation machine, which is partially exposed to 

treated water. The GALL Report recommends GALL Report AMP XI.S3 “ASME Code 

Section XI, Subsection IWF,” to ensure that this aging effect is adequately managed.

GALL Report AMP XI.S3 recommends using periodic visual inspections of a specified number 

of component supports (including bolting), at an interval of 10 years to manage aging. The staff 

noted that the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) 

Handling Systems program proposes to manage the aging of stainless steel bolting through 

annual visual inspections in accordance with ASME B30, which addresses construction, 

installation, operation, inspection, testing, and maintenance of cranes and related equipment. 

The staff’s evaluation of the Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems program is documented in SER Sections 3.0.3.2.6. In 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 aging using the Inspection of Overhead Heavy 

Load and Light Load (Related to Refueling) Handling Systems program acceptable because the 

stainless steel bolting associated with cranes, hoists, and fuel handling and storage equipment 

will be inspected annually for indications of loss of material.

3.5.2.1.5 Loss of Material

LRA Table 3.5.1, item 3.5.1-93 addresses stainless steel metal components, concrete anchors, 

and bolting exposed to outdoor air that will be managed for loss of material. For the AMR items 

that cite generic note E, the LRA credits the RG 1.127, Inspection of Water-Control Structures 
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Associated with Nuclear Power Plants program to manage the aging effect for stainless steel 

metal components, concrete anchors, and bolting. The GALL Report recommends GALL 

Report AMP XI.S6 “Structures Monitoring” program to ensure that this aging effect is adequately 

managed. 

GALL Report AMP XI.S6 recommends using periodic visual inspections, at a frequency not to 

exceed 5 years, to monitor steel components for loss of material; concrete anchor bolts for loss 

of material, loose or missing nuts, and cracking of concrete around anchor bolts; and structural 

bolting for loose bolts, missing or loose nuts, and other conditions indicative of loss of preload, 

to ensure that there is no loss of intended function between inspections. The staff noted that 

the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

program, when enhanced, proposes to manage the aging of stainless steel metal components, 

concrete anchors, and bolting associated with the spray pond and pump house through visual 

inspections using guidance provided in RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants program and ACI 349.3R-02. 

The staff’s evaluation of the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants program is documented in SER Section 3.0.3.2.18. In 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 aging using the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants program acceptable because the stainless 

steel metal components, concrete anchors, and bolting associated with the spray pond and 

pump house will be inspected visually for loss of material using guidance provided in the 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

program and ACI 349.3R-02. The visual inspection interval and parameters monitored are 

consistent with those recommended in GALL Report AMP XI.S6.

3.5.2.1.6 Reduction or Loss of Isolation Function 

LRA Table 3.5.1, item 3.5.1-94 addresses elastomer supports exposed to either uncontrolled 

indoor air or outdoor air that will be managed for reduction or loss of isolation function. For the 

AMR items that cite generic note E, the LRA credits the Structures Monitoring program to 

manage the aging effect for elastomer supports. The GALL Report recommends GALL Report 

AMP XI.S3, “ASME Code Section XI, Subsection IWF,” program to ensure that this aging effect 

is adequately managed.

GALL Report AMP XI.S3 recommends performing VT-3 examinations for the elastomeric 

vibration elements and supplementing by feel to detect hardening if the vibration isolation 

element is suspect. The staff noted that the Structures Monitoring program, after enhancement, 

proposes to manage the aging of elastomeric supports through visual inspections of elastomeric 

vibration elements and structural seals for cracking, loss of material, and hardening. Visual 

inspections are to be supplemented by manipulation to detect hardening when vibration 

isolation function is suspect.

The staff’s evaluation of the Structures Monitoring program is documented in SER 

Section 3.0.3.2.17. In its review of components associated with item 3.5.1-94 for which the 

applicant cited generic note E, the staff finds that the applicant’s proposal to manage aging 

using the Structures Monitoring program acceptable because reduction or loss of isolation 

function will be managed through visual examinations, supplemented by manipulation to detect 

hardening when vibration isolation function is suspect.
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3.5.2.1.7 Conclusion

The staff evaluated the GALL Report AMR items that the applicant claimed were not applicable. 

On the basis of its review, the staff concludes that the AMR results that the applicant claimed 

were not applicable are not applicable to LGS Units 1 and 2.

As discussed in SER Section 3.0.2.2, for those AMRs that the applicant claimed consistency 

with the GALL Report, the staff evaluated the applicant’s claim of consistency. The staff also 

reviewed information pertaining to the applicant’s consideration of recent operating experience 

and proposals for managing aging effects. On the basis of its review, the staff concludes that 

the AMR results, which the applicant claimed to be consistent with the GALL Report, are 

consistent.

Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their 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 evaluates aging management, as recommended by 

the GALL Report, for the structures and component supports components and provides 

information concerning how it will manage aging effects in the following three areas:

(1) PWR and BWR containments:

‒ aging of inaccessible concrete areas

‒ cracks and distortion because of increased stress levels from settlement; reduction 

of foundation strength, cracking, and differential settlement caused by erosion of 

porous concrete subfoundations if not covered by the Structures Monitoring program

‒ reduction of strength and modulus of concrete structures caused by elevated 

temperature

‒ loss of material caused by general, pitting, and crevice corrosion

‒ loss of prestress caused by relaxation, shrinkage, creep, and elevated temperature

‒ cumulative fatigue damage

‒ cracking caused by SCC

‒ cracking caused by cyclic loading

‒ loss of material (scaling, cracking, and spalling) caused by freeze-thaw

‒ cracking caused by expansion and reaction with aggregate and increase in porosity 

and permeability caused by leaching of calcium hydroxide

(2) safety-related and other structures and component supports:

‒ aging of structures not covered by the Structures Monitoring program
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‒ aging management of inaccessible areas (below-grade inaccessible concrete areas 

of Groups 1-5, and 7-9 structures)

‒ reduction of strength and modulus of concrete structures caused by elevated 

temperature for Group 1-5 structures

‒ aging management of inaccessible areas for Group 6 structures (below-grade 

inaccessible concrete areas)

‒ cracking caused by SCC and loss of material caused by pitting and crevice corrosion 

for Group 7 and 8 stainless steel tank liners

‒ aging of supports not covered by the Structures Monitoring program

‒ cumulative fatigue damage caused by cyclic loading

(3) QA for aging management of nonsafety-related components

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.

3.5.2.2.1 PWR and BWR Containments

3.5.2.2.1.1 Cracking and Distortion Caused by Increased Stress Levels from Settlement; 

Reduction of Foundation Strength, and Cracking Caused by Differential Settlement and Erosion 

of Porous Concrete Subfoundations

LRA Table 3.5.1, items 3.5.1-1 and 3.5.1-2, addresses concrete components exposed to either 

a soil or water-flowing environment. The GALL Report recommends GALL Report AMP XI.S2, 

“ASME Code Section XI, Subsection IWL” program to manage for cracks and distortion caused 

by increased stress levels from settlement, and the GALL Report XI.S6, “Structures Monitoring”

program to manage for a reduction of foundation strength, cracking, and differential settlement 

caused by erosion of porous concrete subfoundations. The applicant stated that these items 

are not applicable because the LGS containments are founded on bedrock, LGS does not rely 

on a de-watering system, and LGS does not use porous concrete subfoundations. The staff 

evaluated the applicant’s claim by reviewing LRA Sections 2.4.11 and 3.5, and finds it 

acceptable because the containment foundations are founded on bedrock, LGS does not 

employ a de-watering system, and LGS does not use porous concrete subfoundations.

3.5.2.2.1.2 Reduction of Strength and Modulus of Elasticity Caused by Elevated Temperature

LRA Table 3.5.1, item 3.5.1-3, addresses concrete structures exposed to either an air-indoor,

uncontrolled or air-outdoor environment that are being managed for reduction of strength and 

modulus of elasticity because of elevated temperature exposure. The SRP-LR states that 

reduction in strength and modulus of concrete structures could occur for concrete structures 

caused by exposure to temperatures in excess of those specified in Subsection CC-3400 of 

ASME Code, Section III, Division 2, for general areas (150 °F) and local areas (200 °F). The 

applicant stated that this item is not applicable because concrete associated with the 

containment is not exposed to temperatures above these limits. The applicant also stated that 
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containment average bulk temperature does not exceed 145 °F and that localized concrete 

temperatures exceeding 200 °F have not been reported. The staff reviewed the UFSAR to

evaluate the applicant’s claim and finds it acceptable because containment concrete 

temperatures are below the limits provided in Subsection CC-3400 of ASME Code Section III, 

Division 2, for both general and local areas.

3.5.2.2.1.3 Loss of Material Caused by General, Pitting, and Crevice Corrosion

(1) Steel elements of inaccessible areas for all types of PWR and BWR containments.

LRA Table 3.5.1, item 3.5.1-4 addresses inaccessible areas of steel elements (drywell 

shell, drywell head) exposed to either an uncontrolled indoor air or concrete

environment. The GALL Report recommends GALL Report AMP XI.S1, “ASME Code 

Section XI, Subsection IWE,” and GALL Report AMP XI.S4, “10 CFR Part 50, 

Appendix J,” to manage for loss of material caused by general, pitting, and crevice 

corrosion. The applicant stated that this item is not applicable because LGS uses 

Mark II concrete containments and this item only applies to Mark III steel containments. 

The staff evaluated the applicant’s claim by reviewing the GALL Report and finds it 

acceptable because this item only applies to BWR Mark III steel containments.

LRA Section 3.5.2.2.1.3 associated with LRA Table 3.5.1, item 3.5.1-5 addresses steel 

elements of accessible and inaccessible areas of containments exposed to either an 

uncontrolled indoor or treated water environment that will be managed for loss of 

material caused by general, pitting, and crevice corrosion by the ASME Code Section XI, 

Subsection IWE, and 10 CFR Part 50, Appendix J programs. 

The applicant addressed the further evaluation criteria of the SRP-LR by stating that 

LRA Table 3.5-1, item 3.5.1-5 will be addressed under the ASME Code Section XI, 

Subsection IWE and 10 CFR Part 50, Appendix J programs to manage the loss of 

material of steel elements in both the accessible and inaccessible areas of the drywell 

and suppression pool liner, liner anchors, integral attachments, drywell head, and 

embedded shell, including the region shielded by the diaphragm floor. The applicant 

also stated that the LGS Mark II concrete containments drywell and suppression pool 

design does not include large ASME Code, Section XI, Subsection IWE liners or other 

surfaces that are inaccessible for inspection caused by coverage by permanent 

insulation such as certain PWRs, nor do they include areas under a concrete floor slab 

as is common in Mark I containments and certain PWRs. The applicant further stated 

that the majority of the LGS ASME Code, Section XI, Subsection IWE surfaces are 

accessible for inspection, the coated liner surfaces are inspected for coating defects 

such as blisters that could indicate corrosion of the carbon steel liner, and that there are 

limited areas that are inaccessible for inspection, including the thickened embedded 

steel structural weldment covered by the outer edges of the steel lined concrete 

diaphragm slab (drywell floor), and also the suppression pool floor liner areas covered 

by the suppression pool columns and areas behind the suction strainers. In addition, the 

applicant stated that the diaphragm slab concrete floor is lined with steel that is welded 

to the containment wall liner, the suppression pool concrete floor is lined with steel that 

is welded to the suppression pool wall liner such that there are no concrete to steel 

interface surfaces that would require a moisture barrier seal, and the LGS BWR Mark II 

concrete containment design does not result in corrosive materials contacting the liner. 

Also, the applicant stated that the primary containment atmosphere is inerted with 
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nitrogen during operation, and that some general corrosion and pitting have been 

identified in underwater portions of the suppression pool that will be addressed during 

the period of extended operation by enhancing the ASME Code Section XI, 

Subsection IWE program. Finally, the applicant stated that while some general 

corrosion and pitting has been identified by ASME Code, Subsection IWE examinations, 

the corrosion is primarily in underwater portions of the suppression pool, the corrosion 

has not been significant, and the ASME Code Section XI, Subsection IWE program will 

be enhanced before the period of extended operation to address the conditions 

identified.

The staff reviewed the applicant’s evaluation for consistency with SRP-LR 

Section 3.5.2.2.1.3 item 1 which states that loss of material caused by general, pitting, 

and crevice corrosion could occur in steel elements of inaccessible areas for all types of 

PWR and BWR containments exposed to an uncontrolled, indoor air or treated water 

environment. 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, and the GALL Report recommends further evaluation of plant-specific programs 

to manage this aging effect if corrosion is indicated from the ASME Code, Subsection 

IWE examinations. The staff noted that during regular inspections in accordance the 

applicant’s ASME Code Section XI, Subsection IWE program some loss of material due 

general corrosion was identified in the suppression pool liner plate. The applicant 

performed further evaluation of this condition and determined that enhancement to the 

ASME Code Section XI, Subsection IWE aging management program is necessary to 

monitor and manage this degradation of the suppression pool liner plate. The staff 

reviewed this enhancement and determined it does not address the staff concern on 

how degradation in the coating can be used to determine the scope and extent of the 

augmented inspection of the liner plate condition and thickness. The details of the staff 

evaluation and concerns are described in SER Section 3.0.3.2.13. This item is 

unresolved and is currently being tracked as Open Item 3.0.3.2.13-1.

(2) Steel torus shell of Mark I containments

LRA Section 3.5.2.2.1.3 associated with LRA Table 3.5.1, item 3.5.1-6 addresses loss of 

material caused by general, pitting, and crevice corrosion in the steel torus shell of 

Mark I containments exposed to either an uncontrolled indoor air or treated water 

environment. The applicant stated that this item is not applicable because LGS uses a 

Mark II concrete containment incorporating a suppression pool and not a torus. The 

staff evaluated the applicant’s claim by reviewing LRA Sections 2.4.11 and 3.5 and finds 

it acceptable because the LGS uses Mark II concrete containments that do not include a 

torus. 

(3) 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

LRA Section 3.5.2.2.1.3 associated with LRA Table 3.5.1, item 3.5.1-7, addresses steel 

torus ring girders and downcomers of Mark I containments, downcomers of Mark II 

containments, and the interior surface of the suppression chamber shell of Mark III 

containments exposed to either a treated water or uncontrolled indoor air environment 

that will be managed for loss of material caused by general, pitting, and crevice 
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corrosion by the ASME Code Section XI, Subsection IWE program. The LRA further 

stated that item 3.5.1-7 is applicable to Mark I and Mark III steel containments and is not 

applicable to the LGS Mark II concrete containment; therefore, further evaluation of the 

plant-specific programs is not required for this item. The applicant also stated that the 

ASME Code Section XI, Subsection IWE program will be used to manage the loss of 

material of the LGS Mark II steel diaphragm floor liner, downcomers, and vacuum relief 

valve piping as addressed by item 3.5.1-31.

The criteria in SRP-LR Section 3.5.2.2.1.3, item 3, states that loss of material caused by

general, pitting, and crevice corrosion could occur in steel torus ring girders and 

downcomers of Mark I containments, downcomers of Mark II containments, and the 

interior surface of the suppression chamber shell of Mark III containments exposed to 

either a treated water or an uncontrolled indoor air environment. The SRP-LR also 

states that the existing program relies on the ASME Code Section XI, Subsection IWE 

program to manage this aging effect, and recommends further evaluation of 

plant-specific programs to manage this aging effect if corrosion is significant. 

The staff’s evaluation of the ASME Code Section XI, Subsection IWE program is 

documented in SER Sections 3.0.3.2.13. The staff noted that the ASME Code 

Section XI, Subsection IWE program will be used to manage the loss of material of the 

LGS Mark II steel diaphragm floor liner, downcomer piping, and vent system. The staff 

reviewed SRP Section 3.5.2.2.1.3, item 3 and Table 3.5-1, item 7, associated GALL 

Report items II.B1.1.CP-109 and II.B.3.1.CP-158, and confirmed that LRA Table 3.5.1, 

item 3.5.1-7 is applicable to Mark I and Mark III containments only; therefore, further 

evaluation of this item at LGS is not required. In addition, the staff reviewed SRP Table 

3.5.1, item 3.5.1-31 that address the pressure-retaining bolting and steel elements of the 

downcomer pipes, and found that ASME Code Section XI, Subsection IWE program is 

acceptable to manage aging for the loss of material caused by general, pitting, and 

crevice corrosion. The SRP-LR does not recommend further evaluation for this item. 

However, the applicant performed further evaluation and developed an acceptable 

inspection and recoating criteria based on original design calculations and supplemental 

analysis; however, the staff is concerned that this criterion is not identified in the 

applicant’s aging management program. The details of the staff evaluation and concern 

are described in SER Section 3.0.3.2.1.3. This item is unresolved and is currently being 

tracked as Open Item 3.0.3.2.13-1.

Based on the programs identified, the staff concludes, pending resolution of Open Item 

3.0.3.2.13-1, that the applicant’s programs meet SRP-LR Section 3.5.2.2.1.3 criteria. For those 

items associated with LRA Section 3.5.2.2.1.3, the staff concludes, pending resolution of 

OI-3.0.3.2.13-1, 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).

3.5.2.2.1.4 Loss of Prestress Caused by 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 addresses loss of 

prestress caused by relaxation, shrinkage, creep, and elevated temperature in steel 

prestressing tendons exposed to either an air-indoor, uncontrolled or air-outdoor environment. 
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The applicant stated that this item is not applicable because LGS concrete containments are not

prestressed and, therefore, do not incorporate steel prestressing tendons, so a TLAA is not 

required. The staff evaluated the applicant’s claim by reviewing LRA Sections 2.4.11 and 3.5 

and finds it acceptable because the LGS containments use Mark II reinforced concrete 

containments that do not contain prestressing tendons.

3.5.2.2.1.5 Cumulative Fatigue Damage

LRA Section 3.5.2.2.1.5 associated with LRA Table 3.5.1, item 3.5.1-9, addresses the TLAAs 

(if CLB fatigue analyses exist) of suppression pool steel shells (including welded joints) and 

penetrations (including penetration sleeves, dissimilar metal welds, and penetration bellows) for 

all types of PWR and BWR containments and BWR vent header, vent line bellows, and 

downcomers exposed to either an uncontrolled indoor air, treated water, or outdoor air 

environment that will be managed for cumulative fatigue damage caused by cyclic loading by a 

TLAA.

TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c). The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that fatigue is a TLAA as 

defined by 10 CFR 54.3. The applicant stated that evaluation of fatigue as a TLAA for the LGS 

primary containment liner and penetration sleeves, refueling bellows, and downcomers is 

addressed in LRA Sections 4.5, 4.6.7, and 4.6.8.

The staff’s evaluation of the TLAAs is documented in SER Chapter 4. In its review of 

components associated with item 3.5.1-9, the staff finds that the applicant has met the further 

evaluation criteria, and the applicant’s proposal to manage aging using TLAAs is acceptable 

because the required TLAAs have been completed.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.1.5 criteria. For those items that apply to 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 

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

3.5.2.2.1.6 Cracking Caused by SCC

LRA Table 3.5.1, item 3.5.1-10, and LRA Section 3.5.2.2.1.6 state that cracking caused by SCC

is not an AERM for LGS stainless steel containment penetration sleeves, bellows, and dissimilar 

metal welds. The GALL Report indicates that the existing aging management relies on ASME 

Code Section XI, Subsection IWE and 10 CFR Part 50, Appendix J programs to manage this 

aging effect. The GALL Report also recommends further evaluation for detection of the aging 

effect. The applicant stated that the LGS primary containment design does not use penetration 

bellows and LRA item 3.5.1-10 is not applicable to the LGS penetration sleeves that are carbon 

steel. In addition, the applicant indicated that while dissimilar welds and stainless steel CRD 

lines associated with penetrations exist, they are exposed to indoor air and are not exposed to a 

corrosive environment such that all the parameters necessary for SCC to occur are not present. 

The applicant further stated that LGS and industry operating experience has not identified 

cracking caused by SCC as an applicable aging effect for dissimilar metal welds on Mark II 

containment penetration sleeves and CRD lines in a BWR indoor-air environment. 
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In its review, the staff finds the applicant’s claim acceptable because the applicant confirmed 

that Units 1 and 2 do not use penetration bellows, consistent with the staff’s review of the 

UFSAR that does not identify any containment penetration bellow for the units. LRA 

item 3.5.1-10 is not applicable to the containment penetration sleeves made of carbon steel, 

consistent with the GALL Report. The applicant confirmed that the industry and plant-specific 

operating experience has not identified cracking caused by SCC of the dissimilar metal welds 

on the Mark II containment penetrations and stainless steel CRD line associated with 

penetrations exposed to BWR indoor air, and the applicant further confirmed that its 

containment penetrations are not exposed to a corrosive environment that involves all the 

factors necessary to cause SCC. In addition, the staff finds that the existing ASME Code 

Section XI, Subsection IWE and 10 CFR Part 50, Appendix J programs are applied to the 

containment penetration components as indicated in LRA item 3.5.1-35 to manage aging of 

these components.

3.5.2.2.1.7 Loss of Material (Scaling, Spalling) and Cracking Caused by 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 (scaling, spalling) and cracking caused by freeze-thaw in concrete in inaccessible 

areas of dome, wall, basemat, ring girders, and buttresses exposed to a freeze-thaw 

environment. The applicant stated that this item is not applicable because the primary 

containments at LGS are enclosed and sheltered within an indoor air environment by reactor 

enclosures (secondary containments), and, therefore, are not subject to freeze-thaw conditions 

that would produce loss of material (spalling, scaling) or cracking. The staff evaluated the 

applicant’s claim by reviewing LRA Sections 2.2.14 and 3.5 and finds it acceptable because the 

LGS containments use Mark II reinforced concrete containments that are enclosed by 

secondary containments and, therefore, are not exposed to environmental conditions 

(e.g., moisture and freeze-thaw temperature cycles) that would produce loss of material 

(scaling, spalling) or cracking.

3.5.2.2.1.8 Cracking Caused by Expansion from Reaction with Aggregates

LRA Section 3.5.2.2.1.8 associated with LRA Table 3.5.1, item 3.5.1-12 addresses cracking 

caused by expansion from reaction with aggregates in concrete in inaccessible areas 

(containment, dome, wall, basemat, ring girders, buttresses, and concrete fill-in annulus) 

exposed to any environment. The GALL Report notes that a plant-specific AMP is not required 

to manage cracking and expansion caused by reaction with aggregate or concrete in 

inaccessible areas if: (1) as described in NUREG-1557, investigations, tests, and petrographic 

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 it is demonstrated that the in-place concrete can perform its intended function. 

The applicant stated that this item is not applicable because fine and course aggregates used in 

the concrete conform to ASTM C33, petrographic examinations of aggregates were performed 

in accordance with ASTM C295, ASTM C289, and other ASTM tests were conducted 

demonstrating that reactive aggregates were not used, and the concrete structures were 

constructed in accordance with ACI 301, ACI 318, and ACI 605 recommendations. The staff 

evaluated the applicant’s claim by reviewing UFSAR Section 3.8.6 and finds it acceptable 

because the aggregate materials were evaluated for potential reactivity using investigations, 

tests, and petrographic examinations recommended in NUREG-1557. 
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3.5.2.2.1.9 Increase in Porosity and Permeability caused by 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 concrete in inaccessible areas (containment, dome, wall, basemat, and ring girders, 

and buttresses) exposed to water-flowing environment. The GALL Report notes that a 

plant-specific AMP is not required to manage increase in porosity and permeability and loss of 

strength caused by leaching of calcium hydroxide and carbonation of concrete in inaccessible 

areas if: (1) there is evidence in the accessible areas that the flowing water has not caused 

leaching and carbonation, and (2) evaluation determines that the observed leaching of calcium 

hydroxide and carbonation in accessible areas has no impact on intended function of the 

concrete structure. 

The applicant stated that this item is not applicable because inspections of LGS primary 

containment structures have not identified any leaching in the accessible primary containment 

areas that may affect the intended function. The applicant also stated that the primary 

containment is completely enclosed and sheltered as a result of being located within the indoor 

air environment of the reactor enclosure (secondary containment), the interior of the primary 

containment is lined with steel, and there is no flowing water through concrete that could be 

associated with this aging effect. The staff evaluated the applicant’s claim by reviewing LRA 

Sections 2.4.11 and 3.5 and finds it acceptable because the LGS containments are completely 

enclosed and sheltered as a result of being located within the indoor air environment of the 

reactor enclosures, no evidence of leaching has been observed on accessible surfaces that 

could impact intended functions, and the containment is not subjected to flowing water.

3.5.2.2.2 Safety-Related and Other Structures and Component Supports

3.5.2.2.2.1 Aging Management of Inaccessible Areas

(1) Loss of material (spalling, scaling) and cracking caused by freeze-thaw in below-grade 

inaccessible concrete areas of Groups 1-2, 5, and 7-9 structures.

LRA Section 3.5.2.2.2.1 associated with LRA Table 3.5.1, item 3.5.1-42 addresses 

inaccessible areas of Groups 1-3, 5, and 7-9 concrete structures exposed to freeze-thaw 

conditions, which will be managed for loss of material (spalling, scaling) and cracking by 

the Structures Monitoring program. The criteria in SRP-LR Section 3.5.2.2.2.1 item 1 

states that loss of material (spalling, scaling) and cracking could occur for below-grade 

inaccessible areas of Groups 1-3, 5, and 7-9 concrete structures exposed to 

freeze-thaw. The SRP-LR also states that further evaluation is required for plants that 

are located in moderate to severe weathering conditions (weathering index greater than 

100 day-inches per year) as noted in NUREG-1557. The GALL Report states that a 

plant-specific program is not required if documented evidence confirms that the existing 

concrete had an air content of 3 percent to 8 percent and subsequent inspection did not 

exhibit degradation related to freeze-thaw. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that the Structures Monitoring program will 

be used to manage loss of material (spalling, scaling) and cracking in both accessible 

and inaccessible areas. The applicant also stated that the concrete structures at LGS 

are designed and constructed in accordance with ACI 318-71 and ACI 301-66, and the 

concrete mixture design provides for low permeability and adequate air entrainment 
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(3 percent to 7 percent) resulting in good freeze-thaw resistance. The applicant further 

stated that operating experience has not identified significant loss of material (spalling, 

scaling) and cracking due freeze-thaw for in-scope reinforced concrete structures and 

the condition of accessible and above-grade concrete is used as an indicator for the 

condition of the inaccessible and below-grade structural components and provides 

reasonable assurance that degradation of inaccessible structural components will be 

detected before a loss of an intended function. In addition, the applicant stated that in 

the event that unacceptable conditions caused by freeze thaw are identified in the 

accessible areas of structures, procedures require that the extent of the condition be 

determined and additional inspections or evaluations would address inaccessible and 

below grade portions of any affected structure, and LGS will examine exposed portions 

of the below-grade concrete when excavated for any reason in accordance with the 

Structures Monitoring program.

The staff’s evaluation of the Structures Monitoring program is documented in SER 

Section 3.0.3.2.16. The staff noted that concrete structures at LGS are designed and 

constructed in accordance with ACI 318-71 and ACI 301-66 and the concrete mixture 

design provides for low permeability and adequate air entrainment (3 percent to 

7 percent) such that the concrete has good freeze-thaw resistance. Operating 

experience has not identified any freeze-thaw damage that would impact a structure’s 

intended function. In its review of items associated with 3.5.1-42, the staff finds that the 

applicant has met the further evaluation criteria, and the applicant’s proposal to manage 

aging using the Structures Monitoring program is acceptable because the concrete 

structures at LGS are designed and constructed in accordance with ACI 318-71 and 

ACI 301-66, the concrete mixture design provides for low permeability and adequate air 

entrainment (3 percent to 7 percent) such that the concrete has good freeze-thaw 

resistance, accessible concrete structures will be managed for this aging effect under 

the Structures Monitoring program with results used as an indicator for the condition of 

inaccessible and below-grade concrete structures, and LGS will examine exposed 

portions of the below-grade concrete when excavated for any reason in accordance with 

the Structures Monitoring program.

(2) Cracking caused by expansion and reaction with aggregates of Groups 1-5 and 7-9 

structures.

LRA Table 3.5.1, item 3.5.1-43, addresses concrete in inaccessible areas of Groups 1-5, 

and 7-9 concrete structures exposed to any environment. The GALL Report 

recommends further evaluation to determine if a plant-specific AMP is needed. The 

GALL Report also notes that a plant-specific AMP is not required to manage cracking 

and expansion caused by reaction with aggregate or concrete in inaccessible areas if: 

(1) as described in NUREG-1557, investigations, tests, and petrographic 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 it is demonstrated that the in-place concrete can perform its intended 

function. The applicant stated that this item is not applicable because fine and course 

aggregates used in the concrete conform to ASTM C33, petrographic examinations of 

aggregates were performed in accordance with ASTM C295, ASTM C289 and other 

ASTM tests were conducted that demonstrate that reactive aggregates were not used, 

and the concrete structures were constructed in accordance with ACI 301, ACI 318, and 
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ACI 605 recommendations. The staff evaluated the applicant’s claim by reviewing 

UFSAR Section 3.8.6 and finds it acceptable because the aggregate materials were 

evaluated for potential reactivity using investigations, tests, and petrographic 

examinations recommended in NUREG-1557. 

(3) Cracking and distortion because of increased stress levels from differential settlement 

for Groups 1-9 structures and reduction in foundation strength and cracking caused by

differential settlement and erosion of porous concrete subfoundations of Groups 1-3, and 

5-9 structures.

LRA Section 3.5.2.2.2.1 associated with LRA Table 3.5.1, item 3.5.1-44, addresses 

concrete in inaccessible areas of Groups 1-9 structures exposed to differential 

settlement that will be managed for cracking and distortion by the Structures Monitoring 

program. The criteria in the SRP-LR 3.5.2.2.2.1 item 3 states that cracking and 

distortion could occur in Groups 1-9 concrete structures exposed to differential 

settlement or porous concrete subfoundations. The GALL Report recommends further 

evaluation under AMP XI.S6, “Structures Monitoring” to manage differential settlement 

for this component group and if a de-watering system is relied upon for control of 

settlement, then proper functioning of the de-watering system is required through the 

period of extended operation. The applicant addressed the further evaluation criteria of 

the SRP-LR by stating that the Structures Monitoring program will be used to manage 

cracking and distortion of concrete in accessible and inaccessible locations for structures 

founded on soil, all Category I plant facilities are founded on bedrock, and LGS does not 

rely on a de-watering system. 

The staff’s evaluation of the Structures Monitoring program is documented in SER 

Section 3.0.3.2.17. The staff noted that the Structures Monitoring program will be used 

to manage cracking and distortion of concrete in accessible and inaccessible locations 

for structures founded on soil, all Category I plant facilities are founded on bedrock, and 

LGS does not rely on a de-watering system. In its review of components associated with 

item 3.5.1-44, the staff finds that the applicant has met the further evaluation criteria, and 

the applicant’s proposal to manage aging using the Structures Monitoring program is 

acceptable because it is the AMP recommended in the GALL Report, LGS Category I

facilities are founded on bedrock, and LGS does not rely on a de-watering system.

LRA Table 3.5.1, items 3.5.1-45 and 3.5.1-46, addresses concrete in inaccessible areas 

of Groups 1-3 and 5-9 structures exposed to differential settlement and erosion of 

porous concrete subfoundations. The GALL Report recommends further evaluation 

under AMP XI.S6, “Structures Monitoring” to manage differential settlement for this 

component group if a de-watering system is relied upon for control of settlement. The 

applicant stated that these items are not applicable because the LGS containments are 

founded on bedrock, LGS does not rely on a de-watering system, and LGS does not use 

porous concrete subfoundations. The staff evaluated the applicant’s claim by reviewing 

LRA Sections 2.4.11 and 3.5 and finds it acceptable because the containment 

foundations are founded on bedrock, LGS does not employ a de-watering system, and 

LGS does not use porous concrete subfoundations. 
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(4) Increase in porosity and permeability and loss of strength caused by leaching of calcium 

hydroxide and carbonation for Groups 1-5 and 7-9 structures

LRA Section 3.5.2.2.2 associated with LRA Table 3.5.1, item 3.5.1-47 addresses 

concrete in inaccessible areas, exterior above- and below-grade, of Groups 1-5 and 7-9 

structures exposed to water-flowing that will be managed for increase in permeability 

and loss of strength because of leaching of calcium hydroxide and carbonation by the 

Structures Monitoring program. The criteria in SRP-LR states that a plant-specific AMP

is not required to manage increase in porosity and permeability and loss of strength 

because of leaching of calcium hydroxide and carbonation of concrete in inaccessible 

areas if: (1) there is evidence in the accessible areas that the flowing water has not 

caused leaching and carbonation, and (2) evaluation determines 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 the 

Structures Monitoring program will be used to manage increase in porosity and 

permeability, and loss of strength for concrete and exterior above- and below-grade 

accessible and inaccessible concrete and foundations. The applicant also stated that 

leaching of calcium hydroxide is applicable for a water-flowing environment, which may 

occur to a limited extent in accessible or inaccessible portions of in-scope structures. 

The applicant further stated that the effects of carbonation have not been observed on 

LGS concrete, and operating experience has found that increase in porosity and 

permeability and loss of strength caused by these mechanisms is not significant and is,

therefore, adequately managed by the Structures Monitoring program. In addition, the 

applicant stated that the reinforced concrete is designed and constructed to meet 

ACI and ASTM Specifications, including ACI 318, to produce durable concrete, and LGS 

will examine exposed portions of the below-grade concrete when excavated for any 

reason in accordance with the Structures Monitoring program.

The staff’s evaluation of the Structures Monitoring program is documented in SER 

Section 3.0.3.2.17. In its review of items associated with 3.5.1-47, the staff finds that the 

applicant has met the further evaluation criteria, and the applicant’s proposal to manage 

aging using the Structures Monitoring program is acceptable because it is the AMP

recommended in the GALL Report, the reinforced concrete is designed and constructed 

to meet ACI and ASTM specifications, including ACI 318, to produce durable concrete, 

the effects of carbonation have not been observed on LGS concrete, operating 

experience has found that increase in porosity and permeability and loss of strength 

caused by these mechanisms is not significant, and exposed portions of below-grade 

concrete will be examined when excavated for any reason.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.2.1 criteria. For those items that apply to LRA 

Section 3.5.2.2.2.1, 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 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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3.5.2.2.2.2 Reduction of Strength and Modulus Caused by Elevated Temperatures

LRA Table 3.5.1, item 3.5.1-48, addresses reduction in strength and modulus of elasticity of 

Groups 1-5 concrete structures that could result because of elevated temperature exposure. 

The GALL Report recommends further evaluation under a plant-specific program for concrete 

structures exposed to temperatures in excess of those specified in Subsection CC-3400 of 

ASME Code, Section III, Division 2 for general areas (150 °F) and local areas (200 °F). The 

applicant stated that this item is not applicable because concrete associated with the Groups

1-5 concrete structures is not exposed to temperatures above these limits. The applicant also 

stated that containment average bulk temperature does not exceed 145 °F for Group 4 

structures within the primary containment, Group 5 structures (i.e., refuel floor and spent fuel 

storage pool) are part of the reactor enclosure, which is a Group 1 structure, and the spent fuel 

pool water temperature is maintained below 140 °F under normal plant operating conditions. 

The applicant further stated that Groups 1, 3, and 4 concrete structural components are not 

subject to local temperatures greater than 200 °F, process piping operating at temperatures 

greater than 200 °F is insulated through penetrations, and plant operating experience has not 

identified elevated general or local area temperatures of concern to concrete structural 

components. The staff evaluated the applicant’s claim and finds it acceptable because, as 

noted in the UFSAR, concrete temperatures are below the limits provided in 

Subsection CC-3400 of ASME Code Section III, Division 2, for both general and local areas.

3.5.2.2.2.3 Aging Management of Inaccessible Areas for Group 6 Structures

SRP-LR Section 3.5.2.2.2.3 addresses aging management of inaccessible areas for Group 6 

structures (below-grade inaccessible concrete areas) and recommends further evaluation for 

inaccessible areas of certain Group 6 structure/aging effect combinations as identified below 

whether they are covered by inspections in accordance with the GALL Report, Chapter XI.S7, 

“Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants,” or FERC/US Army Corps of Engineers dam inspection and maintenance procedures. 

(1) Loss of material (spalling, scaling) and cracking caused by freeze-thaw that could occur 

in below-grade inaccessible concrete areas of Group 6 structures. 

LRA Section 3.5.2.2.2.3 associated with LRA Table 3.5.1, item 3.5.1-49, addresses 

below-grade concrete components of Group 6 structures (inaccessible areas) and 

exterior above- and below-grade foundation and interior slab concrete exposed to 

outdoor air environment that will be managed for loss of material (spalling, scaling) and 

cracking caused by freeze-thaw by the RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants program. The criteria in SRP-LR 3.5.2.2.3 states 

that loss of material (spalling, scaling) and cracking caused by freeze-thaw could occur 

in below-grade inaccessible concrete areas of Group 6 structures and recommends 

further evaluation of this aging effect for inaccessible areas for plants located in 

moderate to severe weathering conditions. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that the RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants program will be used to 

manage loss of material (spalling, scaling) and cracking in both accessible and 

inaccessible areas. The applicant also stated that the LGS Group 6 structures are 

located in a region where weathering conditions are considered; however, these 

concrete structures are designed and constructed in accordance with ACI 318-71 and 

ACI 301-66 as described in the UFSAR that provides for low permeability and adequate 
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air entrainment (3 percent to 7 percent) such that the concrete has good freeze-thaw 

resistance. The applicant further stated that operating experience review of structural 

concrete for in-scope structures has not identified significant loss of material (spalling, 

scaling) and cracking caused by freeze-thaw. The applicant further stated that the 

condition of accessible and above-grade concrete is used as an indicator of the 

condition of the inaccessible and below-grade structural components and provides 

reasonable assurance that degradation of inaccessible structural components will be 

detected before a loss of an intended function. The applicant stated that LGS examines 

exposed portions of the below-grade concrete, when excavated for any reason in 

accordance with the Structures Monitoring program.

The staff’s evaluation of the RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants program is documented in SER 

Section 3.0.3.2.18. The staff noted that concrete structures at LGS are designed and 

constructed in accordance with ACI 318-71 and ACI 301-66 and the concrete mixture 

design provides for low permeability and adequate air entrainment (3 percent to 

7 percent) such that the concrete has good freeze-thaw resistance, and operating 

experience has not identified any freeze-thaw damage that would affect a structure’s 

intended function. In its review of items associated with 3.5.1-49, the staff finds that the 

applicant has met the further evaluation criteria, and the applicant’s proposal to manage 

aging using the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants program is acceptable because: (1) the concrete structures at 

LGS are designed and constructed in accordance with ACI 318-71 and ACI 301-66, 

(2) the concrete mixture design provides for low permeability and adequate air 

entrainment (3 percent to 7 percent) such that the concrete has good freeze-thaw 

resistance, (3) accessible concrete structures will be managed for this aging effect under 

the Structures Monitoring program with results used as an indicator for the condition of 

inaccessible and below-grade concrete structures, and (4) LGS will examine exposed 

portions of the below-grade concrete when excavated for any reason in accordance with 

the Structures Monitoring program.

(2) Cracking caused by expansion and reaction with aggregates that could occur in 

below-grade inaccessible concrete areas of Group 6 structures

LRA Table 3.5.1, item 3.5.1-50 addresses concrete in inaccessible areas of 

Group 6 concrete structures exposed to any environment. The GALL Report 

recommends further evaluation to determine if a plant-specific AMP is needed. The 

GALL Report also states that a plant-specific AMP is not required to manage cracking 

and expansion caused by reaction with aggregate or concrete in inaccessible areas if: 

(1) as described in NUREG-1557, investigations, tests, and petrographic 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 it is demonstrated that the in-place concrete can perform its intended 

function. The applicant stated that this item is not applicable because fine and course 

aggregates used in the concrete conform to ASTM C33, petrographic examinations of 

aggregates were performed in accordance with ASTM C295, ASTM C289 and other 

ASTM tests were conducted that demonstrate that reactive aggregates were not used, 

the concrete structures were constructed in accordance with ACI 318, and plant 

operating experience has not found cracking associated with expansion caused by
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reaction with aggregates on LGS Group 6 concrete structures. The applicant also stated 

that the RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear 

Power Plants” AMP will continue to inspect and monitor Group 6 concrete structures for 

cracking caused by any mechanism. The staff evaluated the applicant’s claim by 

reviewing UFSAR Section 3.8.6 and finds it acceptable because the aggregate materials 

were evaluated for potential reactivity using investigations, tests, and petrographic 

examinations recommended in NUREG-1557, operating experience has not identified 

cracking associated with reactive aggregates, and structures will be managed for this 

aging effect by the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants program. 

(3) Increase in porosity and permeability and loss of strength caused by leaching of calcium 

hydroxide and carbonation that could occur in below-grade inaccessible concrete areas 

of Group 6 structures

LRA Section 3.5.2.2.2 associated with LRA Table 3.5.1, item 3.5.1-51 addresses 

concrete in inaccessible areas of Group 6 concrete structures exposed to flowing water,

which will be managed for increase in porosity and permeability and loss of strength 

caused by 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 states that further evaluation is required to determine if a plant-specific AMP is 

required to manage increase in porosity and permeability and loss of strength caused by

leaching of calcium hydroxide and carbonation of concrete in inaccessible areas. The 

SRP-LR also 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, 

and (2) evaluation determines that the observed leaching of calcium hydroxide and 

carbonation in accessible areas has no impact on intended function of the concrete 

structure. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants program will be used to manage increase in porosity and 

permeability and loss of strength caused by leaching and carbonation for Group 6 

structures for accessible and inaccessible above and below grade and foundation 

concrete. The applicant also stated that leaching of calcium hydroxide is applicable for a 

flowing water environment, which may occur to a limited extent in accessible or 

inaccessible portions of in-scope structures. The applicant further stated that the effects 

of carbonation have not been observed on LGS concrete and operating experience has 

found that increase in porosity and permeability and loss of strength caused by these 

mechanisms is not significant; therefore, it is adequately managed by the RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants program. 

In addition, the applicant stated that the reinforced concrete is designed and constructed 

to meet ACI and ASTM Specifications, including ACI 318, to produce durable concrete, 

and LGS will examine exposed portions of the below-grade concrete when excavated for 

any reason in accordance with the Structures Monitoring program.

The staff’s evaluation of the Regulatory Guide 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants program is documented in SER 

Section 3.0.3.2.18. The staff noted that the LGS reinforced concrete is designed and 

constructed to meet ACI and ASTM specifications, including ACI 318, to produce 

durable concrete, the effects of carbonation have not been observed on LGS concrete, 

operating experience has found that increase in porosity and permeability and loss of 
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strength caused by these mechanisms is not significant, and exposed portions of 

below-grade concrete will be examined when excavated for any reason. In its review of 

items associated with 3.5.1-51, the staff finds that the applicant has met the further 

evaluation criteria, and the applicant’s proposal to manage aging using the RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants program is 

acceptable because the reinforced concrete is designed and constructed to meet 

ACI and ASTM Specifications, including ACI 318, to produce durable concrete, the 

effects of carbonation have not been observed on LGS concrete, operating experience 

has found that increase in porosity and permeability and loss of strength caused by

these mechanisms is not significant, and exposed portions of below-grade concrete will 

be examined when excavated for any reason.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.2.3 criteria. For those items that apply to LRA 

Section 3.5.2.2.2.3, 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).

3.5.2.2.2.4 Cracking Caused by Stress Corrosion Cracking, and Loss of Material caused by

Pitting and Crevice Corrosion

LRA Section 3.5.2.2.4, associated with LRA Table 3.5.1, item 3.5.1-52 addresses cracking and 

loss of material caused by pitting and crevice corrosion of Groups 7 and 8 stainless steel tank 

liners exposed to standing water. The applicant stated that this item is not applicable because 

LGS does not have Group 7 or Group 8 structures. The staff reviewed LRA Section 2.4 and the 

UFSAR and confirmed that the applicant’s LRA does not have any AMR results that are 

applicable to these items. 

3.5.2.2.2.5 Cumulative Fatigue Damage Caused by Fatigue

LRA Section 3.5.2.2.2.5, which is associated with LRA Table 3.5.1, item 3.5.1.53, addresses 

cumulative fatigue damage caused by cyclic loading in component support members, anchor 

bolts, and welds for Groups B1.1, B1.2, and B1.3 component supports exposed to uncontrolled 

indoor air. The applicant stated its CLB does not contain any fatigue analysis for component 

support members, bolted connections, or support anchorage to building structures. The staff 

reviewed the LGS Units 1 and 2 UFSAR and LRA Section 4 and confirmed that the applicant’s 

CLB does not contain fatigue analyses that were identified as TLAAs as required by 

10 CFR 54.21(c)(1) for component support members, anchor bolts, and welds for Groups B1.1, 

B1.2, and B1.3; therefore, the staff finds the applicant’s claim acceptable.

3.5.2.2.3 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.

3.5.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

In LRA Tables 3.5.2-1 through 3.5.2-17, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with or not addressed 

in the GALL Report.
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In LRA Tables 3.5.2-1 through 3.5.2-17, the applicant indicated, via 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.

3.5.2.3.1 220 and 500 kV Substations – Summary of Aging Management Evaluation

The staff reviewed LRA Table 3.5.2-1, which summarizes the results of AMR evaluations for 

220 kV and 500 kV substations component groups. The staff’s review did not identify any items 

with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for this system are consistent with the GALL Report.

3.5.2.3.2 Admin Building Shop and Warehouse – Summary of Aging Management Evaluation

The staff reviewed LRA Table 3.5.2-2, which summarizes the results of AMR evaluations for the 

admin building shop and warehouse component groups.

In LRA Tables 3.5.2-2, 3.5.2-3, and 3.5.2-16, the applicant stated that for polyvinyl chloride 

(PVC) roofing scuppers exposed to outdoor air, there is no aging effect and no AMP is 

proposed. The AMR items cite generic note J.

The staff reviewed the associated items in the LRA and could not confirm that no credible aging 

effects are applicable for this component, material, and environment combination. The staff 

lacked sufficient information to conclude that no aging management is required for exposure to 

the outdoor air environment because the type of PVC material could influence the effect of 

exposure to outdoor UV light. By letter dated January 18, 2012 the staff issued RAI 3.5.2.3.2-1 

requesting the applicant to state the specific type of PVC material used in the roofing scuppers

within the scope of license renewal and the basis for why exposure to outdoor UV does not 

require age managing of these components.

In its response, dated February 16, 2012, the applicant stated that the specific PVC compound 

that is used for the roofing scuppers is not known. The PVC material is a commercial grade 

product and is assumed to not contain additives that would inhibit UV deterioration. The 

potential aging effect of PVC caused by sunlight UV is cracking caused by a change in material 

properties. Cracking is unlikely to prevent the scuppers from directing flow through the concrete 

opening; however, the PVC roofing scuppers will be managed for cracking by the Structures 
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Monitoring AMP. The applicant revised LRA Tables 3.5.2-2, 3.5.2-3, and 3.5.2-16 to reflect 

cracking as an AERM for these items and designated the Structures Monitoring program to 

manage the aging.

The staff finds the applicant’s response acceptable because the applicant identified the correct 

aging effect, cracking, for a polymeric component exposed to outdoor UV and will manage this 

aging using the Structures Monitoring program, which conducts visual inspections capable of 

detecting cracking on a 5-year inspection schedule. The staff’s concern described in 

RAI 3.5.2.3.2-1 is resolved. However, LRA Section B.2.1.35, Structures Monitoring, program

Description states, “Elastomers will be monitored for hardening, shrinkage and a loss of sealing”

and does not address polymeric materials. In addition, Enhancement No. 2 lists newly added 

components. The staff noted that this enhancement was not updated to include roofing 

scuppers. By letter dated April 5, 2012, the staff issued followup RAI 3.5.2.3.2-1.1 requesting 

the applicant to revise LRA Section B.2.1.35 to include polymeric materials being managed for 

cracking and add roofing scuppers to Enhancement No. 2.

In its response, dated April 13, 2012, the applicant stated that LRA Section A.2.1.35 and 

Enhancement No. 2 for the Structures Monitoring program were revised to include roofing 

scuppers. In addition LRA Section B.2.1.35 was revised to state that PVC roof scuppers are 

monitored for cracking.

The staff finds the applicant’s response acceptable because the Structures Monitoring program 

and Enhancement No. 2 were revised to include the component and its aging effect. The staff’s 

concern described in RAI 3.5.2.3.2-1.1 is resolved. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.5.2.3.3 Auxiliary Boiler and Lube Oil Storage Enclosure – Summary of Aging Management 

Evaluation

The staff reviewed LRA Table 3.5.2-3, which summarizes the results of AMR evaluations for the 

admin building shop and warehouse component groups.

The staff’s evaluation for PVC roofing scuppers exposed to outdoor air and cite generic note J, 

is documented in Section 3.5.2.3.2.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.5.2.3.4 Circulating Water Pump House – Summary of Aging Management Evaluation

The staff reviewed LRA Table 3.5.2-4, which summarizes the results of AMR evaluations for 

circulating water pump house component groups. The staff’s review did not identify any items 
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with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for this system are consistent with the GALL Report.

3.5.2.3.5 Component Supports Commodities Group – Summary of Aging Management 

Evaluation

The staff reviewed LRA Table 3.5.2-5, which summarizes the results of AMR evaluations for 

component supports commodities group. The staff’s review did not identify any items with notes 

F through J, indicating that the combinations of component type, material, environment, and 

AERM for this system are consistent with the GALL Report.

3.5.2.3.6 Control Enclosure – Summary of Aging Management Evaluation

The staff reviewed LRA Table 3.5.2-6, which summarizes the results of AMR evaluations for 

control enclosure component groups. The staff’s review did not identify any items with notes 

F through J, indicating that the combinations of component type, material, environment, and 

AERM for this system are consistent with the GALL Report.

3.5.2.3.7 Cooling Towers – Summary of Aging Management Evaluation 

The staff reviewed LRA Table 3.5.2-7, which summarizes the results of AMR evaluations for the 

cooling towers component groups.

In LRA Table 3.5.2-7, the applicant stated that the above-grade exterior and interior (accessible) 

reinforced concrete, including basin curb wall, inlet, and outlet walls, and concrete foundation 

(accessible) (basin slab) exposed to water-flowing will be managed for cracking, loss of bond, 

loss of material (spalling, scaling), and increase in porosity and permeability, by the Structures 

Monitoring program. The AMR items cite generic note H.

The staff noted that this material and environment combination is identified in the GALL Report, 

which addresses reinforced concrete water-control structures exposed to water-flowing and 

recommends GALL Report AMP XI.S7, “Regulatory Guide 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants,” or the FERC US Army Corps of Engineers 

dam inspections and maintenance programs to manage aging effects. The applicant addressed 

the GALL Report identified aging effects for this component, material and environment 

combination in AMR items in LRA Table 3.5.2-7. 

The staff’s evaluation of the Structures Monitoring program is documented in SER 

Section 3.0.3.2.17. The staff noted that under the Structures Monitoring program, structures 

and structural components are inspected by qualified personnel in accordance with station 

procedures, which will be enhanced for consistency with ACI 349.3R-02. The staff also noted 

that the concrete structures are inspected for indications of deterioration and distress including 

evidence of leaching, loss of material, cracking, and loss of bond as identified in ACI 201.1R, 

“Guide for Making a Condition Survey of Existing Buildings.” The staff further noted that the 

Structures Monitoring program addresses environments of outdoor air, uncontrolled indoor air, 

treated water, raw water, water-flowing, and ground water and soil. The staff finds the 

applicant’s proposal to manage aging using the Structures Monitoring program acceptable 

because the reinforced concrete structures associated with the cooling towers will be managed 

for cracking, loss of bond, and loss of material (spalling, scaling) through inspections by 
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qualified personnel, at inspection intervals not to exceed 5 years, in accordance with station 

procedures that have been enhanced for consistency with ACI 349.3R-02.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.5.2.3.8 Diesel Oil Storage Tank Structures – Summary of Aging Management Evaluation

The staff reviewed LRA Table 3.5.2-8, which summarizes the results of AMR evaluations for 

diesel oil storage tank structures component groups. The staff’s review did not identify any 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for this system are consistent with the GALL Report.

3.5.2.3.9 Emergency Diesel Generator Enclosure – Summary of Aging Management Evaluation

The staff reviewed LRA Table 3.5.2-9, which summarizes the results of AMR evaluations for 

EDG enclosure component groups. The staff’s review did not identify any items with notes F 

through J, indicating that the combinations of component type, material, environment, and 

AERM for this system are consistent with the GALL Report.

3.5.2.3.10 Piping and Component Insulation Commodity Group – Summary of Aging 

Management Evaluation

The staff reviewed LRA Table 3.5.2-10, which summarizes the results of AMR evaluations for 

the piping and component insulation commodity group.

In LRA Table 3.5.2-10, the applicant stated that for calcium silicate, fiberglass, foamed plastic, 

insulation cement and finishing cement, caulking and lagging adhesive, and insulation jacketing 

exposed to outdoor air, there is no aging effect and no AMP is proposed. The AMR items cite 

generic note J. 

In LRA Table 3.5.2-10, the applicant stated that for calcium silicate, cellular glass, ceramic fiber, 

fiberglass, fiberglass (molded), foamed plastic, Min-K, mineral fiber and NUKON insulation, and 

insulation jacketing, cement and finishing cement exposed to uncontrolled indoor air, there is no 

aging effect and no AMP is proposed. The staff noted that the insulation jacketing materials are 

constructed of caulking adhesive, lagging adhesive, fiberglass cloth (including silicone coated 

fiberglass cloth), or plastic mastic. The AMR items cite generic notes F and J.

The staff reviewed the associated items in the LRA and could not confirm that no credible aging 

effects are applicable for this component, material, and environment combination. The staff 

lacked sufficient information to conclude that no aging management is required for these 

components for the following reasons. The staff could not determine the product form, 

installation, function, or the specific material of construction of Min-K insulation. By letter dated 

January 18, 2012, the staff issued RAI 3.5.2.3.10-2 requesting the applicant to provide sufficient 

detail on the function and material of fabrication for Min-K insulation for the staff to 

independently evaluate and conclude that there is no AERM for this component. 
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In its response, dated February 16, 2012, the applicant stated that:

Min-K is an insulation material consisting of fused silica particles combined with 

titanium dioxide and glass fibers, manufactured by Johns-Manville Co. Min-K 

flexible insulation material is used in applications where limited clearances or 

obstructions exist caused by its low thermal conductivity. Min-K insulation is 

applied in blanket form and covered with aluminum jacketing secured with 

aluminum, galvanized steel, or stainless steel straps. Min-K insulation is not 

subject to aging effects requiring management for the uncontrolled indoor air 

environment used as shown in Table 3.5.2-10 of the LGS LRA.

The staff finds the applicant’s response acceptable because in its response to RAI 3.0.2-1, 

provided by letter dated February 15, 2012, the applicant stated that for all the AMR items in the 

LRA, the environment of uncontrolled indoor air contains no humidity, condensation, moisture or 

contaminants, and the Min-K insulation, as well as the other insulation and jacket components, 

are composed of materials that in the absence of moisture and outdoor UV will not degrade. 

The staff’s concern described in RAI 3.5.2.3.2.10-2 is resolved.

The staff noted that LRA Table 3.0-2 states that the uncontrolled indoor air environment can 

result in the surfaces of components being wet. Given the definition of the uncontrolled indoor 

air environment, it was not clear to the staff how water would not accumulate in the insulation 

material during periods when insulated systems are at ambient shutdown conditions. The staff 

also noted that UFSAR Section 5.2.3.2.4 describes the compatibility of thermal insulation to the 

underlying external surfaces of the piping it encloses; however, it is not clear to the staff that this 

UFSAR section is applicable to insulation materials not associated with the RCPB. The staff 

further noted that LRA Table 3.3.2-8, Emergency Diesel Generator System, and LRA 

Table 3.4.2-2, Condensate System, have stainless steel components exposed to the outdoor air 

environment that could be insulated. Therefore, the staff lacked sufficient information to 

conclude that there are no AERM associated with the components. By letter dated 

January 18, 2012, the staff issued RAI 3.5.2.3.10-3 requesting the applicant to state the basis 

for why the insulation materials exposed to uncontrolled indoor air listed in LRA Table 3.5.2-10 

will not accumulate moisture resulting in degradation of its thermal insulation function, state 

whether UFSAR Section 5.2.3.2.4 applies to all insulation within the plant, or state the basis for 

why deleterious compounds (e.g., chlorides, halogens) will not leach out of the insulation and 

cause SCC or loss of material for the components it encloses. The applicant was also asked to 

state whether the stainless steel components exposed to outdoor air in LRA Tables 3.3.2-8 and 

3.4.2-2 are insulated, and if they are insulated state the basis for why deleterious compounds 

(e.g., chlorides, halogens) will not leach out of the insulation and cause SCC of the stainless 

steel materials.

In its response to RAI 3.0.2-1, which is discussed in SER Section 3.0.1.2, the applicant stated 

that for all the AMR items in the LRA, the environment of uncontrolled indoor air contains no 

humidity, condensation, moisture, or contaminants. The applicant’s response to 

RAI 3.5.2.3.10-3, provided by letter dated February 16, 2012, states that UFSAR 

Section 5.2.3.2.4 does not apply to all insulation in the plant; however, its insulation specification 

requires that all insulating materials for stainless steel must meet RG 1.36, “Nonmetallic 

Thermal Insulation for Austenitic Stainless Steel,” which includes controls to preclude 

deleterious compounds (e.g., chlorides, halogens). The response to RAI 3.5.2.3.1-3 also stated 

that the outdoor EDG stainless steel exhaust piping is not insulated, and the CST isolation 
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stainless steel valves are heat traced and insulated, this insulation is constructed of glass fiber 

material within a sealed aluminum jacket, and the insulation meets RG 1.36 recommendations.

The staff finds the applicant’s response acceptable because insulation and jacket components 

are composed of materials that in the absence of moisture and outdoor UV will not degrade and 

plant-specific insulation specifications ensure that deleterious materials are not contained within 

the insulation. The staff’s concern described in RAI 3.5.2.3.2-10-3 is resolved.

The staff reviewed the associated items in the LRA and could not confirm that no credible aging 

effects are applicable for this component, material, and environment combination. The staff 

lacked sufficient information to conclude that no aging management is required for exposure to 

the outdoor air environment caused by the potential impact of UV exposure and water intrusion. 

By letter dated January 18, 2012, the staff issued RAI 3.5.2.3.10-1 requesting the applicant to

state for the fiberglass and calcium silicate insulation components: state how the configuration 

of the jacketing ensures that it is properly installed so as to prevent water intrusion into the 

insulation; state the specific material types for any foamed plastic insulation material other than 

Rubatex; state the basis for why these materials are not subject to aging caused by direct 

exposure to sunlight UV; and state the specific materials of construction for the items associated 

with insulation jacketing, including insulation cement and the jacket components where the 

material type is not clear (i.e., integral vapor barrier, straps, bands, clamps, fasteners, breather 

springs, caulking and lagging adhesive); and state the basis for why these materials are not 

subject to aging caused by direct exposure to sunlight UV.

In its response, dated February 16, 2012, the applicant stated that the outdoor fiberglass and 

calcium silicate insulation jacketing is installed with interlocking joints along the length of the 

jacket and overlapping circumferential joints that are sealed and installed to be watertight, and 

the foamed plastic insulation material is sprayed-on polyurethane foam insulation on the 

external surface of the backup fire water storage tank installed with a coating that reduces the

effect of direct UV exposure. Also, the applicant revised Table 3.5.2-10 to manage insulation 

degradation for foamed plastic (including Rubatex) by the Aboveground Metallic Tanks program. 

The outdoor jacketing material is aluminum, using either aluminum or galvanized steel straps, 

tie wire, bands, fasteners, breather springs, or clips. The aluminum jacketing is supplied with a 

factory-applied moisture proof barrier of epoxy coating or laminated polyethylene on the inside. 

The adhesive and insulating cement conforms to ASTM C449 and the caulking is a silicone 

rubber based compound. Further, most of the nonmetallic components are covered by the 

aluminum jacketing and thus not susceptible to degradation caused by UV exposure; however, 

some of the silicone rubber caulking may be exposed to UV. Therefore, the applicant revised 

Table 3.5.2-10 to manage the aging of this commodity group with the Structures Monitoring 

program.

The staff finds the applicant’s response acceptable because (a) the outdoor fiberglass and 

calcium silicate insulation is covered with jacketing installed in such a manner as to preclude 

water intrusion, (b) the foamed plastic insulation and Rubatex components will be managed for 

degradation by the Aboveground Metallic Tanks program, which conducts visual inspections on 

a 2-year interval, (c) the insulation jacketing including insulation cement and the jacket 

components will be managed for degradation by the Structures Monitoring program, which 

conducts visual inspections on a 5-year interval, and (d) both the Aboveground Metallic Tanks 

and Structures Monitoring programs use visual inspections that are capable of detecting 

degradation of the components. The staff’s concern described in RAI 3.5.2.3.2-10-1 is resolved.
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On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.5.2.3.11 Primary Containment – Summary of Aging Management Evaluation 

The staff reviewed LRA Table 3.5.2-11, which summarizes the results of AMR evaluations for 

the primary containment component groups.

In LRA Table 3.5.2-11 the applicant stated that for concrete doors (reactor shield doors and 

plugs), concrete interior (diaphragm slab and pedestal), and steel components exposed to an 

encased in steel environment, there is no aging effect and no AMP proposed. The AMR items 

cite generic note G and plant-specific note 2. Plant-specific note 2 states that concrete or 

concrete (high density) or grout (high density) or Boron concrete encased in steel is protected 

from environments that promote age-related degradation. Concrete encased in steel has no 

aging effects.

The staff reviewed the associated items in the LRA to confirm that no credible aging effects are 

applicable for this component, material, and environment combination. The staff finds the 

applicant’s proposal acceptable based on its review of ACI 201.1R and ACI 349.3R-02 which 

does not identify any durability issues associated with concrete in a steel environment. The 

staff notes that by being encased in steel, the components are protected from external 

environments and exhibit no aging effects requiring management for the period of extended 

operation.

In LRA Table 3.5.2-11 the applicant stated that for lead metal components (permanent drywell 

shielding) exposed to uncontrolled indoor air, there is no aging effect and no AMP is proposed. 

The AMR item cites generic note J and plant-specific note 4. Plant-specific note 4 states that 

lead shielding and fiberglass cloth have no applicable aging effects requiring management.

The staff reviewed the associated items in the LRA to confirm that no credible aging effects are 

applicable for this component, material, and environment combination. The staff finds the 

applicant’s proposal acceptable because there is no indication in the industry that lead exposed 

to an uncontrolled indoor air environment has any aging effects requiring management. The 

lack of historic negative operating experience indicates that lead is not likely to experience any 

degradation from uncontrolled indoor air. Therefore, based on industry experience and the 

assumption of proper design and application of the material, the staff finds that lead permanent 

drywell shielding plugs exposed to an uncontrolled indoor air environment exhibit no aging 

effects requiring management for the period of extended operation.

In LRA Table 3.5.2-11, the applicant stated that for fiberglass metal components (permanent 

drywell shielding) exposed to uncontrolled indoor air there is no aging effect and no AMP is 

proposed. The AMR item cites generic note J. This item cites plant-specific note 4 that states 

that lead shielding and fiberglass cloth have no applicable aging effects requiring management.

The staff reviewed the associated items in the LRA and could not confirm that no credible aging 

effects are applicable for this component, material, and environment combination. The staff 

lacked sufficient information to conclude that no aging management is required for these 
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components because, given that the fiberglass material is located in the drywell, it is susceptible 

to high radiation levels. The staff noted that radiation can break down the molecule chains in 

the structure. By letter dated January 18, 2012, the staff issued RAI 3.5.2.3.11-1 requesting the 

applicant to state the composition of the matrix (e.g., polyester or vinyl ester) in which the glass 

fibers are set and state the basis for why there are no aging effects for this component, or state 

an AMP to manage the aging of the insulation components. In its response, dated 

February 16, 2012, the applicant stated that the permanent drywell shielding is a type of lead 

blanket encased in Alpha Maritex material, which is constructed from fiberglass fabric 

impregnated with silicone rubber. This material and blanket configuration was designed for the 

radiation environment in the drywell through the period of extended operation; however, the 

fiberglass fabric for the shielding blanket will be managed for rips and tears by the Structures 

Monitoring program. The applicant revised LRA Table 3.5.2-11 to add rips and tears as an 

AERM for this component and credited the Structures Monitoring program to manage the aging

effect.

The staff finds the applicant’s response acceptable because the applicant will age manage this 

material for rips and tears with the Structures Monitoring program, and the program’s visual 

inspections are capable of detecting rips and tears. The staff’s concern described in 

RAI 3.5.2.3.11-1 is resolved. However, LRA Section B.2.1.35, Structures Monitoring, program

Description states, “Elastomers will be monitored for hardening, shrinkage and a loss of sealing”

and does not address polymeric materials. In addition, Enhancement No. 2 lists newly added 

components. The staff noted that this enhancement was not updated to include fiberglass metal 

components (permanent drywell shielding). By letter dated April 5, 2012 the staff issued 

RAI 3.5.2.3.2-1.1 requesting the applicant to revise LRA Section B.2.1.35 to include polymeric 

materials being managed for rips and tears, and add fiberglass metal components (permanent 

drywell shielding) to Enhancement No. 2

In its response, dated April 13, 2012, the applicant stated that LRA Section A.2.1.35 and 

Enhancement No. 2 for the Structures Monitoring program were revised to include fiberglass 

metal components (permanent drywell shielding). In addition LRA Section B.2.1.35 was revised 

to state that fiberglass metal components (permanent drywell shielding) are monitored for rips 

and tears.

The staff finds the applicant’s response acceptable because the Structures Monitoring program 

and Enhancement No. 2 were revised to include the component and its aging effect. The staff’s 

concern described in RAI 3.5.2.3.2-1.1 is resolved.

In LRA Table 3.5.2-11, the applicant stated that Service Level 1 coatings exposed to treated 

water will be managed for loss of coating integrity by the Protective Coating Monitoring and 

Maintenance AMP. The AMR item 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 and 

ASTM D 5163, which provides guidelines that are acceptable for establishing an inservice 

coatings monitoring program for Service Level 1 coating systems, the staff finds that the 

applicant has identified all credible aging effects for this component, material, and environment 

combination.
3-389

The staff’s evaluation of the Protective Coating Monitoring and Maintenance program is 

documented in SER Section 3.0.3.2.19. The staff finds the applicant’s proposal to manage 

aging using the Protective Coating Monitoring and Maintenance Program acceptable because 

the applicant will be able to identify defective or deficient coatings and perform repairs in 

accordance with ASTM D 5163. In addition, degraded coating will be documented and 

summarized for further evaluation and trending, which is consistent with the GALL Report.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.5.2.3.12 Radwaste Enclosure – Summary of Aging Management Evaluation 

The staff reviewed LRA Table 3.5.2-12, which summarizes the results of AMR evaluations for 

the radwaste enclosure component groups.

In LRA Table 3.5.2-12, the applicant stated that for lead penetration seals exposed to 

uncontrolled indoor air there is no aging effect and no AMP is proposed.

The staff reviewed the associated items in the LRA to confirm that no aging effects are 

applicable for this component, material, and environment combination. The staff finds the 

applicant’s proposal acceptable because there is no indication in the industry that lead exposed 

to an uncontrolled indoor air environment has any aging effects requiring management. The 

lack of historic negative operating experience indicates that lead is not likely to experience any 

degradation from uncontrolled air indoor. Therefore, based on industry experience and the 

assumption of proper design and application of the material, the staff finds that lead penetration 

seals exposed to an uncontrolled indoor air environment exhibit no aging effects requiring 

management for the period of extended operation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.5.2.3.13 Reactor Enclosure – Summary of Aging Management Evaluation

The staff reviewed LRA Table 3.5.2-13, which summarizes the results of AMR evaluations for 

the reactor enclosure component groups.

In LRA Table 3.5.2-13, the applicant stated there is a TLAA for the loss of prestress aging effect 

of prestressed concrete exposed to an uncontrolled indoor air environment, which cites generic 

note H, and a plant-specific note, which states that “[t]he fuel pool girders are two interior 

concrete prestressed girders that are subject to loss of prestress, which is managed by a TLAA 

evaluated in Section 4.6.10.”

The staff confirmed that there is a TLAA, as documented in LRA Section 4.6.10, for this 

component, material, and environment. The staff’s evaluation of the TLAA for the prestressed 
3-390

fuel pool girders is documented in SER Section 4.6.10. The staff finds the applicant’s proposal 

to manage aging using the TLAA acceptable because the applicant has demonstrated that the 

original analysis for the girder prestress remains valid for the period of extended operation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.5.2.3.14 Service Water Pipe Tunnel – Summary of Aging Management Evaluation

The staff reviewed LRA Table 3.5.2-14, which summarizes the results of AMR evaluations for 

SW pipe tunnel component groups. The staff’s review did not identify any items with notes F 

through J, indicating that the combinations of component type, material, environment, and 

AERM for this system are consistent with the GALL Report.

3.5.2.3.15 Spray Pond Pump House – Summary of Aging Management Evaluation 

The staff reviewed LRA Table 3.5.2-15, which summarizes the results of AMR evaluations for 

the spray pond pump house component groups.

In LRA Table 3.5.2-15, the applicant stated that reinforced concrete pipe encasement, intake 

area slab, overflow structure, below grade (exterior, inaccessible) columns (spray network 

supports), foundation (inaccessible), and interior exposed to water flowing will be managed for 

cracking, loss of bond, and loss of material (spalling, scaling) by RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants program. The AMR item cites 

generic note H.

The staff noted that this material and environment combination is identified in the GALL Report,

which addresses reinforced concrete components exposed to water flowing and recommends 

GALL Report AMP XI.S6, “Structures Monitoring” program to manage aging effects. The 

applicant addressed the GALL Report identified aging effects for these component, material, 

and environment combinations in AMR items in LRA Table 3.5.2-15.

The staff’s evaluation of the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants program is documented in SER 3.0.3.2.18. The staff noted that the 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

program addresses age-related deterioration, degradation caused by environmental conditions, 

and the effects of natural phenomena that may affect the safety function of water-control 

structures. The staff also noted that the program will be used to manage loss of material, loss 

of preload, cracking, loss of bond, loss of material (spalling, scaling), increase in porosity and 

permeability, loss of strength, and loss of form in uncontrolled indoor air, outdoor air, raw water, 

water-standing, water flowing, groundwater, and soil environments. The staff further noted that 

the program is based on guidance provided in NRC RG 1.127 and ACI 349.3R-02 and that 

water-control structures will be monitored at a frequency not to exceed 5 years. The staff finds 

the applicant’s proposal to manage aging using the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants program acceptable because the program will 

monitor the components in a water flowing environment for cracking, loss of bond, and loss of 

material (spalling, scaling) at a frequency not to exceed 5 years using guidance based on 
3-391

ACI 349.3R-02, acceptability of inaccessible areas will be evaluated when conditions exist in 

accessible areas that could indicate the presence of, or result in, degradation to such 

inaccessible areas, exposed portions of the below-grade concrete will be examined when 

excavated for any reason and water chemistry will be monitored at least every 5 years for pH, 

chlorides, and sulfates and verify that it remains nonaggressive or evaluate results exceeding 

criteria to assess impact, if any, on submerged concrete.

In LRA Table 3.5.2-15, the applicant stated that for soil, rip-rap, sand, and gravel earthen 

water-control structures (emergency spillway), and embankments (dikes, include rock covered 

with shotcrete) exposed to outdoor air will be managed for loss of material and loss of form by 

the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

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 sample literature as for example 

that of the Department of Transportation “Bridge Scour and Stream Instability 

Countermeasures: Experience, Selection, and Design Guidance,” 3rd Edition, publication dated

September 2009 that identifies loss of material (loss of mass, mass wasting, erosion) and 

resulting loss of form as the aging mechanisms, 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 RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants program is documented in SER 3.0.3.2.18. The staff noted that the 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

program addresses age-related deterioration, degradation caused by environmental conditions, 

and the effects of natural phenomena that may affect the safety function of water-control 

structures. The staff also noted that the program will be used to manage loss of material, loss 

of preload, cracking, loss of bond, loss of material (spalling, scaling), increase in porosity and 

permeability, loss of strength, and loss of form in uncontrolled indoor air, outdoor air, raw water, 

water-standing, water-flowing, groundwater, and soil environments for earthen water-control 

structures (e.g., embankments and dikes). The staff further noted that the program is based on 

guidance provided in NRC RG 1.127 and ACI 349.3R-02 and water-control structures will be 

monitored at a frequency not to exceed 5 years. The staff finds the applicant’s proposal to 

manage aging using the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants program acceptable because the program will monitor the earthen 

water-control structures and embankments in an outdoor air environment for loss of material 

and loss of form at a frequency not to exceed 5 years using guidance based on ACI 349.3R-02 

(for example, see also “Guidelines for Inspection and Maintenance of Dams,” CT Department of 

Environmental Protection, September 2001).

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).
3-392

3.5.2.3.16 Turbine Enclosure – Summary of Aging Management Evaluation

The staff reviewed LRA Table 3.5.2-11, which summarizes the results of AMR evaluations for 

the turbine enclosure component groups.

The staff’s evaluation for PVC roofing scuppers exposed to outdoor air and cite generic note J, 

is documented in Section 3.5.2.3.2.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.5.2.3.17 Yard Facilities – Summary of Aging Management Evaluation 

The staff reviewed LRA Table 3.5.2-11, which summarizes the results of AMR evaluations for 

the yard facilities component groups.

In LRA Table 3.5.2-17 the applicant stated that soil tank dikes exposed to outdoor air will be 

managed for loss of material and loss of form by the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants program. The AMR item cites 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 sample literature as for example 

that of the Department of Transportation “Bridge Scour and Stream Instability 

Countermeasures: Experience, Selection, and Design Guidance,” 3rd Edition, publication dated 

September 2009 that identifies loss of material (loss of mass, mass wasting, erosion) and 

resulting loss of form as the aging mechanisms, 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 RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants program is documented in SER 3.0.3.2.18. The staff noted that the 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

program addresses age-related deterioration, degradation caused by environmental conditions, 

and the effects of natural phenomena that may affect the safety function of water-control 

structures. The staff also noted that the program will be used to manage loss of material, loss 

of preload, cracking, loss of bond, loss of material (spalling, scaling), increase in porosity and 

permeability, loss of strength, and loss of form in uncontrolled indoor air, outdoor air, raw water, 

water-standing, water flowing, groundwater, and soil environments for earthen water-control 

structures (e.g., embankments and dikes). The staff further noted that the AMP is based on 

guidance provided in NRC RG 1.127 and ACI 349.3R-02 and water-control structures will be 

monitored at a frequency not to exceed 5 years. The staff finds the applicant’s proposal to 

manage aging using the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants program acceptable because the AMP will monitor the soil tank dikes in 

an outdoor air environment for loss of material and loss of form at a frequency not to exceed 

5 years using guidance based on ACI 349.3R-02 (for example, see also “Guidelines for 

Inspection and Maintenance of Dams,” CT Department of Environmental Protection, September 

2001).
3-393

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

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 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 and Instrumentation and Controls System

This SER section documents the staff’s review of the applicant’s AMR results for the electrical 

and instrumentation and control (I&C) system components and component groups of:

 • cable connections (metallic parts)

 • electrical penetrations

 • fuse holders

 • high-voltage insulators

 • insulation materials for electrical cables and connections

 • metal enclosed bus

 • switchyard bus and connections

 • transmission conductors and connectors

3.6.1 Summary of Technical Information in the Application 

LRA Section 3.6 provides AMR results for the electrical and I&C system components and 

component groups. LRA Table 3.6.1, “Summary of Aging Management Programs for the 

Electrical and I&C Components Evaluated in Chapter VI of NUREG-1801,” is a summary 

comparison of the applicant’s AMRs with those evaluated in the GALL Report for the electrical 

and I&C 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.
3-394

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 and I&C 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 an onsite audit of AMRs to ensure the applicant’s claim that certain AMRs 

were consistent with the GALL Report. 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 was applicable and that the applicant identified the appropriate GALL Report AMRs. The 

staff’s evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff’s 

audit evaluation are documented in SER Section 3.6.2.1.

In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

were consistent with the SRP-LR Section 3.6.2.2 acceptance criteria. The staff’s audit 

evaluations are documented in SER Section 3.6.2.2.

The staff also conducted a technical review of the remaining AMRs not consistent with or not 

addressed in the GALL Report. The technical review evaluated whether all plausible aging 

effects have been identified and whether the aging effects listed were appropriate for the 

material-environment combinations specified. The staff’s evaluations are documented in SER 

Section 3.6.2.3.

For SSCs the applicant claimed were not applicable or required no aging management, the staff 

reviewed the AMR items and the plant’s operating experience to verify the applicant’s claims.

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.
3-395

Table 3.6-1 Staff Evaluation for Electrical and Instrumentation and Controls in the 

GALL Report

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in the 

GALL 

Report

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 caused 

by various 

mechanisms in 

accordance with 

10 CFR 50.49

EQ is a 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 

caused by

mechanical wear 

caused by wind 

blowing on 

transmission 

conductors

A plant-specific aging 

management program 

is to be evaluated

Yes NA Not applicable to 

LGS (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 

caused by

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 NA Not applicable to 

LGS (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 caused 

by corrosion

A plant-specific aging 

management program 

is to be evaluated for 

ACSR

Yes NA Not applicable to 

LGS (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 

caused by

oxidation or loss 

of preload

A plant-specific aging 

management program 

is to be evaluated

Yes NA Not applicable to 

LGS (see SER 

Section 3.6.2.2.3)
3-396

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in the 

GALL 

Report

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 

caused by

wind-induced 

abrasion; 

Increased 

resistance of 

connection 

caused by

oxidation or loss 

of preload

A plant-specific aging 

management program 

is to be evaluated

Yes NA Not applicable to 

LGS (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 

caused by

wind-induced 

abrasion

A plant-specific aging 

management program 

is to be evaluated for 

ACAR and ACSR

Yes NA Not applicable to 

LGS (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 

caused by

thermal/

thermoxidative 

degradation of 

organics, 

radiolysis, and 

photolysis (UV 

sensitive 

materials only) 

of organics; 

radiation-induce

d 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 

caused by

thermal/thermoxi

dative 

degradation of 

organics, 

radiolysis, and 

photolysis (UV 

sensitive 

materials only) 

of organics; 

radiation-induce

d 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
3-397

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in the 

GALL 

Report

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 

caused by

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 

caused by

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 

caused by 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 

caused by

thermal/thermoxi

dative 

degradation of 

organics/thermo

plastics, 

radiation-induce

d oxidation, 

moisture/debris 

intrusion, and 

ohmic heating

Chapter XI.E4, “Metal 

Enclosed Bus”

No Metal Enclosed 

Bus

Consistent with 

the GALL Report
3-398

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in the 

GALL 

Report

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 

caused by

general, pitting, 

and crevice 

corrosion

Chapter XI.E4, “Metal 

Enclosed Bus,” or 

Chapter XI.S6, 

“Structures Monitoring”

No Structures 

Monitoring

Consistent with 

the GALL Report

Metal enclosed bus: 

external surface of 

enclosure 

assemblies 

composed of 

galvanized steel; 

aluminum exposed to 

air-outdoor (3.6.1-15)

Loss of material 

caused by pitting 

and crevice 

corrosion

Chapter XI.E4, “Metal 

Enclosed Bus,” or 

Chapter XI.S6, 

“Structures Monitoring”

No NA Not applicable to 

LGS (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, 

uncontrolled 

(3.6.1-16)

Increased 

resistance of 

connection 

caused by

chemical 

contamination, 

corrosion, and 

oxidation (in an 

air, indoor 

controlled 

environment, 

increased 

resistance of 

connection 

caused by

chemical 

contamination, 

corrosion and 

oxidation do not 

apply); fatigue 

caused by ohmic 

heating, thermal 

cycling, 

electrical 

transients

Chapter XI.E5, “Fuse 

Holders”

No Fuse Holders Consistent with 

the GALL Report

(see SER 

Section 3.6.2.1)
3-399

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in the 

GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

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 

caused by

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 Fuse Holders Consistent with 

the GALL Report

(see SER 

Section 3.6.2.1)

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 

caused by

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 

caused by

corrosion of 

connector 

contact surfaces 

caused by 

intrusion of 

borated water

Chapter XI.M10, “Boric 

Acid Corrosion”

No NA 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 caused 

by corrosion

None - for Aluminum 

Conductor Aluminum 

Alloy Reinforced 

(ACAR)

None NA Not applicable to 

LGS (see SER 

Section 3.6.2.1.1)
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Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in the 

GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

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

NA Consistent with 

the GALL Report

The staff’s review of the electrical and I&C system component groups followed any one of 

several approaches. One approach, documented in SER Section 3.6.2.1, reviewed AMR 

results for components that the applicant indicated are consistent with the GALL Report and 

require no further evaluation. Another approach, documented in SER Section 3.6.2.2, reviewed 

AMR results for components that the applicant indicated are consistent with the GALL Report 

and for which further evaluation is recommended. A third approach, documented in SER 

Section 3.6.2.3, reviewed AMR results for components that the applicant indicated are not 

consistent with, or not addressed in, the GALL Report. The staff’s review of AMPs credited to 

manage or monitor aging effects of the electrical and I&C system components is documented in 

SER Section 3.0.3.

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 the electrical and I&C system components:

 • insulation material for electrical cables and connections not subject to 10 CFR 50.49 EQ 

requirements

 • insulation material for electrical cables and connections not subject to 10 CFR 50.49 EQ

requirements used in instrumentation circuits

 • inaccessible power cables not subject to 10 CFR 50.49 EQ requirements

 • electrical cable connections not subject to 10 CFR 50.49 EQ requirements

 • metal enclosed bus

 • structure monitoring

 • fuse holders
3-401

LRA Table 3.6.2-1 summarizes AMRs for the electrical and I&C system components and 

indicate AMRs claimed to be consistent with the GALL Report.

The staff audited and reviewed the information in the LRA. 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 was applicable and that the applicant identified the appropriate GALL 

Report AMRs. The staff’s evaluation follows.

In LRA Table 3.6.2-1, corresponding to Table 1 items 3.6.1.16 and 17, the applicant indicated, 

via Note A, that the combination of component type, material, environment, and AERM of fuse 

holders (not part of active equipment): metallic clamps is consistent with the GALL Report. The 

applicant provided information about how it will manage the aging effects by proposing the Fuse 

Holders program (B.2.1.42). The LRA claims that this program is consistent with GALL Report 

AMP XI.E5. During the onsite audit, the staff noted that certain fuse holders (metallic clamps) 

were in scope of license renewal (i.e., fuse holders in the switchyard control house) but were not 

included in the scope of Fuse Holders program. The GALL Report items VI.A.LP-23 and 

VI.A.LP-31, “Fuse Holders (Not Part of active equipment): Metallic Clamps,” identifies the aging 

effect or aging mechanism as increased resistance of connection caused by chemical 

contamination, corrosion, oxidation; fatigue caused by ohmic heating, thermal cycling, electrical 

transients, increased resistance of connection caused by fatigue caused by frequent 

manipulation or vibration. The associated GALL Report AMP XI.E5, “Fuse Holders,” states that 

fuse holders within the scope of license renewal should be tested to provide an indication of the 

condition of the metallic clamps of fuse holders. 

The applicant did not provide technical justifications of why these fuse holders are excluded 

from the Fuse Holders program. By letter dated February 14, 2012 the staff issued 

RAI 3.6.2.3-1, requesting the applicant to provide a list of fuse holders within the scope of 

license renewal and subject to an AMR (i.e., fuse holders located outside of active equipment). 

For fuse holders within the scope of license renewal, the staff requested the applicant provide 

an evaluation that addressed each aging effect and mechanism identified in the GALL Report

items VI.A.LP-23 and VI.A.LP-31 and identify fuse holders included in the Fuse Holder program 

and AMP basis document. In its response to RAI 3.6.2.3-1, provided by letter dated 

March 13, 2012, the applicant stated that the LGS metallic clamps of fuse holders, that are not 

part of an active assembly, were scoped and screened for AMR in accordance with the scoping 

and screening methodologies, documented in LRA Sections 2.1.1, 2.1.5, and 2.1.6. The 

applicant identified five electrical panels that contain fuse holders metallic clamps that are 

subject to an AMR:

 • two drywell leak detection fuse panels – 12 fuse holders

 • toxic chemical detection fuse panel – 6 fuse holders

 • 500 kV substation battery fuse panel – 2 fuse holders

 • 220 kV substation battery fuse panel – 2 fuse holders

Other LGS fuse holders that are not part of a larger assembly are for circuits that do not perform 

a license renewal intended function. The applicant also stated that the potential aging effects as 

discussed in the GALL Report items VI.A.LP-23 and VI.A.LP-31 are not applicable for the 

500 kV substation battery fuse panel, the 220 kV substation battery fuse panel, and the toxic 
3-402

chemical detection fuse panels. The applicant’s response to RAI 3.6.2.3-1 stated the following 

in relation to the aging effects for these fuse holders:

Chemical Contamination, Corrosion and Oxidation

These fuse holders are located in indoor, controlled environments that do not 

subject them to environmental aging mechanisms. The toxic chemical detection 

fuse panel is located in the plant’s control enclosure in the upper fan room. The 

substation battery fuse panels are located in the substation control houses in the 

500 kV and 220 kV substation yards. These panels and the enclosed fuse 

holders are located in indoor, controlled environments, are not subject to weather 

conditions and are, therefore, not subject to moisture from precipitation. Their 

indoor, controlled environment locations assure the fuse holders do not 

experience high relative humidity during normal conditions. A second barrier 

protecting the fuse holders from exposure to moisture is their location inside 

closed electrical boxes. The fuse holders are also protected from chemical 

contamination by their location inside closed electrical boxes. There are no 

sources of chemicals in the vicinity of the fuse boxes. Oxidation and corrosion 

are not a concern since the fuse holders are not located in or near humid areas, 

nor are they exposed to industrial or oceanic environments.

A walkdown of these electrical panels containing the in-scope fuse holders 

confirmed that the operating conditions for these fuse holders are clean and dry, 

with no evidence of moisture intrusion, chemical contamination, oxidation or 

corrosion.

Ohmic Heating, Thermal Cycling and Electrical Transients

Fuses for circuits that carry significant current in power applications could 

potentially be exposed to ohmic heating and thermal cycling. The fuse holders 

being evaluated are not in circuits that carry significant current in power 

applications. The fuses in the toxic chemical detection fuse panel provide 

120Vac power to enclosure fans. These circuits are loaded with a small constant 

current. The substation battery fuse panels are for substation equipment direct 

current control power. The normal supply of power to loads is from the battery 

charger. The battery is normally on a float charge, thus the fuses are lightly 

loaded with a small constant current. Therefore, electrical and thermal cycling is 

not considered an applicable aging mechanism for these fuse holders. 

Mechanical stress caused by forces associated with electrical faults and 

transients are mitigated by the fast action of circuit protective devices at high 

currents. Also, mechanical stress caused by electrical faults is not considered a 

credible aging mechanism since such faults are infrequent and random in nature. 

The corrective action process is used to document adverse conditions and 

provides corrective actions associated with electrical faults and transients that 

cause the actuation of circuit protective devices.

Frequent Manipulation or Vibration

Wear and fatigue is caused by repeated removal and reinsertion of fuses. The 

fuses in these fuse holders are not subject to frequent manipulation (i.e., removal 

and reinsertion) because they are neither clearance nor isolation points which 

support periodic testing or preventative maintenance. Additionally, if fuses are 

manipulated for nonroutine inspection or maintenance, proceduralized good work 
3-403

practices would identify any abnormal condition such as loose or corroded fuse 

holders. These fuse holders are located in electrical panels that are not mounted 

on moving or rotating equipment such as motors, compressors, fans or pumps. 

Because electrical panels are mounted with no attached sources of vibration, 

vibration is not an applicable aging mechanism. Therefore, these fuse holders 

will not exhibit aging effects from frequent manipulation or vibration.

The applicant also stated that potential aging effects as discussed in the GALL Report items 

VI.A.LP-23 and VI.A.LP-31 are applicable to the fuse holders for the drywell drain leak detection 

circuits. Therefore, these fuse holders are included in the Fuse Holders program. The 

applicant’s response to RAI 3.6.2.3-1 also included a list of fuse holders that will be managed by 

the Fuse Holder program and stated that the Fuse Holders program basis document will be 

revised to identify these fuses in Element 1,”Scope of Program,” in the Fuse Holders program 

basis document.

The staff finds the applicant response acceptable. The staff finds that fatigue, mechanical 

stress, vibration, chemical contamination, corrosion, and oxidation stressors are not applicable 

for fuse holders in the toxic chemical detection fuse panels, 500 kV substation battery fuse 

panel, nor the 220 kV substation battery fuse panel at LGS. Fatigue is an aging effect for plants 

that manipulate fuse to de-energize circuits for plant testing. The LGS fuses in these panels are 

not routinely pulled or manipulated for plant testing. Therefore, fatigue and mechanical stress 

are not applicable aging effect for these fuse panels. Ohmic heating and thermal cycling are for 

fuses that carry high current in power supply application or in heavy loading motors. The fuses 

installed in these panels are control circuits operating at low current that do not experience 

thermal cycling or ohmic heating. Therefore, the ohmic heating and thermal cycling are not 

applicable stressors for these fuse panels. Stresses associated with mechanical stress caused 

by electrical faults is not considered a creditable aging stressor since such faults are infrequent 

and the fuse design will interrupt the fault current in milliseconds. Forces associated with faults 

are mitigated by the fast action of fuse elements. Therefore, mechanical stress is not an 

applicable aging effect. Vibration is an applicable aging stressor for fuse holders that are 

mounted on moving equipment such as motors, compressors, and pumps. The fuses in these

panels are not mounted on the equipment. They are mounted on a concrete wall or support 

structure that does not vibrate. Therefore, vibration is not an applicable stressor. Chemical 

contamination, corrosion, and oxidation are not aging stressors for fuse holders located in a 

controlled indoor air environment. Increased resistance of connection caused by chemical 

contamination, corrosion, and oxidation do not apply as indicated in the GALL Report

item VI.A.LP-23. Furthermore, fuse holders are enclosed in a protective panel that would 

provide protection against chemical attack. The applicant has confirmed that there is no 

potential source of chemical contamination in the areas near the fuse holders. The applicant’s 

walkdown for the electrical panels containing the in-scope fuse holders confirmed that the 

operating conditions for these fuse holders are clean and dry, with no evidence of moisture 

intrusion, chemical contamination, oxidation, or corrosion. Therefore, chemical contamination is 

not an applicable aging effect at LGS for the toxic chemical detection fuse panels, 500 kV 

substation battery fuse panel, or the 220 kV substation battery fuse panel. 

The applicant has indicated that the potential aging effects as discussed in the GALL Report 

items VI.A.LP-23 and VI.A.LP-31 are applicable to the fuse holders for the drywell drain leak 

detection circuits. Therefore, these fuse holders are included in the Fuse Holder program. The 

applicant will manage these aging effects with the Fuse Holder program. The staff’s evaluation 

of this program is in SER Section 3.0.3.1.23. The staff finds the proposed AMR acceptable 
3-404

because as discussed above, the applicant has identified the proper aging effects for fuse 

holders within the scope of license renewal and subject to an AMR. Also, the Fuse Holder 

program will detect the increased resistance of connection of the fuse holder metallic clamp 

caused by aging effects using thermography and/or resistance measurement. The testing of the 

fuse holders is consistent with that in GALL Report AMP XI.E5. The applicant will revise the 

Fuse Holders program basis document to identify these fuses in Element 1, “Scope of 

Program,” in the Fuse Holders program-basis document. Therefore, the staff’s concern as 

described in RAI 3.6.2.3-1 is resolved.

3.6.2.1.1 AMR Results Identified as Not Applicable

In LRA Table 3.6.1, item 3.6.1-15 under metal enclosed bus: external surface of enclosed 

assemblies composed of galvanized steel, aluminum exposed to outdoor air, the applicant 

states that there is no galvanized steel or aluminum in metal enclosed bus exposed to outdoor 

air that are in scope of license renewal. During the onsite audit, the staff did not identify metal 

enclosed bus enclosure assemblies composed of galvanized steel or aluminum exposed to 

air-outdoor within the scope of license renewal. Therefore, the staff determined that no AMR is 

required for galvanized steel or aluminum enclosure assemblies at LGS.

In LRA Table 3.6.1, item 3.6.1-20 under transmission conductor composed of aluminum 

exposed to outdoor air, the applicant states that there are no aluminum transmission conductors 

exposed to air-outdoor that are in scope of license renewal at LGS. The staff noted that loss of 

conductor strength caused by corrosion is not applicable to aluminum conductor aluminum alloy 

reinforced (ACAR) transmission conductors. LGS does not have ACAR transmission 

conductors, it has aluminum conductor steel reinforced (ACSR) transmission conductors. 

ACAR transmission conductors are, therefore, not applicable to LGS. The AMR for ACSR 

transmission conductors is addressed in SER Section 3.6.2.2.3. The staff concludes that the 

applicant has demonstrated that the effects of aging for these components will be adequately 

managed so that their 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).

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 these items only apply to PWRs, and finds these 

items are not applicable to LGS.

3.6.2.1.2 Conclusion

The staff evaluated the GALL Report AMR items that the applicant claimed were not applicable. 

On the basis of its review, the staff concludes that the AMR results, which the applicant claimed 

were not applicable, are not applicable to LGS Units 1 and 2.

As discussed in SER Section 3.0.2.2, for those AMRs that the applicant claimed consistency 

with the GALL Report, the staff evaluated the applicant’s claim of consistency. The staff also 

reviewed information pertaining to the applicant’s consideration of recent operating experience 

and proposals for managing aging effects. On the basis of its review, the staff concludes that 

the AMR results, which the applicant claimed to be consistent with the GALL Report, are 

consistent.
3-405

Therefore, the staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their 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).

3.6.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended 

In LRA Section 3.6.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the electrical and I&C system components and provides information 

concerning how it will manage the following aging effects:

 • electrical equipment subject to EQ

 • reduced insulation resistance caused by presence of any salt deposits and surface 

contamination, and loss of material caused by mechanical wear caused by wind blowing on 

transmission conductors

 • loss of material caused by wind-induced abrasion and fatigue, loss of conductor strength 

caused by corrosion, and increased resistance of connection caused by oxidation or loss of 

preload

 • QA for aging management of nonsafety-related components

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 3.6.2.2.The staff’s review of the applicant’s 

further evaluation follows.

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification 

LRA Section 3.6.2.2.1 is associated with LRA Table 3.6.1 item 3.6.1-1. The applicant stated 

that Environmental Qualification is a TLAA as defined in 10 CFR 54.3. TLAAs are required to 

be evaluated in accordance with 10 CFR 54.21(c)(1). The applicant also stated that evaluation 

of this TLAA is addressed separately in Section 4.4, “Environmental Qualification (EQ) of 

Electrical Equipment,” of this LRA. SER Section 4.4 documents the staff’s review of the 

applicant’s evaluation of this TLAA and the EQ electrical component program.

3.6.2.2.2 Reduced Insulation Resistance Caused by Presence of Any Salt Deposits and 

Surface Contamination, and Loss of Material Caused by Mechanical Wear

LRA Section 3.6.2.2.2 is associated with LRA Table 3.6.1, items 3.6.1-2 and 3.6.1-3 and 

addresses reduced insulation resistance caused by presence of salt deposits and surface 

contamination, and loss of material caused by mechanical wear. The applicant stated that LGS 

is not located near the seacoast. It is located inland in southeastern Pennsylvania.

The applicant also stated that LGS is located in an area where industrial airborne particle 

concentrations are comparatively low, since it is located in a suburban area with no heavy 

industry nearby. Minor contamination is washed away by rainfall or snow, and cumulative build 
3-406

up has not been experienced and is not expected to occur. Based on LGS’s location and 

confirmed by its operating experience, surface contamination is not a significant aging effect for 

LGS. The applicant then concluded that aging management activities for surface contamination 

from dust, salt, and industrial effluents are not required for the period of extended operation.

Regarding loss of material caused by mechanical wear, the applicant stated that wind loading 

that can cause a transmission line and insulators to sway is considered in the design and 

installation. Although rare, surface rust of the metallic cap may form where galvanizing is burnt 

off caused by flashover from lightning strikes. Surface rust is not a significant concern and 

would not cause a loss of intended function if left unmanaged for the period of extended 

operation. The applicant also stated that wear and surface rust have not been identified during 

routine switchyard inspections. Based on LGS’s design and confirmed by its operating 

experience, mechanical wear caused by wind blowing on transmission conductors is not 

significant enough to cause a loss of intended function. The applicant then concluded that 

aging management activities for loss of material caused by mechanical wear is not required for 

the period of extended operation. 

The staff reviewed LRA Section 3.6.2.2.2 against the criteria in SRP-LR Section 3.6.2.2.2, which 

states that reduced insulation resistance caused by salt deposits and surface contamination 

may occur in high-voltage insulators. The SRP-LR recommends further evaluation of 

plant-specific AMPs for plants at locations of potential salt deposits or surface contamination 

(e.g., in the vicinity of salt water bodies or industrial pollution). Loss of material caused by

mechanical wear caused by wind on transmission conductors may occur in high-voltage 

insulators. The GALL Report recommends further evaluation of a plant-specific AMP to ensure 

that these aging effects are adequately managed.

The staff noted that SRP-LR Section 3.6.2.2.2 states that a plant-specific AMP may be required 

for management of reduced insulation resistance caused by presence of salt deposits and 

surface contamination for plants located such that potential exists for salt deposits or surface 

contamination (e.g., in the vicinity of salt water bodies or industrial pollution). Since LGS is not 

located in the vicinity of salt water bodies or industrial pollution, surface contamination of 

high-voltage insulator is not a concern. In addition, rainfall and snow periodically wash away 

contamination; the glazed insulator surface also aids this contamination removal. The 

plant-specific operating experience at LGS supports the applicant’s conclusion that 

contamination is not significant at LGS because the applicant has indicated that there has been 

no occurrence of insulator flashover caused by dust. 

The staff also notes that EPRI 1013475 (License Renewal Electrical Handbook, Revision 1, 

February 2007) states that mechanical wear in insulators 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 the supported transmission conductor, causing it to swing from side to 

side. 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. Although this mechanism is 

possible, industry operating experience has shown that the transmission conductors do not 

normally swing and that even when they do, caused by a substantial wind, do not continue to 

swing for a long period of time once the wind has subsided. Transmission conductors are 

designed and installed not to swing significantly and cause wear caused by wind induced 

abrasion and fatigue. Transmission conductors within the scope of license renewal are typically 

short spans (connecting the switchyard to the startup transformers) and the surface area 

exposed to wind loads are not significant. Furthermore, the applicant has not identified any 
3-407

instances of loss of material on high-voltage insulators caused by mechanical wear. Based on 

its review, the staff finds that mechanical wear aging effect of high-voltage insulators is not an 

AERM at LGS.

Based on the evaluations above, the staff concludes that the applicant has met the SRP-LR 

Section 3.6.2.2.2 criteria. For those items that apply to LRA Section 3.6.2.2.2, the staff finds 

that 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).

3.6.2.2.3 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

LRA Section 3.6.2.2.3 is associated with LRA Table 3.6.1, items 3.6.1-4, 3.6.1-5, 3.6.1-6, and 

3.6.1-7 addressing loss of material caused by wind-induced abrasion and fatigue, loss of 

conductor strength caused by corrosion, and increased resistance of connections caused by

oxidation or loss of preload of transmission conductors and connections, and switchyard bus 

and connections. The applicant stated that transmission conductor vibration or sway could be 

caused by wind loading. Industry experience has shown that the transmission conductors do 

not normally swing significantly. When transmission conductors do swing caused by a 

substantial wind, they do not continue to swing for very long once the wind has subsided. The 

applicant also stated that wind loading that can cause a transmission line to vibrate or sway is 

considered in design and installation. The applicant then concluded that the loss of material 

aging effect that could result from wind-induced transmission conductor vibration or sway is not 

applicable and would not cause a loss of intended function for transmission conductors for the 

period of extended operation.

The applicant also stated that the in scope transmission conductors at LGS are a tie line 

between the 500 kV and 220 kV substations. These conductors are 1590 MCM 54/19 

aluminum conductor steel reinforced (ACSR). Each phase has two conductors. The 1590 

MCM 54/19 ACSR transmission conductor is a large, substantial transmission conductor. It is 

approximately 1.5 inches in diameter and is configured with 19 steel conductors wrapped by 54 

aluminum conductors. The rated or ultimate strength per ASTM standards and National Electric

Safety Code (NESC) heavy load tension requirements of 1590 MCM ACSR are 54500 lbs and 

19075 lbs, respectively.

The applicant stated that the PECO Transmission and Distribution design practices follow the 

NESC methodologies. The NESC requires that tension on installed conductors be a maximum 

of 60 percent of the ultimate conductor strength. The NESC also states the maximum tension of 

a conductor must be designed to withstand heavy load requirements, which include 

consideration of ice, wind, and temperature. The most prevalent contribution to loss of 

conductor strength of an ACSR transmission conductor is corrosion, which includes corrosion of 

the steel core and aluminum strand pitting. For ACSR conductors, degradation begins as a loss 

of zinc from the galvanized steel core wires. Corrosion rates depend largely on air quality,

which includes suspended particles chemistry, sulfur dioxide concentration in air, precipitation, 

fog chemistry, and meteorological conditions.
3-408

The applicant stated that tests performed by Ontario Hydroelectric showed a 30 percent loss of 

composite conductor strength of an 80-year-old ACSR conductor caused by corrosion. The 

LGS in scope transmission conductors are the same type of transmission conductors evaluated 

in the Ontario Hydroelectric study and in the analysis of the Ontario Hydroelectric Study and in 

the EPRI License Renewal Electrical Handbook. 

The applicant stated that LGS is located in an area where industrial airborne particle 

concentrations are comparatively low, since it is located in a suburban area with no heavy 

industry nearby. In the Ontario Hydroelectric Study, the conductors most affected by 

atmospheric corrosion were located in areas subject to pollution sources and a major urban 

area. Therefore, the environmental impact to the LGS transmission conductors (which are 

located in a suburban area) is bounded by the Ontario Hydroelectric conductors (which are 

located in polluted and urban environments).

The applicant stated that assuming a 30 percent loss of strength as demonstrated by the 

Ontario Hydroelectric tests, there would still be significant margin between what is required by 

the NESC and actual conductor strength. The margin between the NESC heavy load and the 

ultimate strength is 35,425 lbs; i.e., there is a 65 percent ultimate strength margin. The 

applicant also stated that the Ontario Hydroelectric study showed a 30 percent loss of 

composite conductor strength in an 80-year-old conductor. In the case of the 1590 MCM ACSR 

transmission conductors, a 30 percent loss of ultimate strength would mean that there would still 

be a 35 percent ultimate strength margin between what is required by the NESC and the actual 

conductor strength. The applicant further stated that in conclusion, the in scope LGS 

transmission conductors are bounded by the Ontario Hydroelectric study by test methodology, 

design and construction, and environment. The applicant then concluded that the above 

evaluations demonstrate with reasonable assurance that transmission conductors will have 

ample strength margin through the period of extended operation.

The applicant stated that good bolting practices are employed for transmission connectors. The 

connections are treated with corrosion inhibitors to avoid connection oxidation and torqued at 

the time of installation to avoid loss of preload. The applicant also stated that the transmission 

connectors are designed and installed using lock washers and stainless steel Belleville washers 

(not electroplated) that provide vibration absorption and prevent loss of preload. The applicant 

then concluded that oxidation and loss of preload are not applicable aging mechanisms at LGS.

The applicant stated that switchyard buses are connected to flexible conductors that do not 

normally vibrate and are supported by insulators and ultimately by static, structural components 

such as concrete footings and structural steel. Switchyard bus is rigidly mounted and is,

therefore, not subject to abrasion induced by wind loading. Since there are no connections to 

moving or vibrating equipment, wind-induced abrasion and fatigue is not applicable to LGS 

switchyard bus. The applicant also stated that good bolting practices are employed for 

switchyard bus connections. The connections are treated with corrosion inhibitors to avoid 

connection oxidation and torqued at the time of installation to avoid loss of preload. The 

switchyard bus bolted connections are designed and installed using lock washers and stainless 

steel Belleville washers (not electroplated) that provide vibration absorption and prevent loss of 

preload. The applicant then concluded that oxidation and loss of preload are not applicable 

aging mechanisms at LGS.

The staff reviewed LRA Section 3.6.2.2.3 against the criteria in SRP-LR Section 3.6.2.2.3, which 

states that loss of material caused by wind induced abrasion and fatigue, loss of conductor 
3-409

strength caused by corrosion, and increased resistance of connection caused by oxidation or 

loss of preload could occur in transmission conductors and connections, and in switchyard bus 

and connections. The GALL Report recommends further evaluation of a plant-specific AMP to 

ensure that this aging effect is adequately managed. 

The staff noted switchyard buses are connected to flexible conductors that do not swing and are 

supported by insulators and structural supports such as concrete footings and structural steel. 

Since there are no connections to moving or vibrating equipment, wind-induced abrasion and 

fatigue is not an applicable aging mechanism for switchyard bus and connections at LGS.

The staff noted that wind born particulates have not been shown to be a contributor to loss of 

material at LGS and wind fatigue is addressed in 3.6.2.2.2. Therefore, the staff finds that wind 

induced abrasion and fatigue is not a significant AERM for transmission conductors and 

connections at LGS.

The staff noted that design of switchyard bolted connections precludes torque relaxation. The 

use of stainless steel Belleville washers is the industry standard to preclude torque relaxation. 

LGS design incorporates the use of stainless steel Belleville washers on bolted electrical 

connections to compensate for temperature changes, maintain the proper torque, and prevent 

loosening. This method of assembly is consistent with the good bolting practices recommended 

by industry guidelines (EPRI TR-104213, “Bolted Joint Maintenance & Application Guide”). 

Based on the review, the staff finds that loosing of the switchyard bolted connections is not an 

AERM at LGS. 

The bolted connections and washers at LGS are coated with an antioxidant compound 

(electrical joint compound) before tightening the connection to prevent the formation of oxides 

on the metal surface and to prevent moisture from entering the connection, thus reducing the 

chances of corrosion. The staff finds that increased resistance of connection caused by

oxidation or loss of preload are not significant aging effects requiring management for 

transmission conductor and switchyard bus connections at LGS. 

The Ontario Hydro study showed about 30 percent loss of conductor strength of an 80-year- old 

ACSR conductor caused by corrosion. In addition, the National Electrical Safety Code (NESC) 

requires that tension on installed conductors be a maximum of 60 percent of the ultimate 

conductor strength. The NESC also sets the maximum tension a conductor must be designed 

to withstand under heavy load requirements, which include consideration of 1⁄2 inch of radial ice 

and 4 pounds per square feet (psf) wind. The staff reviewed these requirements concerning the 

specific conductors included in the AMR at LGS. Based on the Ontario Hydro study, a loss of 

conductor strength of 30 percent on ACSR transmission conductors would mean that the 

conductor strength would be 38150 lbs (54,500 lbs x 0.7 = 38,150 lbs). The ratio between the 

heavy loading and the ultimate conductor strength would be approximately 50 percent (19,075 

lbs/38,150 lbs). The NESC requires that tension on installed conductor be a maximum of 

60 percent of the ultimate conductor strength. The tension (heavy load) of a typical 

transmission conductor as illustrated by the applicant would not exceed the NESC maximum 

requirement of 60 percent of the ultimate conductor strength. The staff determined that with a 

30 percent loss of conductor strength, there is still ample margin between the NESC 

requirements and the actual conductor strength. Therefore, the staff finds that loss of conductor 

strength caused by corrosion is not a significant AERM at LGS.
3-410

Based on the evaluations above, 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 function(s) will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.6.2.2.4 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.

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 not consistent with or not addressed in the GALL 

Report.

In LRA Table 3.6.2-1, the applicant, via notes F through J, indicated 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.

3.6.2.3.1 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.

In LRA Table 3.6.2-1, the applicant stated that no aging effect is expected, and, therefore, no 

AMP is credited for managing cement, metal and porcelain high-voltage insulators exposed to 

outdoor air. The applicant cited generic note I indicating that the aging effect in the GALL 

Report for this component, material, and environment combination is not applicable. The LRA 

relates the component to GALL Report items VI.A.LP-32 and LRA Table 3.6.1, item 3.6.1-2 both 

of which identify loss of material caused by mechanical wear caused by wind blowing on 

transmission conductors as an applicable aging effect for porcelain, malleable iron, aluminum, 

galvanized steel, and cement high-voltage insulators exposed outdoor air. The GALL Report 

item states that a plant-specific program is to be evaluated. 
3-411

Plant-specific note 1 states that, based on LGS design and operating experience, loss of 

material is not an applicable aging effect for LGS high-voltage insulators.

The staff’s evaluation of cement, metal, and porcelain high-voltage insulators exposed to 

outdoor air with a potential aging effect of loss of material caused by mechanical wear caused 

by wind blowing on transmission conductors is documented in SER Section 3.6.2.2.2. The staff 

agrees, based on its evaluation, that the aging effect of loss of material caused by mechanical 

wear caused by wind blowing on transmission conductors is not applicable to LGS cement, 

metal, and porcelain high-voltage insulators exposed to outdoor air.

In LRA Table 3.6.2-1, the applicant stated that no aging effect is expected, and, therefore, no 

AMP is credited for managing cement, metal and porcelain high-voltage insulators exposed to 

outdoor air. The applicant cited generic note I indicating that the aging effect in the GALL 

Report for this component, material, and environment combination is not applicable. The LRA 

relates the component to GALL Report item VI.A.LP-28 and LRA Table 3.6.1 item 3.6.1-3, both 

of which identify reduced insulation resistance caused by the presence of salt deposits or 

surface contamination as an applicable aging effect for porcelain, malleable iron, aluminum, 

galvanized steel, and cement high-voltage insulators exposed outdoor air. GALL Report item 

VI.A.LP-28 and LRA Table 3.6.1 item 3.6.1-3, both state that a plant-specific 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). 

The LRA also cites plant-specific note 2 which states that based on LGS design and operating 

experience, reduced insulation is not an applicable aging effect for LGS high-voltage insulators.

The staff’s evaluation of cement, metal, and porcelain high-voltage insulators exposed to 

outdoor air with a potential aging effect of reduced insulation resistance caused by the presence 

of salt deposits or surface contamination is documented in SER Section 3.6.2.2.2. The staff 

agrees, based on its evaluation, that the aging effect of reduced insulation resistance caused by

the presence of salt deposits or surface contamination is not applicable to LGS cement, metal, 

and porcelain high-voltage insulators exposed to outdoor air.

In LRA Table 3.6.2-1, the applicant stated that no aging effect is expected, and, therefore, no 

AMP is credited for managing aluminum and stainless steel switchyard bus and connections 

exposed externally to outdoor air. The applicant cited generic note I indicating that the aging 

effect in the GALL Report for this component, material, and environment combination is not 

applicable. The LRA relates the component to GALL Report item VI.A.LP-39 and LRA 

Table 3.6.1 item 3.6.1-6, both of which identify loss of material caused by wind-induced 

abrasion and increased resistance of connection caused by oxidation or loss of preload as 

applicable aging effects for aluminum, copper, bronze, stainless steel, and galvanized 

switchyard bus and connections exposed outdoor air. GALL Report item VI.A.LP-39 and LRA 

Table 3.6.1 item 3.6.1-6, both state that a plant-specific program is to be evaluated. 

The LRA also cites plant-specific note 3 which states that based on LGS design and operating 

experience, loss of material and increased resistance of connection are not applicable aging 

effects for LGS switchyard bus and connections.

The staff’s evaluation of aluminum and stainless steel switchyard bus and connections exposed 

externally to outdoor air with a potential aging effect of loss of material caused by wind-induced 
3-412

abrasion and increased resistance of connection caused by oxidation or loss of preload is 

documented in SER Section 3.6.2.2.3. The staff agrees, based on its evaluation, that the aging 

effects of loss of material caused by wind-induced abrasion and increased resistance of 

connection caused by oxidation or loss of preload is not applicable to LGS aluminum and 

stainless steel switchyard bus and connections exposed externally to outdoor air.

In LRA Table 3.6.2-1, the applicant stated that no aging effect is expected, and, therefore, no 

AMP is credited for managing aluminum and steel transmission conductors exposed externally 

to outdoor air. The applicant cited generic note I indicating that the aging effect in the GALL 

Report for this component, material, and environment combination is not applicable. The LRA 

relates the component to GALL Report item VI.A.LP-47 and LRA Table 3.6.1 item 3.6.1-7, both 

of which identify loss of material caused by wind-induced abrasion as an applicable aging effect 

for aluminum and steel transmission conductors exposed outdoor air. GALL Report item 

VI.A.LP-47 and LRA Table 3.6.1 item 3.6.1-7, both state that a plant-specific program is to be 

evaluated for ACAR and ACSR. 

The LRA also cites plant-specific note 4 which states that based on LGS design and operating 

experience, loss of material is not applicable aging effects for LGS transmission conductors.

The staff’s evaluation of aluminum and steel transmission conductors exposed externally to 

outdoor air with a potential aging effect of loss of material caused by wind-induced abrasion is 

documented in SER Section 3.6.2.2.3. The staff agrees, based on its evaluation, that the aging 

effect of loss of material caused by wind-induced abrasion is not applicable to LGS aluminum 

and steel switchyard transmission conductors exposed externally to outdoor air.

In LRA Table 3.6.2-1, the applicant stated that no aging effect is expected, and, therefore, no 

AMP is credited for managing aluminum and steel transmission conductors exposed externally 

to outdoor air. The applicant cited generic note I indicating that the aging effect in the GALL 

Report for this component, material, and environment combination is not applicable. The LRA 

relates the component to GALL Report item VI.A.LP-38 and LRA Table 3.6.1 item 3.6.1-4, both 

of which identify loss of conductor strength caused by corrosion as an applicable aging effect for 

aluminum and steel transmission conductors exposed outdoor air. GALL Report item 

VI.A.LP-38 and LRA Table 3.6.1 item 3.6.1-4, both state that a plant-specific program is to be 

evaluated for ACSR. 

The LRA also cites plant-specific note 5, which states that based on LGS design and operating 

experience, loss of conductor strength is not applicable aging effects for LGS transmission 

conductors.

The staff’s evaluation of aluminum and steel transmission conductors exposed externally to 

outdoor air with a potential aging effect of loss of conductor strength caused by corrosion is 

documented in SER Section 3.6.2.2.3. The staff agrees, based on its evaluation, that the aging 

effect of loss of conductor strength caused by corrosion is not applicable to LGS aluminum and 

steel switchyard transmission conductors exposed externally to outdoor air.

In LRA Table 3.6.2-1, the applicant stated that no aging effect is expected, and, therefore, no 

AMP is credited for managing stainless steel transmission conductors exposed externally to 

outdoor air. The applicant cited generic note I indicating that the aging effect in the GALL 

Report for this component, material, and environment combination is not applicable. The LRA 

relates the component to GALL Report item VI.A.LP-48 and LRA Table 3.6.1 item 3.6.1-5, both 
3-413

of which identify increased resistance of connection caused by oxidation or loss of preload as 

an applicable aging effect for aluminum and steel transmission conductors exposed to outdoor 

air. GALL Report item VI.A.LP-38 and LRA Table 3.6.1 item 3.6.1-5, both state that a 

plant-specific program is to be evaluated. 

The LRA also cites plant-specific note 6 which states that based on LGS design and operating 

experience, increased resistance of connection is not an applicable aging effect for LGS 

transmission conductors.

The staff’s evaluation of stainless steel transmission conductors exposed externally to outdoor 

air with a potential aging effect of increased resistance of connection caused by oxidation or 

loss of preload is documented in SER Section 3.6.2.2.3. The staff agrees that, based on its 

evaluation, the aging effect of increased resistance of connection caused by oxidation or loss of 

preload is not applicable to LGS stainless steel transmission conductors exposed externally to 

outdoor air.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds 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).

3.6.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the electrical and I&C 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).

3.7 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 and Activities.” 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 any changes made to the CLB, in order 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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SECTION 4

TIME-LIMITED AGING ANALYSES

4.1 Identification of Time-Limited Aging Analyses

This safety evaluation report (SER) section provides the United States Nuclear Regulatory 

Commission’s (NRC’s, the staff) evaluation of the applicant’s basis provided by Exelon 

Generation Company, LLC (Exelon or the applicant) 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. TLAAs are 

certain plant-specific analyses that involve time-limited assumptions defined by the current 

operating term. This SER section also provides the staff’s evaluation of the applicant’s basis for 

identifying those exemptions that need to be identified in the LRA pursuant to 54.21(c)(2). 

Pursuant to 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, which 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) involve a system, structure, or component (SCC) within the scope of license renewal 

application, as delineated in 10 CFR 54.4(a)

 (2) consider the effects of aging

 (3) involve time-limited assumptions defined by the current operating term (e.g., 40 years)

 (4) were determined to be relevant by the applicant in making a safety determination

 (5) involve conclusions or provide the basis for conclusions related to the capability of the 

SSC to perform its intended functions, as described in 10 CFR 54.4(b)

 (6) are contained or incorporated by reference in the CLB

For each evaluation, analysis, or calculation the applicant shall demonstrate one of the 

following:

(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

(3) the effects of aging on the intended function(s) will be adequately managed during the 

period of extended operation

In addition, 10 CFR 54.21(c)(2) requires applicants to list all plant-specific exemptions granted 

in accordance with the exemption approval criteria in 10 CFR 50.12 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.
4-2

The staff’s guidance recommendations for reviewing LRA Chapter 4.1 sections are given in 

NUREG-1800, Revision 2, “Standard Review Plan for Review of License Renewal Applications 

for Nuclear Power Plants” (SRP-LR), Section 4.1. 

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 against the six criteria for TLAAs in 10 CFR 54.3. The LRA also 

states that the applicant reviewed the list of TLAAs in the SRP-LR to see if they are applicable 

to and included as part of the applicant’s CLB. 

The applicant stated that its review of the CLB included the following plant-specific or generic 

sources (documents or records): (1) Updated Final Safety Analysis Report (UFSAR); 

(2) Technical Specifications; (3) NRC Safety Evaluation Reports for the original operating 

licenses; (4) NRC Safety Evaluations (SEs) applicable to its CLB; (5) docketed licensing 

correspondence; (6) vendor-issued, NRC-sponsored, and licensee topical reports; (7) design 

calculations; (8) Code stress reports or Code design reports; and (9) plant drawings and 

specifications.

The applicant provided its list of TLAAs in LRA Table 4.1-2, and indicates that the following 

evaluations, analyses, or calculations in the CLB meet the six criteria for TLAAs in 10 CFR 54.3 

and are TLAAs for the LRA:

 • reactor pressure vessel (RPV) neutron embrittlement in LRA Section 4.2 

 • metal fatigue in LRA Section 4.3

 • environmental qualification of electrical components in LRA Section 4.4

 • containment liner and penetrations fatigue analysis in LRA Section 4.5

 • plant-specific TLAAs in LRA Section 4.6

The applicant provided its bases for dispositioning these TLAAs in accordance with the 

requirements in either 10 CFR 54.21(c)(1)(i), (ii), or (iii) in the applicable subsections of LRA 

Sections 4.2 – 4.6.

The applicant indicated that the following generic evaluations, analyses, or calculations listed in 

SRP-LR Table 4.1-2 are not part of its CLB; therefore, the LRA does not need to include these 

generic categories of TLAAs as applicable TLAAs for the LRA:

 • concrete containment tendon prestress 

 • inservice local metal containment corrosion analyses 

The applicant also indicates potentially applicable plant-specific evaluations, analyses, or 

calculations listed in SRP-LR Table 4.1-3 that are not part of its CLB; therefore, the LRA does 

not need to include these categories of TLAAs:
4-3

 • intergranular separation of reactor vessel low-alloy steel under austenitic stainless steel 

cladding 

 • low-temperature overpressure protection (LTOP) analysis

 • fatigue analysis for reactor coolant pump (RCP) flywheel

 • flow-induced vibration endurance limit analyses for reactor vessel internals (RVI)

 • fatigue analysis for main steam supply lines to a steam-driven auxiliary feedwater pump

 • leak-before-break (LBB) analyses

 • metal corrosion allowance analyses

 • inservice inspection flaw growth analyses for a 40-year period

4.1.1.2 Identification of Regulatory Exemptions

The applicant stated that its review of the CLB identified two exemptions based on a TLAA, but 

neither of these exemptions is required for the period of extended operation. The exemptions 

were associated with pressure-temperature (P-T) limits developed using exemptions to 

Appendix G of 10 CFR Part 50 to permit use of American Society of Mechanical Engineers 

(ASME) Code Cases N-588 and N-640. Since the current P-T limits are only valid for 

32 effective full-power years (EFPY), the LRA states that they must be superseded before the 

period of extended operation. Therefore, the current exemptions will not be required during the 

period of extended operation.

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 results for the 

LRA against the six criteria for TLAA identification in 10 CFR 54.3 and the generic list of TLAAs 

in SRP-LR Section 4.1, including those in SRP-LR Tables 4.1-2 and 4.1-3 as applicable to its 

CLB. The staff used the review procedures in SRP-LR Section 4.1.3 as the basis for its review.

4.1.2.1.1 Evaluations, Analyses, and Calculations in the CLB Conforming to 10 CFR 54.3 TLAA 

Criteria

The staff confirmed that the applicant included its TLAAs for the RPV neutron irradiation 

embrittlement analyses in the applicable referenced subsections of LRA Section 4.2, which 

includes the TLAAs for the upper-shelf energy (USE) assessment, adjusted reference 

temperature (ART), P-T limits assessment, reactor vessel (RV) circumferential weld inspection, 

RV axial weld inspection, and RV core reflood thermal shock analysis. The staff confirmed that 

these analyses conform to all six of the criteria for identifying TLAAs in 10 CFR 54.3. Thus, the 

staff noted that the applicant’s identification of these TLAAs was in conformance with the staff 

recommendations in SRP-LR Sections 4.1 and 4.2, which provide the bases for identifying 

these types of neutron irradiation embrittlement analyses as TLAAs in accordance with the 

requirements in 10 CFR 54.21(c)(1). Based on this review, the staff finds that the identification 

of these analyses as TLAAs is acceptable because it is in compliance with 10 CFR 54.21(c)(1). 

The staff evaluates the applicant’s basis for dispositioning each of these TLAAs in accordance 

with either 10 CFR 54.21(c)(1)(ii) or (iii) in the applicable subsections of SER Section 4.2.
4-4

The staff confirmed that the applicant included its TLAAs on metal fatigue analyses in the 

applicable subsections of LRA Section 4.3. The staff confirmed that these analyses conform to 

all six of the criteria for identifying TLAAs in 10 CFR 54.3. Thus, the staff noted that the 

applicant’s identification of these TLAAs was in conformance with the staff recommendations in 

SRP-LR Sections 4.1 and 4.3, which provide the bases for identifying these types of fatigue 

analyses as TLAAs in accordance with the requirements in 10 CFR 54.21(c)(1). Based on this 

review, the staff finds that the identification of these analyses as TLAAs is acceptable because it 

is in compliance with 10 CFR 54.21(c)(1). The staff evaluates the applicant’s basis for 

dispositioning each of these TLAAs in accordance with either 10 CFR 54.21(c)(1)(i) or (iii) in the 

applicable subsections of SER Section 4.3.

The staff noted 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 (GSI) No. 190, dated December 26, 1999. 

The staff’s evaluation of the applicant’s environmentally assisted fatigue (EAF) calculations for 

limiting reactor coolant pressure boundary (RCPB) components is given in SER Section 4.3.3.

The staff confirmed that the applicant included its TLAA on environmental qualification (EQ) of 

electrical equipment in LRA Section 4.4. The staff confirmed that the analysis conforms to all 

six of the criteria for identifying TLAAs in 10 CFR 54.3. Thus, the staff confirmed that the 

applicant’s identification of the EQ TLAA was in conformance with the staff recommendations in 

SRP-LR Sections 4.1 and 4.4, which provide the bases for identifying EQ analyses as TLAAs in 

accordance with 10 CFR 54.21(c)(1). Based on this review, the staff finds that the identification 

of the EQ TLAA is acceptable because it is in compliance with 10 CFR 54.21(c)(1). The staff 

evaluates the applicant’s basis for dispositioning the EQ analysis in accordance with 

10 CFR 54.21(c)(1)(iii) in SER Section 4.4. 

The staff confirmed that the applicant included its TLAAs on fatigue analyses for the 

containment liner and penetrations in LRA Section 4.5. The staff confirmed that the analyses 

conform to the six criteria for TLAAs in 10 CFR 54.3. Thus, the staff noted that the applicant’s 

identification of these TLAAs was in conformance with the staff recommendations in SRP-LR 

Sections 4.1 and 4.6, which provide the staff’s bases for identifying containment structure 

analyses as TLAAs in accordance with 10 CFR 54.21(c)(1). Based on this review, the staff 

finds that the identification of these containment component TLAAs is acceptable because it is 

in compliance with 10 CFR 54.21(c)(1). The staff evaluates the applicant’s basis for 

dispositioning these TLAAs in accordance with 10 CFR 54.21(c)(1)(iii) in SER Sections 4.5.

The staff confirmed that the applicant included the following plant-specific TLAAs for the LRA in 

the LRA Section 4.6: (1) reactor enclosure crane cyclic loading analysis (LRA Section 4.6.1),

(2) emergency diesel generator (EDG) enclosure cranes cyclic loading analysis (LRA 

Section 4.6.2), (3) RPV core plate rim hold-down bolt loss of preload (LRA Section 4.6.3),

(4) main steam line flow restrictors erosion analysis (LRA Section 4.6.4), (5) jet pump auxiliary 

spring wedge assembly (LRA Section 4.6.5), (6) jet pump restrainer bracket pad repair clamps 

(LRA Section 4.6.6), (7) refueling bellows and support cyclic loading analysis (LRA 

Section 4.6.7), (8) downcomers and main steam relief valve (MSRV) discharge piping fatigue 

analyses (LRA Section 4.6.8);and (9) jet pump slip joint repair clamps (LRA Section 4.6.9). The 

staff noted that the applicant’s identification of these TLAAs was in conformance with the staff 

recommendations for identifying plant-specific TLAAs in SRP-LR Sections 4.1 and 4.7. 
4-5

Based on this review, the staff finds that the identification of these plant-specific TLAAs is 

acceptable because it is in compliance with 10 CFR 54.21(c)(1). The staff evaluates the 

applicant’s basis for dispositioning these plant-specific TLAAs in accordance with either 

10 CFR 54.21(c)(1)(i), (ii), or (iii) in the applicable subsections of SER Section 4.6.

4.1.2.1.2 Staff Evaluation of Applicant’s List of Evaluations, Analyses, and Calculations in the 

CLB That Do Not Conform to Six Criteria for TLAAs in 10 CFR 54.3 and the Absence of Generic 

or Potentially Applicable Plant-Specific TLAAs caused by Absence in the CLB

Main Steam Isolation Valves Metal Fatigue TLAA. UFSAR Section 5.4.5.2, states that the 

design objective for the main steam isolation valve (MSIV) is a minimum of 40 years’ service at 

the specified operating conditions. Operating cycles (excluding exercise cycles) are estimated 

to be 50 cycles per year during the first year and 20 cycles per each year thereafter. The staff 

noted that the MSIV analysis performed was based on a specific number of operating cycles. 

However, the applicant did not identify this analysis as a TLAA in the LRA. By letter dated 

January 31, 2012, the staff issued RAI 4.1-1 requesting the applicant to justify why the MSIV 

analysis performed based on operating cycles need not be identified as a TLAA in accordance 

with 10 CFR 54.21(c)(1).

In its response dated February 29, 2012, the applicant stated that the MSIV fatigue analysis is a 

TLAA identified and evaluated in LRA Section 4.3.1 for ASME Code, Section III, Class 1 valves. 

The staff noted that LRA Section 4.3.1 describes the applicant’s disposition of the metal fatigue 

TLAA for ASME Code Section III, Class 1 components including Class 1 valves. The staff’s

evaluation of the applicant’s TLAA disposition is documented in SER Section 4.3.1.2. The 

applicant also stated that operating cycles described in UFSAR Section 5.4.5.2 are included in 

the thermal and pressure cycles evaluated in the MSIV ASME Code Section III, Class 1 fatigue 

analysis. The applicant stated that the MSIV fatigue analysis is based on the transients listed in 

UFSAR Section 3.9.1.1.8, “Main Steam Isolation Valve Transients.” The staff noted that one of 

those transients in UFSAR Section 3.9.1.1.8 is “Preop @ 100 F/hr” with a limit of 150 cycles and 

this transient was not included in LRA Tables 4.3.1-1 and 4.3.1-2. Therefore, it was not clear to 

the staff whether this transient is monitored or needs to be monitored during the period of 

extended operation. By letter dated April 17, 2012, the staff issued followup RAI 4.1-1.1 

requesting the applicant to clarify if this transient is associated with a transient already 

monitored by the Fatigue Monitoring program. 

In its response dated May 4, 2012, the applicant stated that the “Preop at 100oF/hr” thermal 

transient, referenced in UFSAR Section 3.9.1.1.8, is not monitored by the Fatigue Monitoring 

program. The applicant explained that the MSIVs were designed in accordance with the 

1968 Draft ASME Code for Pumps and Valves for Nuclear Power. The Draft ASME Code 

required the manufacturer to verify the adequacy of the valve for its expected cyclic loading 

conditions by computing a thermal cyclic index, It, with a limit of 1.0. The applicant explained 

that the design specifications for the MSIVs describe this transient as “Preoperational and 

Periodic Inservice Testing” with a total 150 cycles, but Section 454.1.d in the Draft ASME 

Code allows the transient to be excluded from the consideration in these cyclic duty evaluations. 

The applicant stated that, therefore, the transient did not contribute to the It values calculated for 

the MSIVs. The staff noted that since this transient was not included in the determination of the 

It value in the design calculation, the transient is not required to be monitored by the Fatigue 

Monitoring program.
4-6

The staff finds the applicant’s responses to RAI 4.1-1 and followup RAI 4.1-1.1 acceptable 

because the applicant clarified that the TLAA disposition of the MSIV is documented in LRA 

Section 4.3.1 and the “Preop at 100 F/hr” transient was not used in determining the It value for 

the MSIV; thus, the Fatigue Monitoring program can be used, without monitoring this transient, 

to ensure the TLAA remains valid. The staff’s concerns identified in RAI 4.1-1 and followup

RAI 4.1-1.1 are resolved.

Absence of a Concrete Containment Tendon Prestress TLAA. In LRA Table 4.1-2, the applicant 

identified that the Limerick Generating Station (LGS), Units 1 and 2, CLBs do not include a 

containment tendon pre-stress analysis. The applicant stated that its containment design does 

not include tendons.

SRP-LR Table 4.1-2 identifies the containment tendon pre-stress analysis as a generic type of 

TLAA that may be generically applicable to an applicant’s plant design. SRP-LR Section 4.5 

provides the staff’s recommended criteria for accepting these type of TLAAs in accordance with 

the TLAA acceptance requirements in 10 CFR 54.21(c)(1)(i), (ii), or (iii). The relevant SRP-LR 

recommendations are only applicable to concrete containment structures that use pre-stressed 

tendons as the containment structure reinforcement basis.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff confirmed, from its review of UFSAR Section 3.8.1, that the containment 

is a concrete structure reinforced with rebar and, therefore, it does not use pre-stressed tendons 

as the basis for reinforcing the containment mat, cylinder, or dome. Therefore, the staff 

concludes that the LRA does not need to include a concrete containment pre-stress TLAA 

because it has confirmed that the containment does not include pre-stressed tendons as the 

containment reinforcement basis. Thus, it is not contained in or incorporated by reference in the 

LGS Units 1 and 2 CLBs (Criterion 6 of 10 CFR 54.3(a)).

Absence of an Inservice Localized Metal Containment Corrosion TLAA. In LRA Table 4.1-2, the 

applicant identified that the LGS Units 1 and 2 CLBs do not include any inservice local metal 

containment corrosion analyses for the containment structure. 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. 

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff confirmed that UFSAR Section 3.8 indicates that the containment is a 

reinforced concrete containment design. The staff also confirmed that UFSAR Section 3.8 does 

not reference any localized metal corrosion analyses for the containment structure, other 

Seismic Category 1 structures, or their subcomponents. Therefore, the staff concludes that the 

LRA does not need to include any localized metal containment corrosion TLAAs because it has 

confirmed that the applicant’s CLB does not include any metal corrosion analyses for the 

concrete containment structure, other Seismic Category 1 structures, or their subcomponents. 

Thus, localized metal corrosion analyses are not contained in or incorporated by reference in 

the LGS Units 1 and 2 CLBs (Criterion 6 of 10 CFR 54.3(a)). 

Absence of a TLAA for Managing Growth of Intergranular Separation of Reactor Vessel 

Low-Alloy Steel under Austenitic Stainless Steel Cladding. In LRA Table 4.1-2, the applicant 

identified that the CLB does not include any cycle-dependent analysis in evaluation of 

intergranular separations (underclad cracks or underclad cracking) in RPV cladding-to-forging 

welds. 
4-7

SRP-LR Table 4.1-3 identifies that the CLB may include a plant-specific RPV underclad 

cracking analysis that qualifies as a TLAA for the applicant’s LRA. The relevant SRP-LR 

recommendations are only applicable to pressurized-water reactor (PWR) or boiling water 

reactor (BWR) designs that include RPV SA-508, Class 2 forgings that were welded to the RPV 

cladding using an uncontrolled high-heat input weld process. The SRP-LR guidance does not 

apply if the CLB confirms that the design of the shell, head, or nozzle portions of the RPV does 

not include such forging components, or if it can be demonstrated that the heat input used to 

fabricate the applicable SA-508 Class 2 forging-to-cladding welds was appropriately controlled 

during the weld fabrication process. The NRC Regulatory Guide (RG) 1.43 provides the 

recommended criteria for meeting these weld process heat input controls. 

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 5.3.1.2 identifies that the RPVs are 

fabricated primarily from high-strength, low-alloy steel plates and forgings. UFSAR 

Section 5.3.1.2 also indicates that the low-alloy steel RPV plates were ordered to SA-533, 

Grade B, Class 1 specifications and the forgings were ordered to ASME SA-508 Class 2. 

RG 1.43 identified that underclad cracking has been observed for SA-508 Class 2 forging and 

plates made to coarse grain practice. UFSAR Section 5.3.1.4.1.3 indicates that the cracking 

discussed in RG 1.43 is not applicable to its RPV because its vessel plate and nozzle forgings 

are made to fine grain practice. Furthermore, UFSAR Section 5.2.3.3.2.4 indicates that its 

welding of cladding to low-alloy steel forgings is made with a low-heat input process. The staff 

also noted that, in accordance with RG 1.43, such a low-heat input process minimizes heating 

to the base metal and that cracking was not observed in SA-508 Class 2 materials clad by a 

low-heat input process. 

Based on its review, the staff concludes that the generic RV underclad cracking analysis listed 

in SRP-LR Table 4.1-3 is not a TLAA for LGS Units 1 and 2. This analysis is not a TLAA in 

accordance with 10 CFR 54.21(c)(1) because the staff has confirmed that LGS Units 1 and 2

RV designs do not include SA-508 Class 2 or 3 forging shells or forging nozzles with cladding 

welded to the vessel using a high-heat input welding process. Thus, the RV underclad cracking 

analysis is not contained in or incorporated by reference in the LGS Units 1 and 2 CLBs

(Criterion 6 of 10 CFR 54.3(a)).

Absence of a Low-Temperature Overpressure Protection TLAA. In LRA Table 4.1-2, the 

applicant identified that the Units 1 and 2 CLBs do not include a LTOP analysis for the RPV and 

RCPB. 

SRP-LR Table 4.1-3 identifies that the CLB may include a plant-specific LTOP analysis that 

qualifies as a TLAA. The SRP-LR recommendations are only applicable to the LTOP systems 

in PWRs. The SRP-LR guidance is not applicable to BWRs because BWRs do not include 

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 Chapter 1 of the UFSAR defines the reactors as a General 

Electric (GE)-designed BWR built to the BWR-4 model specifications. The staff also confirmed 

that the BWR-4 model does not include an LTOP system. Therefore, the staff concludes that 

the LRA does not need to include a plant-specific LTOP TLAA because the staff has confirmed

that the applicant’s reactor design does not have an LTOP system. Thus, the LTOP analysis is 
4-8

not contained in or incorporated by reference in the LGS Units 1 and 2 CLBs (Criterion 6 of 

10 CFR 54.3(a)).

Absence of a TLAA for Main Steam Supply Lines to a Steam-Driven Auxiliary Feedwater Pump. 

In LRA Table 4.1-2, the applicant identified that the LGS Units 1 and 2 CLBs include fatigue 

analyses for main steam supply lines to turbine-driven HPCI pumps and RCIC pump.

SRP-LR Table 4.1-3 identifies that the CLB may include a plant-specific metal fatigue analysis 

for auxiliary feedwater (AFW) pump main steam supply lines that qualifies as a TLAA. The 

SRP-LR recommendations are only applicable to PWRs that include steam-driven AFW pumps. 

The SRP-LR guidance is not applicable to BWRs because BWRs are not designed with AFW 

pumps.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that Chapter 1 of the UFSAR defines the reactors as a 

GE-designed BWR built to the BWR-4 model specifications. The staff also confirmed that the 

BWR-4 model does not include AFW systems or pumps. Therefore, the staff concludes that the 

LRA does not need to include a plant-specific TLAA for steam-driven AFW pump steam supply 

lines because it has confirmed that the applicant’s reactor design does not have AFW systems 

or pumps. The staff’s review of the fatigue analyses for the main steam supply lines to the 

HPCI and RCIC pumps are documented in SER Section 4.3.1.2. Thus, the fatigue analysis for 

main steam lines that supply steam to steam-driven AFW pumps is not contained in or 

incorporated by reference in the LGS Units 1 and 2 CLBs (Criterion 6 of 10 CFR 54.3(a)).

Absence of a Flaw Growth TLAA for Reactor Coolant Pump Flywheels. In LRA Table 4.1-2, the 

applicant identified that the CLB does not include any cycle dependent flaw growth or flaw 

tolerance, for RCP flywheels. SRP-LR Table 4.1-3 identifies that that 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 SRP-LR guidance is not applicable to a BWR 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 Chapter 1 of the UFSAR defines the reactors as a 

GE-designed BWR built to the BWR-4 model specifications. The staff also confirmed that the 

BWR-4 model does not include an RCP flywheel. Therefore, the staff concludes that the LRA 

does not need to include a plant-specific TLAA for RCP flywheels because it has confirmed that 

the applicant’s reactor design does not have RCP flywheels. Thus, the flaw growth analysis for 

RCP flywheels is not contained in or incorporated by reference in the LGS Units 1 and 2 CLBs 

(Criterion 6 of 10 CFR 54.3(a)).

Absence of a Flow-Induced Vibration Endurance Limit Analyses for RVI Components. SRP-LR 

Table 4.1-3 identifies “Flow-Induced Vibration (FIV) Endurance Limit for the Reactor Vessel 

Internals” as an analysis that may be generically applicable to an applicant’s CLB. 

UFSAR Section 3.9.2.4 indicates that the reactor internals were tested consistent with the 

provisions of RG 1.20, Revision 2, “Comprehensive Vibration Assessment Program for Reactor 

Internals During Preoperational and Initial Startup Testing,” for nonprototype Category I plants. 

The test procedure required operating the recirculation system at the rated flow, with internals 

installed, followed by inspection for evidence of vibration, wear, or loose parts. The test 
4-9

duration was sufficient to subject critical components to at least 106 cycles of vibration during 

two-loop and single-loop operation of the recirculation system. UFSAR Section 3.9.2.3 also 

states that the major reactor internal components within the vessel were subjected to extensive 

testing coupled with dynamic systems analyses to properly describe the resulting FIV 

phenomena incurred from normal operation and from anticipated operational transients. The 

staff noted that the stresses associated with the high-cycle FIV analyses for the RVI 

components would permit the components to withstand an extremely high number (more than 

106 cycles) of low stress cycles beyond the number of vibratory cycles associated with the end 

of the period of extended operation, and the analyses would not conform to the TLAA Criterion 3 

in 10 CFR 54.3(a), that the analyses does not involve time-dependent parameters defined by 

the life of the plant (e.g., 40 years).

The staff noted that the applicant received a 5-percent stretch power uprate (SPU) by an 

amendment dated January 24, 1996, for LGS Unit 1 and February 16, 1995, for LGS Unit 2. In 

its SPU amendment request, the applicant indicated that the stretch power uprate did not have 

an impact on the FIV loads assumed for the design of the RV internals. The staff reviewed the 

SPU SE and noted that Section 3.2.3 of the SE concluded that the 5 percent SPU would have 

little or no effect on the FIV assumptions for the RV internals because the uprated conditions did 

not create any change to the maximum allowable core flow. 

The staff also noted that the applicant received a 1.65-percent measurement uncertainty 

recapture (MUR) power uprate by an amendment dated April 3, 2011, for LGS Units 1 and 2. In 

its MUR amendment request, the applicant indicated that the MUR uprate also did not have an

impact on the FIV loads assumed for the design of the RV internals. The staff reviewed the SE 

for the MUR amendment approval and noted that Section 3.5.2 of the SE concluded that the 

1.65-percent MUR power uprate would have little or no effect on the FIV assumptions for the RV 

internals because the maximum licensed core flow is unchanged. The staff also noted that the 

SE did not identify a need to include assessment of any age-related degradation caused by FIV 

of the RV internal components under SPU and MUR loads. 

Based on this review, the staff concludes that the RV internals FIV endurance limit analyses do 

not meet the definition of TLAAs because the analyses do not involve time-limited assumptions 

defined by the current operating term (Criterion 3 of 10 CFR 54.3(a)). 

Absence of a Leak-Before-Break TLAA. In LRA Table 4.1-2, the applicant identified that its 

review of the LGS Units 1 and 2 CLBs did not identify any LBB analysis for the RCPB piping. 

SRP-LR Table 4.1-3 identifies that the CLB may include a plant-specific time-dependent LBB 

analysis for the RCPB that qualifies as a TLAA. The staff noted that the relevant SRP-LR 

recommendations are only applicable to LBB analyses requested for high-energy piping 

systems in PWR RCPB designs and approved by the staff for relaxation from “Dynamic Effect”

analysis requirements in 10 CFR Part 50, Appendix A, General Design Criterion (GDC) 4. The 

staff noted that the relevant SRP-LR guidance is not applicable to BWR designs because the 

staff has not approved any LBB analysis methodologies for analogous high-energy piping in 

BWR RCPB designs. The staff reviewed the information in the UFSAR and confirmed that the 

applicant’s design basis does not include or make reference to any LBB analysis requested and 

approved for relaxation from the dynamic effect analysis requirements in 10 CFR Part 50, 

Appendix A, GDC 4. 

Based on its review, the staff concludes that the LRA does not need to include a plant-specific 

LBB TLAA because it has confirmed that the LGS Units 1 and 2 CLBs do not include any LBB 
4-10

analyses. Thus, a LBB analysis is not contained or incorporated by reference in the applicant’s 

CLB (Criterion 6 of 10 CFR 54.3(a)). 

Absence of Plant-Specific Metal Corrosion Allowance TLAAs. In LRA Table 4.1-2, the applicant 

identified that the LGS Units 1 and 2 CLBs do not include any time-dependent metal corrosion 

allowance evaluations for metallic components that would need to be identified as TLAAs for the 

LRA. SRP-LR Table 4.1-3 identifies that the CLB may include a plant-specific metal component 

corrosion allowance analysis that qualify as TLAAs. 

The staff considered additional documents, such as NRC generic communications and ASME 

Code requirements, which could incorporate a requirement for a corrosion allowance TLAA. 

The staff reviewed the information in the UFSAR for relevance to the applicant’s “absence of a 

TLAA” basis and noted that, in UFSAR Table 3.9-6(g), the applicant identified that the 

calculation of the minimum wall thickness for nozzles on the main steam safety/relief valves 

included a corrosion allowance of the components. The staff also noted that, in UFSAR 

Table 3.9-6(h), the applicant identified a corrosion allowance of a 0.12-inch minimum that was 

added to minimum wall thickness for the MSIVs. The staff noted that in UFSAR 

Section 5.2.3.2.3, the applicant states that conservative corrosion allowances were included in 

the design of carbon steel and alloy steel reactor coolant system (RCS) components to protect 

them from general corrosion as a result of exposure to the reactor coolant environment. The 

staff noted that the corrosion allowances, specified in the initial design of these components as 

an input, were not based on any time-dependent analyses.

Based on its review, the staff concludes that the LRA does not need to include a plant-specific 

metal corrosion allowance TLAA because it has confirmed that the applicant’s design does not 

have a time-dependent assessment for metal corrosion (Criterion 3 of 10 CFR 54.3(a)).

Absence of Inservice Inspection Flaw Growth Analyses Defined by a 40-Year Period. In LRA 

Table 4.1-2, the applicant identified that the LGS Units 1 and 2 CLBs do not include any 

time-dependent inservice inspection flaw growth, flaw tolerance, or fracture mechanics 

evaluations for ASME Code Class components that demonstrate structural stability over a 

40-year period. SRP-LR Table 4.1-3 identifies that the CLB may include a plant-specific 

inservice inspection fatigue flaw growth or time-dependent flaw tolerance analyses that qualify 

as TLAAs. 

During the review of the LRA, the staff confirmed that the CLB did not include any inservice 

inspection-based flaw evaluations defined by a 40-year licensing period, with the exception of 

the applicant’s flaw evaluation for a vessel nozzle-to-safe end weld identified below.

In Appendix C to the LRA, as amended by letter dated February 15, 2012, the applicant 

provided responses to applicant action items (AAIs) to all applicable Boiling Water Reactor 

Vessel and Internals Project (BWRVIP) reports credited for aging management. In particular, 

AAI No. 14 for BWRVIP-74-A “BWR Reactor Vessel Inspection and Flaw Evaluation 

Guidelines,” states:

Components that have indications that have been previously analytically 

evaluated in accordance with subsection IWB-3600 of Section XI to the ASME 

Code until the end of the 40-year service period shall be re-evaluated for the 

60-year service period corresponding to the LR term.
4-11

The UFSAR supplement contains a commitment (Commitment No. 47) to address 

BWRVIP-74-A, AAI No. 14. Commitment No. 47 states that the flaw in LGS Unit 1 RPV nozzle 

to safe-end weld VRR-1RD-1A-N2H will be re-evaluated in accordance with ASME

Code, Section XI, Subsection IWB-3600, for the 60-year service period. The staff noted that 

BWRVIP-74-A is referenced by the BWR Vessel Internals program and the staff’s evaluation of 

the applicant’s program is documented in SER Section 3.0.3.2.2. The staff also noted that the 

response did not include a justification of why such analyses were not identified as TLAAs in 

accordance with 10 CFR 54.21(c)(1). By letter dated March 9, 2012, the staff issued RAI 4.1-2 

requesting the applicant to justify whether or not the flaw evaluations should be identified as 

TLAA for the LRA.

In its response dated March 20, 2012, the applicant stated that a flaw was identified in the, 

LGS, Unit 1 RPV nozzle-to-safe end weld VRR-1RD-1A-N2H (N2H) in 1989 during an 

ultrasonic test examination. Three evaluations of the flaw in the N2H safe end were performed 

in accordance with ASME Code Section XI, Subsection IWB-3600, before the use of the 

mechanical stress improvement process (MSIP) repair process in 1992. The applicant stated 

that the first two evaluations were performed to justify that it was acceptable for continued 

service for one additional operating cycle and they do not conform to the definition of a TLAA. 

The applicant also stated that the third evaluation was submitted to the staff by letter dated 

April 3, 1992, for the application of MSIP. The applicant stated in the April 3, 1992, letter that an 

evaluation to verify the stability of the crack was performed based on ASME Code, Section XI, 

Subsection, IWB-3642. The applicant further stated that this evaluation and the application of 

MSIP are not TLAAs because they do not involve time-limited assumptions defined by the 

current operating term (Criterion 3 of 10 CFR 54.3(a)). The staff reviewed the information in the 

April 3, 1992, letter and confirmed that the evaluation of the compressive stress zone generated 

by the MSIP and the magnitude of the compressive stress do not involve a time-dependent 

parameter. The staff also confirmed that the provision in ASME Code, Section XI, IWB-3642, 

which relies on the safety margin based on load for normal, emergency, and faulted operating 

conditions, do not involve any time-dependent parameter. 

Based on its review, the staff found the applicant’s response to RAI 4.1-2 acceptable because 

the applicant clarified that the flaw evaluations performed for the MSIP application do not 

involve time-limited assumptions defined by the current operating term (Criterion 3 of 

10 CFR 54.3(a)). Therefore, the staff concluded that the applicant does not need to include a 

plant-specific TLAA for the flaw tolerance evaluations for the RPV nozzle-to-safe end weld 

VRR-1RD-1A-N2H (N2H). 

Based on its review, the staff concludes that the LRA does not need to include a plant-specific 

TLAA for inservice inspection flaw analysis because it has confirmed that the LGS Units 1 and 2 

CLBs do not include any inservice inspection flaw analyses with time-dependent assumption. 

Thus, inservice inspection flaw analyses are not contained or incorporated by reference in the 

applicant’s CLB (Criterion 6 of 10 CFR 54.3(a)). 

Potentially Applicable TLAAs in Response to BWRVIP Report AAIs. The LRA references 

several BWRVIP reports, which have been reviewed and approved by the staff, as part of its 

aging management programs (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 AAIs that were to be addressed by license renewal applicants as part of the basis for 

applying the reports to the CLB. BWR applicants applying for license renewal were requested 

to include their responses to the AAIs in their LRAs. The staff noted that the LRA did not 
4-12

include the applicant’s responses to the AAIs associated with these BWRVIP reports. By letter 

dated January 17, 2012, the staff issued RAI BWRVIP-1 requesting the applicant to submit the 

necessary information for each AAI in the BWRVIP reports that are applicable to the LGS CLB. 

In its response, dated February 15, 2012, the applicant amended the LRA to include a new 

Appendix C that addressed each of the applicable AAIs. The applicant stated that it identified a 

need to provide a new license renewal commitment for BWRVIP-74-A, “BWR Reactor Pressure 

Vessel Inspection and Flaw Evaluation Guidelines,” relative to AAI No. 14. The staff noted that 

the applicant’s BWR Vessel Internals program credits BWRVIP-74-A. The staff’s review of AAI 

No. 14 on BWRVIP-74-A is documented in SER Section 3.0.3.2.2. 

The staff noted that the applicant also provided responses to AAIs for the following BWRVIP 

reports in LRA Appendix C:

 • BWRVIP-18, “BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines

(Revision 1)”

 • BWRVIP-25, “BWR Core Plate Inspection and Flaw Evaluation Guidelines”

 • BWRVIP-26-A, “BWR Top Guide 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 2)

 • 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, “BWR Vessel ID Attachment Weld Inspection and Flaw Evaluation 

Guidelines” (Credited in BWR Vessel ID Attachment Weld program)

 • BWRVIP-49-A, “BWR Instrument Penetration Inspection and Flaw Evaluation Guidelines” 

(Credited in BWR Penetrations program)

 • BWRVIP-74-A, “BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guideline 

for License Renewal”

 • BWRVIP-76-A, “BWR Core Shroud Inspection and Flaw Evaluation Guidelines”

Based on its review, the staff found that the applicant resolved the issue identified in 

RAI BWRVIP-1 because the applicant amended the LRA to include its responses to each of the 

AAIs currently applicable to the LGS Units 1 and 2 CLBs. The staff’s evaluations of the 

applicant’s responses to the AAIs that relate to TLAAs are provided in the following subsections.

TLAA-Related AAIs that are Generically Applicable to Multiple BWRVIP Reports. The staff 

noted that AAI No. 2 is generically applicable to the aforementioned BWRVIP reports listed 

above. AAI No. 2 requests that LR applicants referencing the applicable BWRVIP reports 

ensure that the programs and activities specified as necessary in the applicable BWRVIP report 

are summarily described in the UFSAR supplement, including the evaluation of TLAAs for the 

period of extended operation. 

In LRA Appendix C, the applicant stated that the UFSAR supplement, contained in LRA 

Appendix A, includes a summary description of the programs and activities, as required by this 
4-13

AAI. The staff confirmed that the applicant included the applicable UFSAR supplements, for 

each of the TLAAs, in accordance with 10 CFR 54.21(c)(1)(d). These UFSAR supplements 

include the following for TLAAs related to reactor vessel and reactor vessel internal 

components: 

 • UFSAR supplement A.4.2 and the following subsections for each of the five TLAAs on 

neutron irradiation embrittlement of RV beltline components: 

− A.4.2.2 on the upper-shelf energy assessment 

− A.4.2.3 on the ART assessment 

− A.4.2.4 on the P-T limits assessment 

− A.4.2.5 on the RV axial weld inspection probability of failure analysis 

− A.4.2.6 on the RV circumferential weld inspection

 • UFSAR supplement A.4.3 and its subsections for each of the two TLAAs on metal 

fatigue analyses for including the following: 

− A.4.3.1 on the ASME Code Section III, Class 1 Fatigue Analyses 

− A.4.3.4 on the RV internal components

 • UFSAR supplement A.4.3.3 on the applicant’s EAF analyses for specific ASME Code 

Class 1 components in the RCPB, including selected RV components.

 • UFSAR supplement A.4.6.3 on the applicant’s loss of preload analyses for RPV core 

plate rim hold-down bolt.

Based on this review, the staff finds that the applicant resolved the generically applicable AAI 

No. 2 from the perspective of TLAAs because it has included the appropriate UFSAR 

supplement sections for the TLAAs associated with the reactor vessel and its internal 

components in LRA Appendix A.

Other Specific Fatigue TLAA-Related AAIs Associated with BWRVIP Reports. LRA Appendix C 

identifies that the following BWRVIP guidelines include additional AAIs related to TLAAs: 

 • BWRVIP-18

 • BWRVIP-25 

 • BWRVIP-26-A

 • BWRVIP-42-A

 • BWRVIP-47-A

 • BWRVIP-74-A

The staff evaluates the applicant’s responses to the TLAA-related AAIs in the following 

paragraphs.

BWRVIP-18, AAI No. 4: The AAI states the following: “Applicants referencing the BWRVIP-18 

report for license renewal should identify and evaluate any potential TLAA issues which may 

impact the structural integrity of the subject core spray internals components.” 
4-14

The response to AAI No. 4 in LRA Appendix C states that the metal fatigue TLAA disposition is 

discussed in LRA Section 4.3.4. The staff confirmed that the applicant included its TLAA on 

metal fatigue in LRA Section 4.3.4. Based on this review, the staff finds that the applicant 

resolved AAI No. 4 on BWRVIP-18-A because it included the appropriate metal fatigue TLAA for 

the core spray (CS) in LRA Section 4.3.4. The staff’s evaluation of the applicant’s disposition 

for this TLAA is documented in SER Section 4.3.4.2. 

BWRVIP-25, AAI No. 4. The AAI states the following: “Due to the susceptibility of the rim 

hold-down bolts to stress relaxation, applicants referencing the BWRVIP-25 report for license 

renewal should identify and evaluate the projected stress relaxation as a potential TLAA issue.” 

The response to AAI No. 4 in LRA Appendix C states that 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. Stress relaxation of the RPV core plate rim hold-down bolts has been 

identified as a TLAA issue as evaluated in LRA Section 4.6.3. The staff confirmed that the 

applicant included its TLAA on loss of preload in LRA Section 4.6.3. Based on this review, the 

staff finds that the applicant resolved AAI No. 4 on BWRVIP-25 because it included the 

appropriate TLAA for the rim hold-down bolts in LRA Section 4.6.3. The staff’s evaluation of the 

applicant’s disposition for this TLAA is documented in SER Section 4.6.3.2.

BWRVIP-26-A, AAI No. 4. The AAI states the following: “Due to [irradiation-assisted stress 

corrosion cracking] IASCC susceptibility of the subject safety-related components, applicants 

referencing the BWRVIP-26 report for license renewal should identify and evaluate the 

projected accumulated neutron fluence as a potential TLAA issue.” 

The response to AAI No. 4 in LRA Appendix C states that accumulated neutron fluence for the 

top guide is not a TLAA for LGS Units 1 and 2 because the top guide has exceeded the 

threshold fluence levels for IASCC identified in BWRVIP-26-A. The applicant also stated that 

the aging effect is managed by inspections conducted as part of BWR Vessel Internals program 

per guidance in BWRVIP-183. The staff confirmed that, in LRA Table 3.1.2-3, the applicant 

identified that cracking is an applicable aging effect requiring management for the top guide and 

credits its BWR Vessel and Internals program for aging management. The staff finds that the 

applicant does not need to treat the fluence level for the top guide as a TLAA because the 

applicant postulates cracking as an applicable aging effect for the top guide components and 

credits its BWR Vessel and Internals program and its BWRVIP-183 inspections for aging 

management. The staff noted that this approach includes management of IASCC, which may 

be induced 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 SER Section 3.0.3.2.2. 

Based on this review, the staff finds that the applicant resolved AAI No. 4 of BWRVIP-26-A. 

BWRVIP-42-A, AAI No. 4. The AAI states the following: “Applicants referencing the 

BWRVIP-42 report for license renewal should identify and evaluate any potential TLAA issues 

which may impact the structural integrity of the subject RPV internals components.” 

The response to the AAI in LRA Appendix C states that the metal fatigue TLAA disposition is 

discussed in LRA Section 4.3.4. The staff confirmed that the applicant included its TLAA on 

metal fatigue for reactor vessel internals (RVIs) in LRA Section 4.3.4. Based on this review, the 

staff finds that the applicant resolved AAI No. 4 on BWRVIP-42-A because it included the 
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appropriate metal fatigue TLAA for the CS in LRA Section 4.3.4. The staff’s evaluation of the 

applicant’s disposition for this TLAA is documented in SER Section 4.3.4.2. 

BWRVIP-47-A, AAI No. 4. The AAI states the following: “Due to fatigue of the subject 

safety-related components, applicants referencing the BWRVIP-47 report for LR should identify 

and evaluate the projected CUF as a potential TLAA issue.” 

The response to the AAI in LRA Appendix C states that the fatigue usage is considered a TLAA 

for RVIs, including the lower plenum, and is discussed in LRA Section 4.3.4. The staff 

confirmed that the applicant included its TLAA on metal fatigue in LRA Section 4.3.4. Based on 

this review, the staff finds that the applicant resolved AAI No. 4 on BWRVIP-47-A because it 

included the appropriate metal fatigue TLAA for the lower plenum in LRA Section 4.3.4. The 

staff’s evaluation of the applicant’s disposition for this TLAA is documented in SER 

Section 4.3.4.2. 

BWRVIP-74-A, AAI No. 8. The AAI states the following:

LR applicants should verify that the number of cycles assumed in the original 

fatigue design is conservative to assure that the estimated fatigue usage for 

60 years of plant operation is not underestimated. The use of alternative actions 

for cases where the estimated fatigue is projected to exceed 1.0 will require 

case-by-case staff review and approval. Further, a LR applicant must address 

environmental fatigue for the components listed in the BWRVIP-74 report for the 

LR period.

The response to the AAI in LRA Appendix C states that the RVIs fatigue analyses are evaluated 

as TLAAs in LRA Section 4.3.4. The response further stated that transient cycle projections 

demonstrate that current transient cycle limits will not be exceeded during the period of 

extended operation. The response also stated that environmental fatigue for reactor vessel 

components is addressed in LRA Section 4.3.3 with results shown in LRA Table 4.3.3-1. 

The staff confirmed that the applicant included the applicable metal fatigue TLAAs for the RV 

and RV internals components in LRA Sections 4.3.1 and 4.3.4, respectively. The staff also 

confirmed that transient cycle projections and EAF evaluations are included in LRA 

Sections 4.3.1 and 4.3.3, respectively. Based on this confirmation, the staff finds that the 

applicant’s response to AAI No. 8 is acceptable and resolves the AAI item because the 

applicant has included the applicable EAF evaluations and metal fatigue TLAAs for these 

components in LRA Sections 4.3. The staff’s evaluations of the applicant’s disposition of the 

EAF evaluations and TLAAs for the RV and its internal components are documented in SER 

Sections 4.3.3.2, 4.3.1.2, and 4.3.4.2, respectively.

BWRVIP-74-A, AAI No. 9. The AAI states the following: “Appendix A to the BWRVIP-74 report 

indicates that a set of P-T [Pressure-Temperature] curves should be developed for the heat-up 

and cool-down operating conditions in the plant at a given EFPY in the LR periods.” 

The response to the AAI in LRA Appendix C states that P-T limit curves will be developed for 

the period of extended operations consistent with the requirements of Appendix G to 10 CFR, 

Part 50, and is described in LRA Section 4.2.4. The staff confirmed that the applicant included 

its TLAA on P-T limit curves in LRA Section 4.2.4. Based on this review, the staff finds that the 

applicant resolved AAI No. 9 on BWRVIP-74-A because it included the appropriate P-T Limit 
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curve TLAA in LRA Section 4.2.4. The staff’s evaluation of the applicant’s disposition for this 

TLAA is documented in SER Section 4.2.4.2. 

BWRVIP-74-A, AAI No. 10. The AAI states the following: 

To demonstrate that the beltline materials meet the Charpy USE criteria specified 

in Appendix B of the report, the applicant shall demonstrate that the percent 

reduction in Charpy USE for their beltline materials are less than those specified 

for the limiting BWR/3-6 plates and the non-Linde 80 submerged arc welds and 

that the percent reduction in Charpy USE for their surveillance weld and plate are 

less than or equal to the values projected using the methodology in RG 1.99, 

Revision 2.

The response to the AAI in LRA Appendix C states that Charpy USE values for the period of 

extended operation were determined using methods consistent with RG 1.99, Revision 2, and is 

described in LRA Section 4.2.2 with results displayed in LRA Tables 4.2.2-1 and 4.2.2-2. The 

staff confirmed that the applicant included its TLAA on Charpy USE in LRA Section 4.2.2. 

Based on this review, the staff finds that the applicant resolved AAI No. 10 on BWRVIP-74-A 

because it included the appropriate Charpy USE TLAA in LRA Section 4.2.2. The staff’s 

evaluation of the applicant’s disposition for this TLAA is documented in SER Section 4.2.2.2. 

BWRVIP-74-A, AAI No. 11. The AAI states the following: 

To obtain relief from the in-service inspection of the circumferential welds during 

the LR period, the BWRVIP report indicates each licensee will have to 

demonstrate that (1) at the end of the renewal period, the circumferential welds 

will satisfy the limiting conditional failure frequency for circumferential welds in 

Appendix E for the staff’s July 28, 1998, SER; and (2) that they have 

implemented operator training and established procedures that limit the 

frequency of cold overpressure events to the amount specified in the staff’s 

FSER.

The response to the AAI in LRA Appendix C states that at the end of the renewal period the 

circumferential welds for each unit will satisfy the limiting conditional failure frequency in the 

staff’s July 28, 1998 FSER, and that the discussion of the relief from ISI inspection of 

circumferential welds is in LRA Section 4.2.6. The staff confirmed that the applicant included its 

TLAA on circumferential weld inspections in LRA Section 4.2.6 and that the applicant 

demonstrated the 2 items discussed in the AAI have been satisfied. Based on this review, the 

staff finds that the applicant resolved AAI No. 11 on BWRVIP-74-A. The staff’s evaluation of the 

applicant’s disposition for this TLAA is documented in SER Section 4.2.6.2. 

BWRVIP-74-A, AAI No. 12. The AAI states the following: 

As indicated in the staff’s March 7, 2000, letter to Carl Terry, a LR applicant shall 

monitor axial beltline weld embrittlement. One acceptable method is to 

determine that the mean RTNDT [reference temperature nil ductility transition] of 

the limiting axial beltline weld at the end of the period of extended operation is 

less than the values specified in Table 1 of this FSER.
4-17

The response to the AAI in LRA Appendix C states that the mean RTNDT of the limiting axial 

beltline weld for each unit at the end of the period of extended operation is less than the value 

specified in Table 1 of BWRVIP-74-A FSER and the axial weld inspection TLAA is discussed in 

LRA Section 4.2.5. The staff confirmed that the applicant included its TLAA on axial welds in 

LRA Section 4.2.5 and that the limiting axial beltline weld at the end of the period of extended 

operation is less than the values specified in Table 1 of the BWRVIP-74-A FSER. Based on this 

review, the staff finds that the applicant resolved AAI No. 12. The staff’s evaluation of the 

applicant’s disposition for this TLAA is documented in SER Section 4.2.5.2.

BWRVIP-74-A, AAI No. 13. The AAI states the following: 

The Charpy USE, P-T limit circumferential weld and axial weld RPV integrity 

evaluations are all dependent upon the neutron fluence. The applicant may 

perform neutron fluence calculations using staff approved methodology or may 

submit the methodology for staff review. If the applicant performs the neutron 

flluence calculation using a methodology previously approved by the staff, the 

applicant should identify the NRC letter that approved the methodology.

The response to the AAI in LRA Appendix C states that an NRC approved methodology was 

used to determine fluence during the period of extended operation and that the methodology 

used was approved within the SER for BWRVIP-114, 115, 117, and 121, and that the 

discussion of the fluence methodology is in LRA Section 4.2.1. The staff confirmed that the 

applicant included its TLAA on fluence in LRA Section 4.2.6. Based on this review, the staff 

finds that the applicant resolved AAI No. 13 on BWRVIP-74-A because the applicant referenced

a previously approved methodology and referenced the NRC approval for the referenced 

methodology. The staff’s evaluation of the applicant’s disposition for this TLAA is documented 

in SER Section 4.2.1.2. 

TLAA-Related AAI Response Conclusion. Based on this review, the staff concludes that the 

applicant either provided a response the staff found acceptable or resolved all of the staff’s 

requests raised in applicable TLAA-related AAIs of the BWRVIP reports referenced in the SER. 

The applicant’s responses to the TLAA-related AAIs are resolved.

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 granted under 

10 CFR 50.12 that are based on a TLAA and evaluate them and justify their use during the 

period of extended operation. The staff reviewed the LGS Units 1 and 2 CLBs to see if they

included any exemptions granted in 10 CFR 50.12 and based on a TLAA. The staff reviewed 

the current operating license and Technical Specifications for the facility and the applicant’s 

UFSAR. The staff’s review also included a search of the NRC’s official recordkeeping system 

(main and legacy libraries in the Agencywide Documents Access and Management System 

(ADAMS)) using the keyword “exemption.” 

The staff noted that the P-T limits for the reactor vessel and RCPB are based on compliance 

with the P-T limit generation requirements in 10 CFR Part 50, Appendix G. For LGS Unit 1, the 

applicant requested an exemption from 10 CFR Part 50, Appendix G, to permit the use of ASME 

Code Cases N-588 and N-640. The staff noted that the 32 Effective Full Power Year (EFPY) 

P-T limits were granted for LGS Unit 1 for Cycle 9 in License Amendment No. 145 dated 
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September 15, 2000. The 32 EFPY P-T limits were granted for Unit 2, for Cycle 7 in License 

Amendment No. 111 dated March 21, 2001. 

In LRA Section 4.2.1, the applicant projected 35 EFPY and 37 EFPY will be accumulated at the 

end of the 40 years operation for LGS Units 1 and 2, respectively. Thus, the staff needed to 

assess whether the exemptions will be needed during the period of extended operation under 

two scenarios: 1) if the actual EFPY at the end of the 40 years operation will be greater than 32 

EFPY; and 2) if the actual EFPY at the end of the 40 years operation will be less than 32 EFPY. 

For the first scenario that the actual EFPY will be greater than 32 EFPY, the applicant is 

required to obtain a new P-T limit based on the requirements in 10 CFR Part 50, Appendix G.

Thus, the current exemptions will be replaced and no longer in effect during the period of 

extended operation. For the second scenario that the actual EFPY will be less than 32 EFPY, 

however, the applicant did not provide an evaluation to justify the continuation of the exemptions 

for the period of extended operation, as required by 10CFR 54.21(c)(2). By letter dated July 10, 

2012, the staff issued RAI 4.1-3 requesting the applicant provide an evaluation that justified the 

continuation of those exemptions associated with Code Cases N-640 and N-588 in the event 

that the current approved P-T limits would be in effect during the period of extended operation. 

In its response dated July 11, 2012, the applicant stated that the staff approved the exemptions 

in letters dated September 7, 2000 for LGS Unit 1 and March 21, 2001 for LGS Unit 2. The 

applicant also updated LRA Table 4.1-3, which corrected the LGS Unit 1 exemption approval 

date. The staff noted that these two approved exemptions placed restriction of their use for one 

operating cycle on each unit. Based upon subsequent fluence data submitted by the applicant 

in letter dated June 26, 2002, the staff granted the use of the Code Cases, without restriction, 

for both units on January 2, 2003 for LGS Unit 1 in License Amendment No. 163 as well as for 

LGS Unit 2 in License Amendment No. 125.

The applicant justified that continuation of the exemption into the period of extended operation

because the use of Code Cases as a basis for the 32 EFPY P-T limits was approved by the 

staff. The staff reviewed the safety evaluation for the exemption in the license amendment 

dated January 2, 2003, and confirmed that use of the exemptions were extended for both units 

to 32 EFPY without any limitation with respect to number of years of plant operation. Thus, the 

staff finds it acceptable that the current exemptions continue to be in effect during the period of 

extended operation if the actual EFPY at the end of the 40 years operation will be less than 32 

EFPY. The applicant also revised LRA Sections 4.1.5 and A.4.1 to reflect that the exemptions 

are identified and justified for continuation during the period of extended operation. Based on its 

review, the staff finds the applicant’s response to RAI 4.1-3 acceptable because the applicant 

provided an evaluation to justify the continuation of the exemptions for the period of extended 

operation, as required by 10CFR 54.21(c)(2).

The staff also noted that Section 2.D, in both LGS Unit 1 Operating License NPF-39 and LGS 

Unit 2 Operating License NPF-85, identified that the applicant was granted a number of 

exemptions from the requirements in 10 CFR Part 50, Appendix J. The staff noted that the 

exemptions involve the method of performing leak rate testing of the containment and MSIVs. 

The staff also noted that those tests are discussed in UFSAR Section 6.2.6 and the exemptions 

on the method of testing do not involve time-limited assumptions defined by the current 

operating term. Thus, these exemptions on the leak-rate testing do not meet Criterion 3 of 

10 CFR 54.3(a) for the definition of a TLAA and the exemption identification criterion in 

10 CFR 54.21(c)(2). 
4-19

Based on its review and the information provided by the applicant, the staff concludes, in 

accordance with 10 CFR 54.21(c)(2), that the applicant has provided a list of plant-specific 

exemptions granted and in effect that are based on TLAAs and the applicant has provided an 

evaluation that justify the continuation of these exemptions for the period of extended operation.

4.1.3 UFSAR Supplement 

LRA Section A.4.1, as amended by letter dated July 11, 2012, provides the UFSAR supplement

summarizing the identification of TLAA and exemptions. Based on its review of the UFSAR 

supplement, the staff finds that the supplement meets the acceptance criteria in SRP-LR 

Section 4.1.2 which states that UFSAR supplement descriptions are provided for each identified 

TLAA. Additionally, the staff determines that the applicant provided an adequate summary 

description to address TLAA and exemptions identification, as required by 10 CFR 54.21(d).

4.1.4 Conclusion 

Based on its review, the staff concludes that the applicant provided an accurate lists of TLAAs, 

as required by 10 CFR 54.21(c)(1). The staff concluded that the applicant has identified the 

appropriate exemptions granted under the requirements in 10 CFR 50.12 and that are based on 

a TLAA, as required by 10 CFR 54.21(c)(2).

4.2 Reactor Pressure Vessel Neutron Embrittlement 

LRA Section 4.2 describes the neutron embrittlement analyses performed for LGS Units 1 

and 2. The LRA states that the beltline region of the RV includes the reactor vessel plates, 

welds and forging materials that are predicted to receive a cumulative neutron exposure that 

exceeds 1.0 x 1017 neutrons/cm2 during the licensed life of the plant.

The LRA states that the TLAAs related to neutron embrittlement are the following:

 • neutron fluence projections (LRA Section 4.2.1)

 • upper-shelf energy (LRA Section 4.2.2)

 • ART (LRA Section 4.2.3)

 • pressure – temperature limits (LRA Section 4.2.4)

 • axial weld inspection (LRA Section 4.2.5)

 • circumferential weld inspection (LRA Section 4.2.6)

 • RPV reflood thermal shock (LRA Section 4.2.7)

 • RPV core plate rim hold-down bolt loss of preload (LRA Section 4.6.3)

 • jet pump auxiliary spring wedge assembly (LRA Section 4.6.5)

 • jet pump restrainer bracket pad repair clamps (LRA Section 4.6.6)

 • jet pump slip joint repair clamps (LRA Section 4.6.9) 
4-20

4.2.1 Neutron Fluence

4.2.1.1 Summary of Technical Information in the Application

LRA Section 4.2.1 summarizes the evaluation of neutron fluence for the period of extended 

operation. To evaluate the effects of neutron irradiation embrittlement on the safety-related 

fracture toughness analyses for the RPV beltline components, the applicant indicated that 

analyses were performed to determine the neutron fluence projections for the RPV beltline 

components through 57 EFPY of operations, which is the projected EFPY associated with 

60 years of licensed operations. The applicant stated that the projections account for a 

5 percent increase in power approved and implemented for LGS Unit 1 starting in cycle 7 and 

for LGS Unit 2 in cycle 4, and an additional 1.65 percent increase in power approved and 

implemented for LGS Unit 1 during midcycle 14 and implemented for LGS Unit 2 at the 

beginning of operating cycle 12.

The applicant stated that the 57 EFPY neutron fluences (E > 1.0 MeV) for the RPV beltline 

shell, weld, and nozzle components at LGS were calculated using the Radiation Analysis 

Modeling Application (RAMA) fluence methodology (RAMA code fluence methodology) that was 

developed for the Electric Power Research Institute (EPRI) and the BWRVIP. The applicant 

stated that use of this methodology was performed consistent with the recommendations and 

guidelines presented in RG 1.190. The applicant stated that the RAMA code fluence 

methodology was also used to determine the 57 EFPY neutron fluence values for the RVI

components at Units 1 and 2.

The applicant stated that each of the LGS fluence projection models are based upon quadrant 

azimuthal symmetry, which means one quarter of the reactor core was modeled in detail to 

provide an accurate representation of the core configuration. The models also include accurate 

geometric representations of the RPV, including the N16 water level instrumentation (WLI) 

nozzles and the N17 low-pressure coolant injection (LPCI) nozzles and their associated 

nozzle-to-vessel weld, which are included in the reactor vessel beltline. The applicant 

references EPRI Report No. 1007283, “BWR Vessel and Internals Project, RAMA Fluence 

Methodology Software (BWRVIP-126),” dated 2003, as the applicable RAMA code 

fluence methodology for the 57 EFPY neutron fluence projections used in the neutron irradiation 

embrittlement assessment TLAAs in the LRA. The applicant stated that this methodology was 

reviewed and approved by the staff. 

The applicant stated that the RVP fluence values were determined at the interface of the RPV 

base metal and cladding (0T) for the RPV beltline materials, which include the RPV lower shell 

plates, RPV lower-intermediate shell plates, RPV axial welds (i.e., RPV weld designations BA, 

BB, BC, BD, BE, BF, BG, BH, and BJ), RPV circumferential weld AB, the N16 WLI nozzles, and 

the N17 LPCI nozzles and their associated nozzle-to-vessel welds. The applicant stated that 

the fluence projections for these nozzles are based upon the highest fluence value at the edge 

of each cutout location within the shell plate and, therefore, are considered applicable for the 

nozzle welds. The applicant identified that the N16 WLI instrumentation nozzles and welds are 

fabricated from nickel-alloy materials. As such, the applicant states that these nozzles and 

welds are not required to be evaluated for loss of fracture toughness by the requirements in 

10 CFR Part 50, Appendix G, because the components are not fabricated from ferritic materials. 

The applicant stated that the 1/4T fluence values for the RPV beltline components were then 

determined from the 0T values using two different methods permitted by RG 1.99, Revision 2. 
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The applicant stated that the first of these 1/4T fluence value methods used a plant-specific 

calculation of displacements per atom (dpa) in iron, substituting the ratio of dpa at the 

1/4T depth to the dpa at 0T in place of the exponential attenuation factor in Equation 3. 

The applicant stated that the second of these methods used the generic exponential attenuation 

formulation provided in Equation 3. The applicant stated that since the 1/4T values obtained 

using the plant-specific dpa method were higher than those resulting from the generic 

attenuation method, the plant-specific 1/4T fluence values were used in evaluating the neutron 

embrittlement TLAAs.

LRA Table 4.2.1-1 provides the 57 EFPY fluence projections for Unit 1, reactor vessel beltline 

shells (plates), girth (circumferential) welds and axial (vertical) welds. LRA Table 4.2.1-2 

provides the 57 EFPY fluence projections for LGS Unit 1 beltline nozzle forgings. 

Table 4.2.1-3 shows the 57 EFPY fluence projections for Unit 2, reactor vessel beltline shells 

(plates), girth (circumferential) welds and axial (vertical) welds. Table 4.2.1-4 shows the 

57 EFPY fluence projections for LGS Unit 2 beltline nozzle forgings.

The applicant stated that the bounding fluence value determined for each RPV shell ring at 

Units 1 and 2 is to be used in the evaluation of all three plates within each shell. For Shell 3 of 

both LGS Units 1 and 2, the highest 57 EFPY neutron fluence for that shell was less than 1.0 x 

1017 neutrons/cm2 and thus these materials were not evaluated for USE or ART.

4.2.1.2 Staff Evaluation

The staff reviewed the applicant’s information against the criteria in RG 1.190, Revision 0, 

“Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence,” 

issued March 2001. The staff noted that the LRA cited BWRVIP-126 as the applicable BWRVIP 

fluence methodology for conforming to the recommendations of RG 1.190, Revision 0. The staff 

noted that the BWRVIP report cited in the LRA only referred to the software programming 

(i.e., RAMA) used to calculate the LGS 57 EFPY. However, in reviewing the applicant’s most 

recent P-T limits for Units 1 and 2 (approved by license amendment No. 163 in January 2003), 

the staff noted that the GE Company Report No. NEDC-32983P-A methodology was used to 

derive the 32 EFPY neutron fluence values for the LGS P-T limit curves. Thus, the staff noted 

that the LRA was not clear about which methodology was adopted by the applicant in its CLB 

(i.e., BWRVIP or GE report) to conform to RG 1.190, nor did the LRA provide the appropriate 

basis to justify why the previously-approved methodology in GE Report No. NEDC-32983P-A 

was not used for derivation of the 57 EFPY neutron fluences values for the LRA.

By letter dated May 18, 2012, the staff issued RAI 4.2.1-1, requesting the applicant to provide its 

basis for referencing the use of RAMA Code methodology to calculate neutron fluence for 

TLAAs in the LRA, when such methodology has not been previously identified as part of the 

applicant’s CLB. As part of its response, the staff also asked the applicant to clearly identify, by 

document reference number, title, and date, all neutron fluence methodologies that are in the 

LGS CLB to conform to the regulatory position in RG 1.190 and to clarify whether the neutron 

fluence methodologies adopted in the CLB has been endorsed for use by the NRC. The staff 

also asked the applicant to clarify how any and all relevant limitations and conditions placed on 

implementation of the fluence calculation methodologies adopted in the LGS CLB have been 

addressed. 
4-22

The applicant responded to RAI 4.2.1-1 by letter dated May 31, 2012. In its response, the 

applicant stated that the use of the RAMA code methodology for calculating neutron fluence 

values (RAMA code fluence methodogy) was benchmarked against the plant-specific dosimetry 

measurement results and reported fluence values from several commercial operating reactors. 

The applicant stated that the RAMA code fluence methodology was reviewed and approved in a 

NRC safety evaluation for the following reports:

 • BWRVIP-114, “BWRVIP RAMA Fluence Methodology Manual”

 • BWRVIP-115, "RAMA Fluence Methodology Benchmark Manual (BWRVIP-115)," 

 • BWRVIP-117, "RAMA Fluence Methodology – Susquehanna Unit 2, Surveillance Capsule 

Fluence Evaluation for Cycles 1-5,"

 • BWRVIP-121, "RAMA Fluence Methodology Procedures Manual" 

 • Hope Creek Evaluation TWE-PSE-001-R-001, "Hope Creek Flux Wire Dosimeter Activation 

Evaluation for Cycle 1"

The applicant stated that in the safety evaluation for the above documents, dated May 13, 2005, 

the staff concluded that the use of the BWRVIP RAMA code fluence methodology provides an 

acceptable “best estimate” methodology for predicting the fast neutron fluencies (for neutrons 

with kinetic energies E > 1.0 Mev) of BWR RPVs.

According to the applicant, the LGS and Susquehanna reactor units have similar designs with 

respect to the design of the reactor vessels fuel assemblies, core shrouds, and jet pump 

assemblies. For this reason, the applicant stated that the application of the RAMA code fluence 

methodology is appropriate for use at LGS because: (a) the LGS reactor units are BWR-IV 

reactors that are similar in design to the reactors for Susquehanna nuclear plant units; 

and (b) the NRC conditions for use of RAMA methodology have been met. Based on this 

determination, the applicant concluded that the RAMA code neutron fluence methodology can 

be applied for the neutron fluence determinations of the LGS RPVs without a bias, as endorsed 

in the NRC SE on use of the RAMA code methodology. 

The applicant also stated that BWRVIP integrated surveillance program was approved by

License Amendment No. 167 for LGS Unit 1 and Amendment No. 130 for LGS Unit 2, dated 

November 4, 2003. 

The applicant indicated that these license amendments define the CLB for computing neutron 

fluence at LGS and that UFSAR Sections 4.1.4.5 and 4.3.2.8 were revised accordingly to state: 

"LGS RPV fluence has been evaluated using a method in accordance with the 

recommendations of RG 1.190. Future evaluations of RPV fluence will be completed using a 

method in accordance with the recommendations of RG 1.190."

The applicant stated that the RAMA code methodology has since been evaluated and adopted 

for use at LGS through implementation of the applicant’s 10 CFR 50.59 design change process. 

The applicant stated that the 57 EFPY neutron fluence values calculated for 60 years of 

operation using RAMA were used in the following sections of the LRA: Section 4.2.2, 

"Upper-Shelf Energy;" Section 4.2.3, "Adjusted Reference Temperature;" Section 4.2.5, "Axial 

Weld Inspection;" Section 4.2.6, "Circumferential Enclosure Weld Inspection;" and Section 

4.2.7, "Reactor Pressure Vessel Reflood Thermal Shock." The applicant stated that it is not 
4-23

currently adopting the RAMA code fluence methodology for LRA 4.2.4, “Pressure Temperature 

Limits,” because the P-T limit curves have not been revised as part of the LRA. The staff notes 

that the P-T limits are included in the LGS Units 1 and 2 technical specification and the revision 

of the P-T limits for the period of extended operation will require a license amendment pursuant 

to 10 CFR 50.90. Therefore, the use of RAMA code fluence methodology for use in 

development of P-T limits will be subject to NRC review and approval for the period of extended 

operation.

The applicant’s response to RAI 4.2.1-1 indicates that NRC-approved Report BWRVIP-117, 

"RAMA Fluence Methodology – Susquehanna Unit 2, Surveillance Capsule Fluence Evaluation 

for Cycles 1-5," was the BWRVIP RAMA code fluence methodology report that was most 

appropriate for application to the LGS CLB caused by the similarity of the LGS and 

Susquehanna reactor designs. Therefore, the staff compared the UFSAR reactor design 

parameters reported in the UFSAR for the Susquehanna units to those reported in the UFSAR 

for the LGS units to determine whether the Susquehanna reactor design provides a valid 

bounding basis for applying Report BWRVIP-117 to the LGS CLB. The staff confirmed that the 

LGS and Susquehanna reactors are all BWR Model IV reactors that have similar reactor and 

reactor vessel internal designs. Based on its verification of the design date, the staff determined 

that the assumptions in Report BWRVIP-117 would be applicable to the LGS reactor design.

From a review of the safety evaluation for the RAMA code fluence methodology, dated 

May 13, 2005, the staff determined that the generic SE endorsing use of the RAMA code 

fluence methodology for calculation of neutron fluence values in the U.S. BWR nuclear industry 

is applicable to LGS Units 1 and 2. 

Therefore, with the exception of the relationship of the RAMA code fluence methodology to the 

P-T limits TLAA, the staff concludes that the applicant has adequately demonstrated that the 

RAMA code fluence methodology is appropriate for application to those remaining neutron 

fluence based TLAAs in the LRA.

Based on this review, the staff finds that the applicant can apply the 57 EFPY neutron fluence 

values reported in LRA Section 4.2.1 to the assessment of the USE analysis (LRA Section 

4.2.2), the ART analysis (LRA Section 4.2.3), the circumferential weld and axial weld probability 

of failure analyses (LRA Sections 4.2.5 and 4.2.6), and the GE RPV reflood thermal shock 

analysis (LRA Section 4.2.7), and for the fluence-based RPV core plate rim hold-down bolt loss 

of preload analysis (LRA Section 4.6.3).

For application to the TLAAs related to the generation of the P-T limits for the period of 

extended operation (i.e., the TLAAs in LRA Section 4.2.3 and 4.2.4), pursuant to the 

requirements in 10 CFR 50.90, the applicant will be required to submit P-T limits for the period 

of extended operation for staff review and have the updated P-T limits approved before the 

expiration of the 32 EFPY P-T limit curves in the technical specifications (i.e., the current P-T 

limit curves approved for the CLB). 

RAI 4.2.1-1 is resolved.

4.2.1.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of 

neutron fluence in LRA Section A.4.2.1. Based on its review of the UFSAR supplement, the 
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staff finds it meets the acceptance criteria in SRP-LR Section 4.2 and is, therefore, acceptable. 

Additionally, the staff determines that the applicant provided an adequate summary description 

of the neutron fluence methodology that was used to establishing the 57 EFPY neutron 

fluencies reported in LRA Section 4.2, as required by 10 CFR 54.21(d).

4.2.1.4 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)(ii), that the 57 EFPY neutron fluence values 

reported for the RPV beltline materials, and for the RPV core plate rim hold-down bolts, 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).

4.2.2 Upper-Shelf Energy 

4.2.2.1 Summary of Technical Information in the Application 

LRA Section 4.2.2 summarizes the applicant’s evaluation of Charpy USE values for the period 

of extended operation. The applicant evaluated compliance with the requirements of 

10 CFR Part 50, Appendix G, using the projected 57 EFPY fluences described in LRA 

Section 4.2.1, as attenuated to the 1/4T location in the wall thickness.

Charpy USE values for most of the materials of the LGS Units 1 and 2 RVs were determined 

consistent with the guidance in RG 1.99, Revision 2, without the use of surveillance data 

(Position 1.2 of the RG). The exception is LGS Unit 1 weld heat 5P6756 from the BWRVIP 

Integrated Surveillance Program, which is the only material applicable for LGS that has credible 

surveillance data. Position 2.2 was used to compute the USE value for weld heat 5P6756. The 

projected USE values for the RV beltline materials were determined to remain in compliance 

with 10 CFR Part 50, Appendix G, requirements, either by demonstrating USE values of at least 

50 ft-lb or through an equivalent margins analysis (EMA).

The applicant dispositions this TLAA in accordance with 10 CFR 54.21 (c)(1)(ii), that the 

analyses have been projected to the end of the period of extended operation.

4.2.2.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.2, in accordance with the review procedures of SRP-LR 

Section 4.2.3.1.1.2, to verify that the Charpy USE analyses have been projected to the end of 

the period of extended operation, pursuant to 10 CFR 54.21(c)(1)(ii). The staff determined the 

chemistry and initial USE values provided in LRA Section 4.2.2 are consistent with those 

provided in the recent license amendment request for a power uprate (approved in Amendment 

Nos. 201 and 163, for Units 1 and 2, respectively, on April 8, 2011). Thus, the values are 

consistent with the CLB for LGS Units 1 and 2. Acceptance criteria for this review are in 

accordance with SRP-LR Section 4.2.2.1.1.2.

Appendix G to 10 CFR Part 50 contains the screening criteria that establish limits on the USE 

values for RV materials after neutron irradiation exposure. The regulation requires the value of 

USE be greater than 50 ft-lbs in the irradiated condition throughout the licensed life of the plant. 

USE values of less than 50 ft-lbs may be acceptable to the staff if it can be demonstrated that 
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these lower values will provide margins of safety against brittle fracture equivalent to those 

required by ASME Code Section XI, Appendix G.

Consistent with RG 1.99, Revision 2, the predicted decrease in USE values caused by neutron 

embrittlement during plant operation is dependent upon the type of material (weld or base 

plate), the amount of copper (Cu) in the material, and the predicted neutron fluence for the 

material. The RG outlines two ways to project the USE values for ferritic steels: Position 1.2 

uses curves of percent decrease in USE as a function of Cu content and neutron fluence (in the 

absence of “credible reactor surveillance data) and Position 2.2 determines percent decrease in 

USE based on the reactor surveillance data. The applicant stated that it used Position 1.2 to 

determine the Charpy USE values at the end of the period of extended operation for all of the 

RV beltline materials except for LGS Unit 1 weld heat number 5P6756, which uses Position 2.2 

because it was the only material with credible surveillance data available.

As part of its review to confirm acceptability of the applicant’s analysis, the staff performed a 

USE evaluation for each of the beltline materials as described in Position 1.2. In all cases, the 

applicant’s projected USE values from Tables 4.2.2-1 and 4.2.2-2 were equal to or less than 

that calculated by the staff, which confirms the conservative nature of the applicant’s evaluation. 

In the case of LGS Unit 1 weld heat number 5P6756, the staff’s prediction from Position 1.2 is 

essentially the same as the applicant’s prediction based on Position 2.2.

Several materials for each unit had projected USE values below 50 ft-lbs at 57 EFPY. In each 

case, the applicant demonstrated equivalence to 10 CFR 50 Appendix G requirements through 

an EMA using the methodology provided in BWROG-94037, “BWR Owners’ Group Topical 

Report on Upper-Shelf Energy Equivalent Margin Analysis – Approved Version,” 

March 21, 1994, and NEDO-32205-A, Revision 1, “10 CFR Part 50, Appendix G, Equivalent 

Margin Analysis for Low Upper-Shelf Energy in BWR/2 through BWR/6 Vessels,” issued 

February 1994. For these materials with projected USE values less than 50 ft-lbs, the staff 

confirmed that the projected percent decrease in the USE value using Position 1.2 of RG 1.99, 

Revision 2, is less than the corresponding approved value from the EMA. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(ii) that the USE 

analyses for the RV beltline materials have been projected to the end of the period of extended 

operation. Additionally, the analyses meet the acceptance criteria in SRP-LR 

Section 4.2.2.1.1.2 because either the projected USE values at the end of the period of 

extended operation are above 50 ft-lbs or the percent decrease in USE value is bounded by an 

approved EMA. 

4.2.2.3 UFSAR Supplement 

LRA Section A.4.2.2 provides the UFSAR supplement summarizing the TLAA evaluation of 

USE. The staff reviewed LRA Section A.4.2.2, consistent with the review procedures in 

SRP-LR Section 4.2.3.2, which states 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. 

Based on its review of the UFSAR supplement, the staff finds that the supplement 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 

evaluation of USE, as required by 10 CFR 54.21(d).
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4.2.2.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that the USE analyses 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 

4.2.3.1 Summary of Technical Information in the Application 

LRA Section 4.2.3 summarizes the ART evaluation of the LGS RV beltline materials for the 

period of extended operation. The applicant states that the fluence values used to calculate the 

ART values are from plant-specific displacements-per-atom attenuation calculations described 

in LRA Section 4.2.1 and consistent with RG 1.99, Revision 2, instead of the generic attenuation 

model outlined in RG 1.99, Revision 2, because the plant-specific values were slightly higher 

(more conservative). The applicant states that the ART values at the 1/4T location for the 

limiting beltline materials remain below 200 °F, consistent with the guidance in [Regulatory 

Position 3] of RG 1.99, Revision 2 [which apply for a new plant]. 

A summary of the limiting ferritic materials at each unit are as follows:

Unit 1 Plate N16 Nozzles LCPI Nozzles Weld

ART +74 °F +48 °F +61 °F +16 °F

Heat No. C7677-1 17-2 Q2Q25W 5P6756

Unit 2 Plate N16 Nozzles LCPI Nozzles Weld

ART +102 °F +38 °F +61 °F +69 °F

Heat No. B3416-1 C9526-1 Q2Q25W 5P6756

The LRA states that the information provided for the N16 nozzles is based upon that for the 

ferritic steel plate adjacent to the nozzle because the N16 nozzles are nickel alloy and do not 

require evaluation in accordance with Appendix G to 10 CFR Part 50.

The applicant dispositions this TLAA for the ART values of the RV beltline materials in 

accordance with 10 CFR 54.21(c)(1)(ii), that the analyses have been projected for the period of 

extended operation.
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4.2.3.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.3 to verify that the ART analyses have been projected to the 

end of the period of extended operation, pursuant to 10 CFR 54.21(c)(1)(ii), and consistent with 

RG 1.99, Revision 2.

Consistent with the guidance of RG 1.99, Revision 2, the ART value for each beltline material is 

evaluated from:

ART = RTNDT(u) + ΔRTNDT + M

where RTNDT(u) is the unirradiated RTNDT as defined in the ASME Code, Paragraph NB-2331, 

ΔRTNDT is the mean value of the shift in RTNDT caused by neutron irradiation, and M is the 

margin term to account for uncertainties in the calculation. The methodology used for 

determining ΔRTNDT and the margin term M are described in RG 1.99, Revision 2. 

In LRA Table 4.2.3-1 and 4.2.3-2, the applicant presented the ART values after 57 EFPY for 

LGS Units 1 and 2. Also presented in these tables are the input parameters necessary for 

calculating the ART values. The staff confirmed that the input parameters for the ART 

calculations are the same as those used in the recent power uprate amendment (approved 

April 8, 2011), and thus, are consistent with the CLB for LGS Units 1 and 2.

As part of its review to confirm acceptability of the applicant’s analysis, the staff performed 

independent ART evaluations for each of the beltline materials in Table 4.2.3-1 and 4.2.3-2. In 

all cases, the applicant’s projected ART values from Table 4.2.3-1 and 4.2.3-2 were equal to or 

greater than that calculated by the staff, which confirms the identity of the limiting materials.

Based on the above discussion, the staff concludes that the ART evaluations for RV beltline 

materials are consistent with the guidance of RG 1.99, Revision 2. The applicant’s TLAA is 

acceptable because it meets the requirements of 10 CFR 54.21(c)(1)(ii) and will ensure that the 

LGS Units 1 and 2 RV materials will have adequate ART values and fracture toughness through 

the period of extended operation.

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(ii), that the ART 

evaluations for the RV beltline materials have been projected to the end of the period of 

extended operation.

4.2.3.3 UFSAR Supplement 

LRA Section A.4.2.3 provides the UFSAR supplement summarizing the TLAA evaluation of 

ART. The staff reviewed LRA Section A.4.2.3, consistent with the review procedures in SRP-LR 

Section 4.2.3.2, which states 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. 

Based on its review of the UFSAR supplement, the staff finds that the supplement 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 

evaluation of ART, as required by 10 CFR 54.21(d).
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4.2.3.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that the ART analyses 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).

4.2.4 Pressure – Temperature (P-T) Limits 

4.2.4.1 Summary of Technical Information in the Application 

LRA Section 4.2.4 summarizes the evaluation of the RV P-T limits, including heatup and 

cooldown operations for the period of extended operation. The current P-T limits, located in the 

technical specifications, were approved up to 32 EFPY. Before exceeding 32 EFPY, 

10 CFR 50, Appendix G, requires new P-T limits to be developed for higher fluence values and 

approved by the NRC.

In addition, the applicant states that the Reactor Vessel Surveillance program provides data to 

update the P-T limits. Based on the available data, LGS Unit 1 is projected to exceed 32 EFPY 

during operating cycle 19, which begins in 2020. LGS Unit 2 is projected to exceed 32 EFPY 

during operating cycle 18, which begins in 2023.

The LRA indicates that SRP-LR Section 4.2.2.1.3 states that the P-T limits for the period of 

extended operation do not have to be submitted as part of the LRA, since the P-T limits are 

required to be updated through the 10 CFR 50.90 licensing process when necessary for P-T 

limits that are located in the Technical Specifications. The applicant stated that it plans to 

submit updates to the P-T limits for LGS Units 1 and 2 to the staff at the appropriate time and by 

the appropriate method to comply with 10 CFR 50, Appendix G.

The applicant dispositions the P-T limits TLAA for LGS Units 1 and 2 in accordance with 

10 CFR 54(c)(1)(iii), that the effects of aging will be adequately managed for the period of 

extended operation.

4.2.4.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.4 to verify that the effects of aging on the P-T limits will be 

adequately managed by the applicant for the period of extended operation, pursuant to 

10 CFR 54.21(c)(1)(iii). This review was consistent with SRP-LR Section 4.2.3.1.3.3 and the 

acceptance criteria of SRP-LR Section 4.2.2.1.3.3.

The staff notes that the current P-T limits, valid for operation up to 32 EFPY, were approved by 

the staff on January 2, 2003, in License Amendment 163 for LGS Unit 1 and License 

Amendment 125 for LGS Unit 2. The staff agrees that the updated P-T limit curves for the 

period of extended operation do not have to be submitted as part of the applicant’s LRA. Before

the expiration of each unit’s current P-T limit curves, the applicant is required to submit revised 

P-T limits in accordance with 10 CFR Part 50, Appendix G, which considers the increase of the 

limiting ART value and plant-specific embrittlement information from any relevant surveillance 

data provided by the BWRVIP ISP. Hence, the staff finds that the applicant’s plan to manage 

the P-T limits in accordance with 10 CFR 54.21(c)(1)(iii) is acceptable because revised P-T limit 
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curves that meet the requirements of 10 CFR Part 50, Appendix G will be implemented by the 

appropriate method. 

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the P-T 

limits will be adequately managed for the period of extended operation. Additionally, the 

analysis meets the acceptance criteria in SRP-LR Section 4.2.2.1.3.3 because the plant-specific 

embrittlement parameters will be used to calculate the limits.

4.2.4.3 UFSAR Supplement 

LRA Section A.4.2.4 provides the UFSAR supplement summarizing the TLAA evaluation of P-T 

limits. The staff reviewed LRA Section A.4.2.4, consistent with the review procedures in 

SRP-LR Section 4.2.3.2, which states 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. 

Based on its review of the UFSAR supplement, the staff finds that the supplement 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 

evaluation of the P-T Limits, 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 demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the P-T limits will be adequately managed during 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).

4.2.5 Axial Weld Inspection 

4.2.5.1 Summary of Technical Information in the Application 

LRA Section 4.2.5 summarizes the TLAA evaluation of the RV axial weld inspection for the 

period of extended operation. The LRA states that BWRVIP-05, “BWR Reactor Pressure 

Vessel Shell Weld Inspection Recommendations,” recommends that 100 percent of the axial 

welds and only those sections of the circumferential welds that intersect with the axial welds 

should be inspected every 10 years. The LRA states that the recommendation for limited 

inspection of circumferential RV welds is based on generic probabilistic fracture mechanics 

analyses that predict the 40-year end-of-life axial weld probability of failure (PoF) is orders of 

magnitude greater than the 40-year end-of-life circumferential weld PoF. The LRA further states 

that the staff used this significant difference in the PoF for the axial and circumferential welds to 

justify relief from inspection of the circumferential welds as described in Generic Letter 

(GL) 98-05. The applicant has provided input data for comparison to the original bounding 

analysis found in the final NRC safety evaluation report (FSER) for BWRVIP-05, dated 

July 28, 1998. The comparison indicates that the limiting RV axial welds at LGS Units 1 and 2 

at 57 EFPY are less likely to fail than the axial weld from the generic RV built by Chicago Bridge 

and Iron (CB&I) at 64 EFPY described in the FSER for BWRVIP-05, because the limiting mean 

RTNDT values for LGS Units 1 and 2 (-4 °F and +9 °F, respectively) are less than that for the 

generic CB&I plant (+117.1 °F).
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The applicant dispositioned the TLAA for the justification of the RV axial weld inspections in 

accordance with 10 CFR 54.21(c)(1)(ii), that the analyses have been projected for the period of 

extended operation.

4.2.5.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.5 to verify that the RV axial welds PoF has been projected 

to the end of the period of extended operation, pursuant to 10 CFR 54.21(c)(1)(ii). This review 

was consistent with SRP-LR Section 4.2.3.1.5 and the acceptance criteria of SRP-LR 

Section 4.2.2.1.5.

The staff has confirmed that all of the input parameters (Cu and nickel (Ni) content, unirradiated 

RTNDT, neutron fluence) used for the PoF calculation listed in LRA Table 4.2.5-1 are consistent 

with those used in the recent power uprate amendment (approved April 8, 2011), and thus, are 

consistent with the CLB for LGS Units 1 and 2. The bounding case is represented by a mean 

ART (ART without the margin term) of +117 °F for a limiting axial weld in a vessel manufactured 

by CB&I. The LGS-specific mean ART value for the Unit 1, limiting axial weld is -4 °F and is 

+9 °F for the limiting Unit 2, axial weld (both vessels were built by CB&I). Because the mean 

ART values for Units 1 and 2 are less than the comparable value for a CB&I-built vessel in the 

FSER for BWRVIP-05, the probability of failure for either of the two LGS RVs is less than the 

failure probability that was found acceptable in the FSER. Hence, the plant-specific analyses

for LGS Units 1 and 2 are bounded by the FSER analysis and, therefore, are acceptable. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(ii), that the TLAA 

associated with the RV axial weld inspection has been projected to the end of the period of 

extended operation. Additionally, it meets the acceptance criteria in SRP-LR Section 4.2.2.1.5.

4.2.5.3 UFSAR Supplement 

LRA Section A.4.2.5 provides the UFSAR supplement summarizing the TLAA evaluation of the 

RV axial weld inspection. The staff reviewed LRA Section A.4.2.5, consistent with the review 

procedures in SRP-LR Section 4.2.3.2, which states 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. 

Based on its review of the UFSAR supplement, the staff finds that the supplement 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 

evaluation of the RV axial welds inspection, 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 has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that the analyses associated with the axial weld inspection 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).
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4.2.6 Circumferential Weld Inspection 

4.2.6.1 Summary of Technical Information in the Application 

LRA Section 4.2.6 summarizes the evaluation of the RPV circumferential weld inspection for the 

period of extended operation. LGS was granted RPV circumferential weld inspection relief from 

the ASME Code requirements for the original license period on September 13, 1999, in LGS ISI 

Program Relief Request RR-1. The relief was based on the evaluation of circumferential welds

at LGS Units 1 and 2 and the limiting CB&I circumferential weld in the FSER for BWRVIP-05. 

The analysis has been projected to compare the mean 57 EFPY RTNDT values for the limiting 

circumferential welds of LGS Units 1 and 2 with those for the limiting CB&I vessel in the FSER 

for BWRVIP-05. In this analysis, the actual RPV failure frequencies are not calculated, but, by 

comparison of the mean RTNDT values, the applicant has demonstrated that the failure 

frequency for the LGS Units 1 and 2 RPV circumferential welds are bounded by the failure 

frequency calculated for the CB&I RPV circumferential welds in the FSER for BWRVIP-05. 

Specifically, the limiting mean RTNDT values for the circumferential welds at LGS Units 1 and 2 

(+10 °F and +9 °F, respectively) are less than that for the generic CB&I plant (+70.6 °F). 

LRA Section 4.2.6 also states that operator training and procedures to limit the frequency of 

cold over-pressure events will continue as required by the staff’s approval of the original relief 

request.

The applicant dispositioned the TLAA for the RPV circumferential weld inspection in accordance 

with 10 CFR 54.21(c)(1)(iii), that the effects of neutron embrittlement on the intended functions 

will be adequately managed by reapplication for relief from the circumferential weld inspection 

under 10 CFR 50.55a(a)(3) before entering the period of extended operation.

4.2.6.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.6 to verify that the TLAA associated with RPV 

circumferential weld inspection will be managed for the period of extended operation, pursuant 

to 10 CFR 54.21(c)(1)(iii). The staff review was performed consistent with SRP-LR 

Section 4.2.2.1.4 and used Generic Letter 98-05. 

The technical basis for the original relief request is found in the FSER for BWRVIP-05, which 

stated the following two requirements for the inspection relief:

(1) at the expiration of the license, the limiting conditional PoF for circumferential welds in 

the evaluation must be below the criterion specified in RG 1.154, “Format and Content of 

Plant-Specific Pressurized Thermal Shock Safety Analysis Reports for Pressurized 

Water Reactors,” and core damage frequency (CDF) of any BWR plant, and 

(2) the applicant must implement operator training and establish procedures that limit the 

frequency of cold overpressure events to the amount specified in the report

The staff has confirmed all of the input parameters (Cu and Ni content, unirradiated RTNDT, 

neutron fluence) used for the PoF calculation listed in LRA Table 4.2.6-1 are consistent with 

those used in the recent power uprate amendment (approved April 8, 2011) ), and thus, are 

consistent with the CLB for LGS Units 1 and 2.. The staff noted that the neutron fluence at 0T 

for the limiting LGS Units 1 and 2 circumferential welds in Table 4.2.6-1 did not agree with the 
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comparable value reported in Tables 4.2.1-1 and 4.2.1-3 for fluence and Tables 4.2.3-1 and 

4.2.3-3 for the temperature shift. In RAI 4.2.6-1, the staff requested that the applicant revise the 

LRA to reflect the accurate fluence projection. In its response dated January 24, 2012, the 

applicant submitted revised fluence values in Table 4.2.6-1 to be consistent with the comparable 

values in Tables 4.2.1-1 and 4.2.1-3 for fluence, and Tables 4.2.3-1 and 4.2.3-3 for the 

temperature shift. This revision to the LRA Table 4.2.6-1 resolves the staff concern expressed 

in RAI 4.2.6-1.

The first criterion from the FSER for BWRVIP-05 is addressed in LRA Table 4.2.6-1, where the 

applicant has summarized the effects of irradiation on the limiting circumferential welds at LGS 

Units 1 and 2 and compared these weld properties to the staff’s limiting CB&I circumferential 

weld used in the July 28, 1998, FSER for BWRVIP-05. The staff notes that the LGS Units 1 and 

2 circumferential welds have a lower copper content, as well as a lower neutron fluence at the 

clad/base metal interface than the limiting CB&I vessel circumferential weld. The unirradiated 

RTNDT and Ni contents are higher for the LGS Units 1 and 2 circumferential welds. Overall, 

however, the effects of chemistry and neutron fluence contribute to lower the mean 57 EFPY 

ART for the LGS Units 1 and 2 circumferential welds when compared to the limiting CB&I vessel 

circumferential weld at 64 EFPY. The staff confirmed that the limiting LGS Units 1 and 2 

circumferential welds are projected to have less irradiation damage than the limiting CB&I 

plant-specific case. Therefore, the applicant’s evaluation is acceptable. 

For the second criterion, the applicant stated in LRA Section 4.2.4 that LGS Units 1 and 2 will 

use the same procedures and training in the period of extended operation that has been the 

practice during the original licensing period. Although this is not specifically related to any 

time-limited parameter subject to a TLAA review, the staff determines that continued 

implementation of operator training and the use of procedures limiting the frequency of cold 

overpressure events meets the second criterion in the FSER for BWRVIP-05.

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(iii), that the 

TLAA associated with the circumferential weld inspection will be adequately managed for the 

period of extended operation. Additionally, the applicant’s analysis meets the acceptance 

criteria in SRP-LR Section 4.2.2.1.4 because the applicant plans to reapply for relief under 

10 CFR 50.55a(a)(3).

4.2.6.3 UFSAR Supplement 

LRA Section A.4.2.6 provides the UFSAR supplement summarizing the TLAA evaluation of the 

RPV circumferential welds inspection. The staff reviewed LRA Section A.4.2.6, consistent with 

the review procedures in SRP-LR Section 4.2.3.2, which states 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. 

Based on its review of the UFSAR supplement, the staff finds that the supplement 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 

evaluation of the RPV circumferential welds inspection, as required by 10 CFR 54.21(d).
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4.2.6.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the TLAA associated with the circumferential weld inspection will be 

adequately managed 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 

4.2.7.1 Summary of Technical Information in the Application 

LRA Section 4.2.7 describes the applicant’s TLAA for thermal shock on the RPV by reevaluating 

the generic fracture mechanics evaluation of the effects of a postulated loss of coolant accident 

(LOCA) on the structural integrity of a BWR. The LRA states that the generic analysis 

envelopes LGS and was based on BWR vessel material properties and 40 year assumed 

cumulative fluence.

The applicant modified the analysis to account for neutron embrittlement by substituting the 

limiting ART values for each unit after 57 EFPY. In addition, the applicant modified the analysis 

for the actual LGS RPV wall thickness, and the wall temperature at the 1/4T location was 

adjusted from 400 °F to 370 °F to ensure that the analysis bounds the temperature at which the 

maximum applied stress intensity factor (KI) = 100 ksi-in1/2 is applied. The applicant then 

calculated the limiting temperature where the material’s resistance (KIc) is equal to 200 ksi-in1/2

based on the limiting ART value for each unit. The applicant’s evaluation showed that the RPV 

for LGS Unit 1 is safe from brittle fracture at any temperature above 178 °F and LGS Unit 2 at 

any temperature above 206 °F. These temperatures compare to the actual RPV temperature of 

370 °F for the 1/4T location in the analysis.

The applicant dispositioned the RPV reflood thermal shock analysis in accordance with 

10 CFR 54.21(c)(1)(ii), 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 for thermal shock to verify, pursuant to 

10 CFR 54.21(c)(1)(ii), that the analyses have been projected to the end of the period of 

extended operation. This review was implemented consistent with SRP-LR Section 4.7.3.

The staff reviewed LRA Sections 4.2.3 and 4.2.7 to verify the fracture toughness of the limiting 

beltline materials. The staff noted that the input data to the calculation of the limiting ART used 

in the reevaluation of the core reflood thermal shock analysis were consistent with 

corresponding input values used to project ART at 57 EFPY for each unit in the recent power 

uprate amendment (approved April 8, 2011), and thus, are consistent with the CLB for Units 1 

and 2. Based on the wide margin between the reported limiting temperatures for safe operation 

for each unit and temperature associated with the maximum KI, the staff determined that brittle 

fracture of the LGS Units 1 and 2 RPVs is unlikely caused by reflood thermal shock following a 

LOCA during the period of extended operation. The applicant’s decision to decrease the 

temperature for the analyses from 400 °F to 370 °F provides an extra margin of safety in this 

analysis.
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The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that the 

reflood thermal shock analyses for the LGS Units 1 and 2 RPVs have been projected to the end 

of the period of extended operation.

4.2.7.3 UFSAR Supplement 

LRA Section A.4.2.7 provides the UFSAR supplement summarizing the reflood thermal shock 

analyses TLAA evaluations. The staff reviewed LRA Section A.4.2.7, consistent with the review 

procedures in SRP-LR Section 4.2.3.2, which states 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. 

Based on its review of the UFSAR supplement, the staff finds that the supplement 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 

evaluation of the reflood thermal shock analyses TLAA evaluations, 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 demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that the RPV reflood thermal shock analyses 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).

4.3 Metal Fatigue

4.3.1 ASME Code Section III, Class 1 Fatigue Analysis

4.3.1.1 Summary of Technical Information in the Application

LRA Section 4.3.1.describes the applicant’s TLAA for ASME Code Section III, Class 1 fatigue 

analyses. The LRA states that the RPV and RCPB piping and components were designed in 

accordance with the ASME Code Section III, Class 1 design requirements. In addition, fatigue 

analyses were prepared for these components to determine the effects of cyclic loadings 

resulting from changes in system temperature, pressure, and seismic loading cycles. These 

fatigue analyses evaluated an explicit number and type of transients that were postulated in the 

design specifications to envelope the number of occurrences possible during the 40-year design 

life of the plant. Since these fatigue usage factors are part of the CLB and originally based on 

40-year assumptions, they have been identified as TLAAs requiring evaluation for the period of 

extended operation.

The applicant dispositioned the TLAA for ASME Code Section III, Class 1 fatigue analyses in 

accordance with 10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of fatigue on the 

intended functions of components analyzed in accordance with ASME Code Section III, Class 1 

requirements will be managed by the Fatigue Monitoring program for the period of extended 

operation.
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4.3.1.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the ASME Code, 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, which states that the reviewer should verify that the 

applicant has identified the appropriate program as described and evaluated in the Generic 

Aging Lessons Learned Report (GALL Report) and included an assessment of the TLAA 

information against relevant design basis and CLB information.

The LRA states that ASME Code, Section III, Class 1 fatigue analyses include the stress reports 

for the RPV, RCPB piping and components, including ASME Code, Section III, Class 1 valves, 

which are based on the same 40-year design transients listed in UFSAR Table 3.9-2, “Plant 

Events,” for the RPV and UFSAR Table 5.2-9, “RCPB Operating Thermal Cycles,” for the RCPB 

components. The LRA states each ASME Code, Section III, Class 1 fatigue analysis 

demonstrates that the component has a cumulative usage factor (CUF) value that does not 

exceed the design Code limit of 1.0.

The applicant stated that it used transient cycle monitoring data from the Fatigue Monitoring 

program to develop the 60-year transient projections shown in LRA Table 4.3.1-1 and LRA 

Table 4.3.1-2 for LGS Units 1 and 2, respectively. The staff noted that these tables contain 

cumulative numbers of cycles through January 2011, and the numbers of cycles projected to 

occur over 60 years. Finally, the current design cycle limit for the monitored transients was also 

provided, which is the number of cycles analyzed in the ASME Code, Section III, Class 1 fatigue 

analyses.

LRA Table 4.3.1-1 indicates that the cumulative cycles of “Startup” (Transient No. 3) and 

“Shutdown” (Transient No. 10) is 52 and 50, respectively, for LGS Unit 1. In addition, the table 

indicates that there were 14 occurrences of “Scram – Turbine-Generator Trip, Feedwater Stays 

ON, Isolation Valves Stay OPEN” (Transient No. 9a) and 47 occurrences of “Scram-all other 

Scrams” (Transient No. 9b). 

LRA Table 4.3.1-2 indicates that the cumulative cycles of “Startup” (Transient No. 3) and 

“Shutdown” (Transient No. 10) are 35 and 33, respectively, for LGS Unit 2. In addition, this 

table indicates that there were 14 occurrences of “Scram – Turbine-Generator Trip, Feedwater 

Stays ON, Isolation Valves Stay OPEN” (Transient No. 9a) and 35 occurrences of “Scram-all 

other Scrams” (Transient No. 9b).

It was not clear to the staff why there were more occurrences of the “Startup” transient than the 

“Shutdown” transient for each unit. The staff also noted that, for LGS Unit 1, there are 

61 scrams compared to 50 occurrences of the “Shutdown” transient, and that, for LGS Unit 2, 

there are 39 scrams as compared to 33 occurrences of the “Shutdown” transient. The staff 

noted that the baseline information for these transients is important because the projections are 

used to support the TLAA dispositions in LRA Section 4. By letter dated January 31, 2012, the 

staff issued RAI 4.3-1 requesting the applicant to clarify these discrepancies.

In its response, dated February 29, 2012, the applicant stated there are two reasons for the 

discrepancy between the Startup and Shutdown transients. The first reason is that as of the 

date the data were obtained in January 2011, both units were operating, which accounted for 

one additional startup as compared to shutdowns. The other reason is that each unit 

experienced an Emergency Scram – Single Relief Valve or Safety Valve Blowdown transient 

(Transient No. 14d), which is a more severe transient that transitions the reactor from operating 
4-36

temperature to cold shutdown. The applicant stated that Transient No. 14d, recorded since the 

event, was more severe than a Shutdown transient and no Shutdown transient was required to 

be recorded. The staff finds it reasonable that a Shutdown transient was not recorded because 

the more severe transient that brought the reactor from operating temperature to cold shutdown 

was recorded. Thus, the staff concluded that the listed occurrences of the Startup transient are 

consistent with the listed occurrences of the Shutdown Transients and one occurrence of the 

Emergency Scram transient. 

The applicant stated that the reason for the discrepancy between reported Scram transients and 

Shutdown transients is that these events do not necessarily correlate with each other. Scram 

events transition the plant from power operation to hot standby, which is generally a short period 

during which preparations are made for further transitioning to cold shutdown. The applicant 

explained that if a transition to cold shutdown is performed after a Scram, then one Scram 

transient is recorded and one Shutdown transient is recorded. However, there are occasions 

when the reactor is placed in hot standby with the intention that it will return to normal power 

operation after a short period of time rather than to cold shutdown. The applicant explained that 

one Scram transient is recorded but no Shutdown transient is recorded in such cases where the 

reactor is returned to power operation directly from hot standby. Also, for planned outages, the 

plant may transition from power operations to cold shutdown by manual control rod insertion 

without initiating a scram, in which case, one Shutdown transient is recorded and no Scram 

transient is recorded.

Based on its review, the staff finds the applicant’s response to RAI 4.3-1 acceptable because 

the applicant clarified the discrepancy between the cumulative Startup and Shutdown transients 

and between the cumulative Shutdown and Scram transients. In addition, the staff finds the 

applicant’s response acceptable because the fatigue monitoring results are consistent with the 

actual transients that occurred at the plant, which provide an accurate baseline count for the 

Fatigue Monitoring program to ensure the validity of the metal fatigue TLAAs during the period 

of extended operation. The staff’s concern described in RAI 4.3-1 is resolved.

The staff reviewed UFSAR Table 3.9-1, Section T “General Electric Criteria for NSSS Piping,”

and noted that it indicates that the “Turbine Stop Valve Closure” transient is an upset transient 

with a design of 120 cycles. UFSAR Table 3.9-1, Section T also indicates that the “Relief Valve 

Lift Cycles” transient is an upset transient with a design of 34,200 cycles. Furthermore, UFSAR 

Figure 3A-394 indicates that “Chugging” is a transient used as an input into the fatigue analysis 

of MSRV downcomers with a design of 3,000 cycles.

These transients were not included in LRA Tables 4.3.1-1 and 4.3.1-2; therefore, it was not 

clear to the staff whether these transients have been used as inputs for the TLAAs discussed in 

LRA Section 4. Depending on the disposition of these TLAAs, if these transients were used as 

inputs, the staff noted that the type of information necessary to justify the disposition will differ. 

By letter dated January 31, 2012, the staff issued RAI 4.3-2 requesting the applicant to identify 

the TLAAs that used these transients and confirm these transients were monitored since initial 

plant startup for each unit.

In its response, dated February 29, 2012, the applicant stated that the TLAAs that use these 

transients are the fatigue analyses for the RPV, RPV internals and supports, and ASME 

Code, Section III, Class 1 piping. The fatigue analyses for the RPV and ASME 

Code, Section III, Class 1 piping that are evaluated in LRA Section 4.3.1 are dispositioned in 

accordance with 10 CFR 54.21(c)(1)(iii), crediting the Fatigue Monitoring program. 
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Furthermore, the RPV internals fatigue TLAAs that are evaluated in LRA Section 4.3.4 that are 

also dispositioned in accordance with 10 CFR 54.21(c)(1)(iii), crediting the Fatigue Monitoring 

program, as amended in response to RAI 4.3-10.

The applicant explained that the transient characterized in UFSAR Table 3.9-1 as “Turbine Stop 

Valve Closure,” is an event included within the definition of Transient No. 9a – “Scram, Turbine 

Generator Trip, Feedwater Stays ON, Isolation Valves Stay OPEN,” which has a design limit of 

40 events. The applicant stated that the Fatigue Monitoring program has monitored these 

events since initial plant startup for each unit and limits the number of turbine stop valve closure 

events to 40, and LRA Tables 4.3.1-1 and 4.3.1-2 show that the 60-year projection for Transient 

No. 9a does not exceed the 40-year design limit. Since the “Turbine Stop Valve Closure”

transient is incorporated by definition into Transient No. 9a, the staff finds it appropriate that the 

Fatigue Monitoring program can and will continue to manage Transient No. 9a through the 

period of extended operation.

The applicant stated that UFSAR Table 3.9-1, Section T includes “Relief Valve Lift Cycles” (at 

3 cycles per actuation) - 34,200 cycles, which equates to 11,400 MSRV actuations. However, 

the downcomers and MSRV discharge piping were analyzed for 1,100 MSRV actuations, which 

is more limiting and is the limit being imposed in the Fatigue Monitoring program for MSRV 

actuations. The staff noted that the Fatigue Monitoring program has an existing enhancement 

to monitor additional transients that are significant contributors to fatigue usage. Therefore, the 

staff finds that the MSRVs will not exceed 11,400 actuations, as specified in UFSAR 

Table 3.9-1, Section T for “Relief Valve Lift Cycles” through the period of extended operation, 

because the applicant’s program is monitoring this transient and has a lower cycle limit of 

1,100 MSRV actuations.

The applicant stated that the chugging cycles are loads that result from various modes of steam 

condensation at the downcomer vent ends following a LOCA. The staff noted that as a result of 

RAIs 4.6.8-1 and 4.6.8-2, the applicant amended LRA Tables 4.3.1-1 and 4.3.1-2 to include 

Transient No. 18, Faulted Condition – Pipe Rupture and Blowdown, which corresponds to a 

LOCA. In addition, this transient is monitored by the Fatigue Monitoring program and the 

monitoring results show that a LOCA event has not occurred in either unit. Since both units 

have not experienced a LOCA event, which would result in chugging cycles, the staff finds the 

applicant’s determination that no chugging cycles have occurred to date is reasonable.

Based on its review, the staff finds the applicant’s response to RAI 4.3-2 acceptable because 

the applicant clarified the analyses that assumed the turbine stop valve closure, relief valve lift 

cycles and chugging transients, and the Fatigue Monitoring program, when enhanced, will 

monitor these transients to ensure the fatigue analyses that used these transients will remain 

valid during the period of extended operation. The staff’s concern described in RAI 4.3-2 is 

resolved.

LRA Table 4.3.1-1 indicates that the “Adjusted 60-year Projected Cycles” are two cycles for the 

“Core Spray” and the “Low-Pressure Coolant Injection” transients for LGS Unit 1. In addition, 

LRA Table 4.3.1-2 also provides the same information about these transients for LGS Unit 2. 

The staff noted that the “Design Cycle Limits” for these two transients are not provided in LRA 

Tables 4.3.1-1 and 4.3.1-2 and the applicant did not explain or justify why the design cycle limits 

are not needed. By letter dated January 31, 2012, the staff issued RAI 4.3-3 requesting the 

applicant to identify the TLAAs that used these transients and to confirm that these transients 

were monitored since initial plant startup for each unit.
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In its response, dated February 29, 2012, the applicant stated that LRA Tables 4.3.1-1 and 

4.3.1-2 include a collection of emergency core cooling system/reactor core isolation cooling 

(ECCS/RCIC) and SLC injections that includes cycles for CS and LPCIs and are not thermal 

transients used as inputs in fatigue TLAAs. The applicant indicated that these events are a 

result of the “numbered” thermal transients provided in LRA Tables 4.3.1-1 and 4.3.1-2. The 

ECCS/RCIC injections are monitored separately to ensure that NRC reporting requirements are 

met regarding fatigue usage of RPV nozzles resulting from ECCS and RCIC injections. The 

staff noted from its audit that these transients are associated with Technical Specification 3.5.1, 

“Action,” Subsection f, which states that in the event an ECCS system is actuated and injects 

water into the RCS, a special report shall be prepared and submitted to the NRC. The applicant 

also stated that since the ECCS/RCIC injections are not transient events used as inputs in the 

fatigue analyses, LRA Tables 4.3.1-1 and 4.3.1-2 are revised to remove this information for 

clarity.

Based on its review, the staff finds the applicant’s response to RAI 4.3-3 and the removal of 

these transients from LRA Table 4.3.1-1 and 4.3.1-2 acceptable because these ECCS/RCIC 

and SLC injections transients were not used as inputs to existing fatigue analyses and are only 

a result of monitored thermal transients. In addition, the staff finds it acceptable that these 

ECCS/RCIC and SLC injections transients are not specifically monitored by the Fatigue 

Monitoring program because the applicant is required to keep track of the actuation of ECCS 

(RCIC, HPCI, LPCI, and CS) and injection of water into the RCS per Technical 

Specification 3.5.1, “Action,” Subsection f. The staff’s concern described in RAI 4.3-3 is 

resolved.

In its response to RAI 4.3-10.2, provided by letter dated June 19, 2012, regarding the staff’s 

concern related to reactor vessel internals components, the applicant stated that fatigue 

exemptions (or fatigue waivers) for ASME Code, Section III, Class 1 components are TLAAs 

because the exemptions meet all six TLAA criteria defined in 10 CFR 54.3. The applicant 

stated that Criterion 3 is met because the time-limited assumptions are based upon an 

evaluation of the thermal and pressure transients defined for 40 years in the design 

specifications for ASME Code, Section III, Class 1 components. The applicant revised LRA 

Sections 4.3.1 and 4.3.4 to clarify that all fatigue exemptions have been identified as TLAAs and 

are managed by the Fatigue Monitoring program. The applicant also stated that UFSAR 

supplement Sections A.4.3.1 and A.4.3.4 were revised with conforming changes. The staff’s 

review of the applicant’s respond to RAI 4.3-10.2 is documented in SER Section 4.3.4.2.

LRA Section 4.3.1 also states that the projections show that the current design cycle limits will 

not be exceeded during 60 years of plant operation for LGS Units 1 and 2; therefore, none of 

the transient types are expected to be exceeded during the period of extended operation and 

the ASME Code, Section III, Class 1 fatigue analyses will remain valid for the period of 

extended operation. The staff noted that since the applicant’s assumption relies on the fact that 

the rate of cycle occurrence in the future will not exceed the average rates of occurrence of past 

cycles, the applicant trended each transient projection graphically to determine if recent rates of 

occurrence could be higher than the overall average rates of occurrence. The applicant 

demonstrated, through such trending, that recent transient occurrence rates are bounded by the 

average occurrence rates. However, the staff noted that in order to ensure that this conclusion 

and basis remains valid for transient projections and trending, the Fatigue Monitoring program 

will be used to monitor and track transient cycle occurrences through the end of the period of 

extended operation to ensure that these limits are not exceeded.
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The staff’s review of the Fatigue Monitoring program is documented in SER Section 3.0.3.2.20. 

The staff determined that the program monitors and tracks the number of critical thermal, 

pressure, and seismic transients to assure that the cumulative number of occurrences of each 

transient type is maintained below the number of cycles used in the most limiting ASME 

Code, Section III, Class 1 fatigue analysis. In addition, the program requires comparison of the 

actual event parameters to the applicable design transient definitions to assure the actual 

transients are bounded by the applicable design transients. If a transient approaches an action 

limit, which the applicant has set to 80 percent of the cycle limit, corrective actions are triggered 

for repair, replacement, or reanalysis of the component, in accordance with its Fatigue 

Monitoring program. The staff determined that these characteristics of the Fatigue Monitoring 

program are consistent with GALL Report AMP X.M1. The staff noted that the applicant’s 

method for managing these ASME Code, Section III, Class 1 fatigue analyses is conservative 

because corrective actions are initiated when one transient type approaches 80 percent of the 

cycle limit, when typically a Class 1 fatigue analysis assumes contributions to fatigue usage 

from more than one transient type.

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of fatigue on the intended functions of the 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. Additionally, it meets the acceptance 

criteria in SRP-LR Section 4.3.2.1.1.3 because the applicant is crediting its Fatigue Monitoring 

program, which the staff determined, as documented in SER Section 3.0.3.2.20, is consistent 

with GALL Report AMP X.M1, to manage metal fatigue by monitoring transient occurrences to 

ensure that the assumptions in the ASME Code, Section III, Class 1 fatigue analyses and 

fatigue exemptions, remain valid during the period of extended operation; otherwise, the 

applicant will take corrective actions in accordance with its program.

4.3.1.3 UFSAR Supplement 

LRA Section A.4.3.1, as amended by letter dated June 19, 2012, provides the UFSAR 

supplement summarizing the metal fatigue and fatigue exemptions TLAAs for ASME Code, 

Section III, Class 1 components. The staff reviewed LRA Section A.4.3.1, consistent with the 

review procedures in SRP-LR Section 4.3.3.2, which states 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 TLAAs. 

Based on its review of the UFSAR supplement, the staff finds that the supplement 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 ASME Code, 

Section III, Class 1 metal fatigue and fatigue exemptions TLAAs, 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 provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that effects of fatigue for ASME Code, 

Section III, 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 
4-40

contains an adequate summary description of the evaluated TLAAs, as required by 

10 CFR 54.21(d).

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

Calculations

4.3.2.1 Summary of Technical Information in the Application 

LRA Section 4.3.2 describes the applicant’s TLAA for ASME Code Section III, Class 2 and 3 

and ANSI B31.1 allowable stress calculations. The LRA states that the piping that was 

designed in accordance with ASME Code Section III, Class 2 or 3 design rules or ANSI B31.1 

Piping Code design rules is not required to have an explicit analysis of cumulative fatigue 

usage, but cyclic loading is considered in a simplified manner in the design process. The LRA 

further states that these codes first require prediction of the overall number of thermal and 

pressure cycles expected during the 40-year lifetime of these components; then a stress range 

reduction factor is determined for the number of cycles. The LRA states that these are 

considered to be implicit fatigue analyses since they are based upon cycles anticipated for the 

life of the component. The applicant evaluated this TLAA for those for the ASME 

Code Section III, Class 2 and 3 and ANSI B31.1 systems connected to ASME Code Section III, 

Class piping, and are affected by the same operational transients and for the remaining systems 

that are affected by different thermal and pressure cycles.

The applicant dispositioned the metal fatigue TLAA for ASME Code Section III, Class 2 and 3 

and ANSI B31.1 allowable stress calculations in accordance with 10 CFR 54.21(c)(1)(i) to 

demonstrate that the analysis remains valid during the period of extended operation.

4.3.2.2 Staff Evaluation

The staff reviewed the applicant’s metal fatigue TLAA for the ASME Code Section III, Class 2 

and 3, and ANSI B31.1 allowable stress calculations 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, 

which states that relevant information in the TLAA, operating plant transient history, design 

basis, and CLB is reviewed to verify 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.

LRA Section 4.3.2 states that for the ASME Code Section III, Class 2 and 3, and ANSI B31.1 

systems that are connected to ASME Code Section III, Class 1 piping, and are affected by the 

same operational transients, the 60-year cycle projections demonstrate that the total number of 

thermal and pressure cycles of all of the transient types added together will not exceed 

7,000 cycles during the period of extended operation. Therefore, the stress range reduction 

factor will not change and the TLAAs will remain valid for the period of extended operation. The 

applicant stated this includes the applicable portions of the following systems: Residual Heat 

Removal (RHR), CS, Reactor Core Isolation Cooling (RCIC), High-Pressure Coolant Injection

(HPCI), Reactor Water Cleanup, Control Rod Drive (CRD), Main Steam, Main Turbine, 

Extraction Steam, Feedwater, Condenser and Air Removal, and Radwaste. 

The applicant also stated in LRA Section 4.3.2, that for the remaining systems affected by 

different thermal and pressure cycles, an operational review was performed that also concluded 
4-41

that the total number of cycles, projected for 60 years, will not exceed 7,000 cycles for the fire 

protection, EDG, and auxiliary steam systems. Systems with operating temperatures below 

specified thresholds were determined to have low numbers of equivalent full temperature cycles 

since the fluid temperature changes are small. Therefore, since the stress range reduction 

factors originally selected for the components in all of these systems remain applicable, the 

applicant determined that the TLAAs remain valid for the period of extended operation.

The staff noted that LRA Section 4.3.2 did not provide information regarding the accumulated 

number of occurrences and the 60-year projected number of occurrences for the 

aforementioned remaining systems that are affected by different thermal and pressure cycles. 

Therefore, the staff could not verify the adequacy of the disposition in accordance with 

10 CFR 54.21(c)(1)(i). Furthermore, UFSAR Section A.4.3.2 indicates that the TLAA will be 

adequately managed for the period of extended operation by the Fatigue Monitoring program in 

accordance with 10 CFR 54.21(c)(1)(iii), which is different from the disposition identified in LRA 

Section 4.3.2. By letter dated January 31, 2012, the staff issued RAI 4.3-4 requesting the 

applicant to identify the “different thermal and pressure cycles” referenced in the LRA and to 

identify the accumulated number of occurrences for each transient. In addition, the staff 

requested that the applicant clarify the discrepancy in the disposition for the TLAA.

In its response dated February 29, 2012, the applicant stated the ASME Code, Section III, 

Class 2 and 3, and ANSI B31.1 piping systems not connected to Class 1 piping that were 

evaluated include the following:

 • The diesel engine exhaust piping from the diesel-driven fire pump and backup diesel-driven 

fire pump in the fire protection system. The engine exhaust piping from the diesel-driven fire 

pumps experiences a thermal cycle each time the engine starts and is later shutdown.

 • The EDGs exhaust piping in the emergency diesel generator system. The diesel generator 

engine exhaust piping experiences a thermal cycle each time the engine starts and is later 

shutdown.

 • The piping from the auxiliary boilers used for plant heating steam in the auxiliary steam 

system. The portions of the plant heating steam piping within the scope of license renewal 

experience a thermal cycle each time the plant heating steam system is placed in service 

and is later shutdown.

The staff noted that each of these systems have 60-year cycle projections based on estimated 

operational cycles rather than actual counts for the number of cycles. The staff’s evaluation of 

each of the 60-year cycle projections based on estimated operational cycles is discussed below.

The applicant explained that the diesel-driven fire pump and backup diesel-driven fire pump is 

common for both units and these engine runs were not monitored since initial plant startup, but 

the number of cycles has been estimated based on operational history. The diesel-driven fire 

pump engine is normally not in service and the engine is only operated during surveillance 

testing and in response to a fire when the motor-driven pump does not maintain fire water 

header pressure. 

In addition, the backup diesel-driven fire pump engine is normally not in service and the engine 

is only operated during surveillance testing and in response to a fire when both the motor driven 

pump and diesel-driven pump do not maintain fire water header pressure. The applicant 

estimated that these engines run no more than two times per year to maintain fire water header 
4-42

pressure. The applicant also stated that it operated an average of 13 times per year during 

surveillance testing. Based on an average of 15 cycles per year, the applicant determined that 

the diesel-driven fire pump exhaust piping will experience approximately 975 thermal cycles 

through the period of extended operation for LGS Unit 2 (65 years total). The staff noted that 

there are less than 65 years between the Operating License of Unit 1, granted in August 1985 

and the end of the period of extended operation of Unit 2, in June 2049. The staff noted that the 

estimate of 975 thermal-cycles is reasonable for LGS because the pump is common for both 

units and the estimate covered the total time span of 65 years of the operations of both units. 

The staff finds the applicant’s estimated number of cycles for the diesel-driven fire pump and 

backup diesel-driven fire pump to be reasonable because it is based on routine usage to 

maintain header pressure or scheduled testing throughout a year. In any event, the number of 

expected cycles through the period of extended operation for both units is expected to be no 

more than 14 percent of the 7,000 allowable cycles; therefore, there is a significant margin to 

account for unanticipated cycles for the diesel-driven fire pump and backup diesel-driven fire 

pump.

The applicant explained that the EDG engine runs have not been monitored since initial plant 

startup, but the number of cycles has been estimated based on operational history. The 

engines are normally not in service, but they are operated in response to a LOCA or a loss of 

offsite power. Since these events occur very infrequently, the applicant estimated that each 

EDG is run no more than once per year in response to these events. In addition, a review of 

surveillance test frequencies determined that each EDG is run an estimated 22 times per year 

for testing. The applicant’s review of the system manager’s informal log of actual EDG runs 

revealed that the average number of runs per EDG in 2010 and 2011 was 19 per year, thus, 

confirming that 22 cycles per year is a conservative estimate for annual EDG surveillance test 

runs. Based on an average of 23 cycles per year, the applicant determined that each EDG will 

experience approximately 1,380 thermal cycles though 60 years of operation. The staff finds 

the applicant’s estimated number of cycles for the EDG runs to be reasonable because it is 

based on a conservative estimate of annual routine surveillance test runs and unanticipated 

response to a LOCA or a loss of offsite power, which are infrequent events. In any event, the 

number of expected cycles through the period of extended operation is expected to be no more 

than 20 percent of the 7,000 allowable cycles; therefore, the staff finds that there is a significant 

margin to account for unanticipated cycles for the EDGs.

The applicant explained that the auxiliary steam system is common for both units and the 

thermal cycles have not been monitored since initial plant startup, but the number of cycles has 

been estimated based on operational history. The auxiliary steam system is typically in service 

for the entire heating system from fall until spring each year; however, the system may be 

removed from service during each heating season to perform maintenance or during periods of 

warm weather when the plant heating system is not needed. The applicant stated that based on 

an estimated average of 5 cycles per year, the auxiliary steam system piping will experience 

approximately 325 thermal cycles through the period of extended operation for LGS Unit 2 

(65 years total). The staff noted that the estimate of 325 thermal-cycles is reasonable for LGS 

because the system is common for both units and the estimate covered the total time span of 65 

years of the operations of both units. The staff finds the applicant’s estimated number of cycles 

for the auxiliary steam system to be reasonable because it is based on routine cycling 

throughout a year. In any event, the number of expected cycles through the period of extended 

operation for both units is expected to be no more than 5 percent of the 7,000 allowable cycles; 

therefore, there is a significant amount of margin to account for unanticipated cycles for the 

auxiliary steam system piping.
4-43

The applicant clarified that the fatigue TLAAs for the ASME Code Section III, Class 2 and 3, and 

ANSI B31.1 piping systems not connected to Class 1 piping systems have been demonstrated 

to remain valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i). 

The staff noted that this is a separate disposition from the one for the ASME Code Section III, 

Class 2 and 3, and ANSI B31.1 connected to the Class 1 piping, which are managed by the 

Fatigue Monitoring program in accordance with 10 CFR 54.21(c)(1)(iii). LRA Section 4.3.2 and 

UFSAR supplement Section A.4.3.2 are revised to include two TLAA dispositions; one for the 

ASME Code, Section III, Class 2 and 3, and ANSI B31.1 piping systems connected to Class 1 

piping, and another one for ASME Code, Section III, Class 2 and 3, and B31.1 piping systems 

that are not connected to Class 1 piping.

Based on its review, the staff finds the applicant’s response to RAI 4.3-4 acceptable because 

the applicant explained the “different thermal and pressure cycles” associated with ASME Code, 

Section III, Class 2 and 3, and ANSI B31.1 piping systems that are not connected to ASME 

Code, Section III, Class 1 piping and the applicant justified that the cycles for these systems will 

not exceed the 7,000 allowable cycles through the period of extended operation, as described 

above. The staff’s review of the applicant’s disposition for the TLAAs associated with ASME 

Code, Section III, Class 2 and 3, and ANSI B31.1 piping systems are discussed below. The 

staff’s concern described in RAI 4.3-4 is resolved.

The staff reviewed LRA Section 4.3.2.2, as amended by letter dated February 29, 2012, the 

response to RAI 4.3-4, and the TLAA for ASME Code, Section III, Class 2 and 3, and ANSI 

B31.1 piping systems that are connected to ASME Code, Section III, Class 1 piping to verify that 

in accordance with 10 CFR 54.21(c)(1)(iii), the effects of fatigue will be adequately managed for 

the period of extended operation.

Since the ASME Code, Section III, Class 2 and 3, and ANSI B31.1 piping systems are 

connected to ASME Code, Section III, Class 1 piping, the staff finds it reasonable to conclude 

that the same operational transients analyzed for the ASME Code, Section III, Class 1 piping 

systems similarly affect the connected ASME Code, Section III, Class 2 and 3, and B31.1 

portions of the piping systems. The staff noted that the Fatigue Monitoring program monitors 

and tracks the number of critical thermal, pressure, and seismic transients listed in LRA 

Table 4.3.1-1 (LGS Unit 1) and LRA Table 4.3.1-2 (LGS Unit 2). In addition, the program 

requires comparison of the actual event parameters (pressure, temperature, or flow rate 

changes) to the applicable design transient definitions to assure the actual transients are 

bounded by the applicable design transients. The staff noted that the applicant’s program 

ensures that the 7,000 limit on the number of full temperature cycles will not be exceeded 

through the period of extended operation without the applicant taking corrective actions.

The staff finds the applicant has demonstrated in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of fatigue on the intended functions of the ASME Code, Section III, Class 2 and 3,

and ANSI B31.1 piping systems connected to ASME Code, Section III, Class 1 piping will be 

adequately managed for the period of extended operation. Additionally, it meets the acceptance 

criteria in SRP–LR Section 4.3.2.1.2.3 because the Fatigue Monitoring program tracks the 

number of design basis transients that will occur through the period of extended operation and 

includes action limits and corrective actions that will ensure that the assumptions made in these 

ASME Code, Section III, Class 2 and 3, and ANSI B31.1 fatigue analyses for systems 

connected to ASME Code, Section III, Class 1 piping will not be exceeded during the period of 

extended operation.
4-44

The staff reviewed LRA Section 4.3.2.2, as amended by letter dated February 29, 2012, and the 

TLAA for ASME Code, Section III, Class 2 and 3, and ANSI B31.1 piping systems that are not 

connected to Class 1 piping to verify in accordance with 10 CFR 54.21(c)(1)(i), that the analysis 

remains valid during the period of extended operation.

As discussed above in the staff’s review of the applicant’s response to RAI 4.3-4, the staff 

determined the following: for the fire protection system, the number of expected cycles through 

the period of extended operation for both units is expected to be no more than 14 percent of the 

7,000 allowable cycles, which leaves significant margin to account for unanticipated cycles for 

the diesel-driven fire pump and backup diesel-driven fire pump; for the EDG system the number 

of expected cycles through the period of extended operation is expected to be no more than 

20 percent of the 7,000 allowable cycles, which leaves significant margin to account for

unanticipated cycles for the EDGs; and for the auxiliary steam system piping the number of 

expected cycles through the period of extended operation for both units is expected to be no 

more than 5 percent of the 7,000 allowable cycles, which leaves significant margin to account 

for unanticipated cycling of the system.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the 

TLAAs of ASME Code, Section III, Class 2 and 3, and ANSI B31.1 piping systems that are not 

connected to Class 1 piping, remain valid for the period of extended operation. Additionally, the 

applicant meets the acceptance criteria in SRP-LR Section 4.3.2.1.2.1 because the projected 

total number of full thermal range transients over the period of extended operation for ANSI 

B31.1 and ASME Code, Section III, Class 2 and 3, piping does not exceed the 7,000-cycle limit, 

with significant margin to account for unanticipated cycling of the systems.

4.3.2.3 UFSAR Supplement 

LRA Section A.4.3.2, as amended by letter dated February 29, 2012, provides the UFSAR 

supplement summarizing the TLAA for ASME Code Section III, Class 2 and 3, and ANSI B31.1 

allowable stress calculations. The staff reviewed LRA Section A.4.3.2, consistent with the 

review procedures in SRP-LR Section 4.3.3.2, which states 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. 

Based on its review of the UFSAR supplement, the staff finds that the supplement 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 of 

ASME Code Section III, Class 2 and 3, and ANSI B31.1 allowable stress calculations, 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 provided an acceptable 

demonstration, as required by 10 CFR 54.21(c)(1)(i), that the fatigue analyses of ASME Code, 

Section III, Class 2 and 3, and ANSI B31.1 piping systems connected to Class 1 piping remain 

valid for the period of extended operation. The staff also concludes that the applicant provided 

an acceptable demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of 

fatigue for ASME Code, Section III, Class 2 and 3, and ANSI B31.1 piping systems connected to 

Class 1 piping will be adequately managed by the Fatigue Monitoring program for the period of 
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extended operation. The staff also concludes that the UFSAR supplement contains an 

adequate summary description of the evaluated TLAAs, 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 in the Application 

LRA Section 4.3.3.describes the applicant’s analyses to address EAF for the RPV and ASME 

Code Class 1 piping. The applicant stated that environmental fatigue calculations were 

performed for each component location listed in NUREG/CR-6260 for the newer-vintage BWR. 

In order to ensure that any other locations that may not be bounded by the NUREG/CR-6260 

locations were evaluated, environmental fatigue calculations were performed for each RPV 

component location that has a reported CUF value in the stress report and for each ASME Code 

Class 1 RCPB piping system in each unit. These calculations were performed for the limiting 

location for each material within the component or system that is in contact with reactor coolant. 

LRA Table 4.3.3-1 shows the results from the environmental fatigue calculations for the RPV 

components and LRA Table 4.3.3-2 shows the results for the ASME Code, Section III, Class 1

RCPB systems. 

The applicant dispositioned the EAF analyses for the RPV and ASME Code, Section III, Class 1 

RCPB piping in accordance with 10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of EAF 

on the intended functions of the analyzed components will be managed by the Fatigue 

Monitoring program for the period of extended operation.

4.3.3.2 Staff Evaluation

The staff noted that the applicant addressed the effects of EAF, consistent with the guidance in 

the SRP-LR and the staff’s recommendations for resolving Generic Safety Issue No. 190 

(GSI-190), dated December 26, 1999. The staff also noted that, consistent with Commission 

Order No. CLI-10-17, dated July 8, 2010, the evaluations associated with EAF do not fall within 

the definition of TLAA in 10 CFR 54.3(a) because these evaluations are not in the CLBs of LGS 

Units 1 and 2. Nevertheless, the applicant has credited its Fatigue Monitoring program to 

manage the effects of EAF; therefore, the staff reviewed LRA Section 4.3.3 and the evaluations 

for EAF to verify, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of EAF will be 

adequately managed for the period of extended operation.

The staff reviewed the applicant’s EAF analyses for the RPV and ASME Code, Section III, 

Class 1 RCPB piping and the corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent 

with the review procedures in SRP-LR Section 4.3.3.1.3, which provides guidance for the 

reviewer to verify that the applicant has addressed EAF as part of an AMP formulated in support 

of license renewal. In addition, the SRP-LR provides guidance for verifying that the critical 

components evaluated for EAF include a sample of high-fatigue usage locations and have 

applied environmental fatigue life correction factor (Fen) values, which are calculated with the 

recommended sets of formulae in NUREG/CR-5704, NUREG/CR-6583, and NUREG/CR-6909.

LRA Table 4.3.3-1 provides the following information for the in-core housing penetration: the 

ASME Code based 60-year CUF is 0.108; the NUREG/CR-6909 based 60-year CUF is 0.140; 

and the 60-year CUFen is 0.83. During its audit, the staff noted that the applicant’s basis 

documents contained different CUF and CUFen values than the values in LRA Table 4.3.3-1. By 

letter dated January 31, 2012, the staff issued RAI 4.3-5 requesting the applicant to clarify the 
4-46

discrepancy between the values presented in LRA Table 4.3.3-1 and its basis documents and to 

confirm that the remaining values in LRA Table 4.3.3-1 are accurate.

In its response dated February 29, 2012, the applicant revised LRA Table 4.3.3-1 with the 

following corrected values for in-core housing penetration for both units: the correct node 

location is 152, the ASME Code CUF is 0.181, the NUREG/CR-6909 CUF is 0.240, the Fen

value is 2.42, and the CUFen is 0.581. The applicant stated that the results from a revised 

environmental fatigue analysis for the CS nozzle forging in each unit is included in the revised 

LRA Table 4.3.3-1 and that additional information associated with this revision is in its response 

to RAI 4.3-9. The staff’s review of the applicant’s response to RAI 4.3-9 is documented

elsewhere in this SER section. The applicant confirmed that the remaining values in

Table 4.3.3-1 are accurate.

The staff finds the applicant’s response to RAI 4.3-5 acceptable because LRA Table 4.3.3-1 

was revised to accurately represent the information from the applicant’s basis documents and 

calculations. The staff’s concern described in RAI 4.3-5 is resolved.

In the applicant’s submittal dated March 25, 2010, “Request for License Amendment Regarding 

Measurement Uncertainty Recapture Power Uprate,” the applicant provided NEDO-33484, 

Revision 0, “Safety Analysis Report for Limerick Generating Station Units 1 & 2 Thermal Power 

Optimization.” Table 3-7 of this report provides 40-year CUF values for the CS nozzle, LPCI 

nozzle, and RPV support skirt and feedwater nozzles. The staff noted that the ASME 

Code CUF values in LRA Table 4.3.3-1 for these components are different from those in 

Table 3-7 of NEDO-33484, Revision 0. The LRA did not explain why these values are different 

in the two documents. By letter dated January 31, 2012, the staff issued RAI 4.3-9 requesting 

the applicant to reconcile and justify the differences in the CUF values.

In its response dated February 29, 2012, the applicant provided an explanation for the 

difference in CUF values between the two documents for the CS nozzle, LPCI nozzle, and RPV

support skirt and feedwater nozzles. The staff’s review of each explanation is documented 

below.

For the LPCI nickel alloy nozzle safe end, the applicant stated that the CUF value of 0.79 shown 

in Table 3-7 of NEDO-33484, was based on the associated power-uprate evaluation. The 

ASME Code CUF value of 0.504 shown in LRA Table 4.3.3-1 is the revised CUF value from the 

environmental fatigue analysis that was further refined from the power-uprate analysis with the 

ASME Code fatigue curve. The NUREG/CR-6909 CUF value of 0.420 and Fen value of 1.94 

were determined using the fatigue curve and Fen formula, respectively, in NUREG/CR-6909. 

The staff noted that the applicant’s use of the formulas and fatigue curves for nickel alloy 

components from NUREG/CR-6909 is consistent with the recommendation of GALL Report 

AMP X.M1.

For the feedwater nozzles, the applicant stated that the environmental fatigue analysis includes 

a new ASME Code Section III, NB-3200, fatigue analysis that includes an updated loads 

analysis that reduces the number of feedwater injections assumed during shutdown events from 

five cycles to one cycle. The applicant explained that this update more closely reflects the 

plant’s actual feedwater system design; therefore, the new CUF value determined in the 

environmental fatigue analysis is lower than the value in the original design report as stated in 

UFSAR Table 3.6-8. The staff finds that the applicant’s update for feedwater injections and 
4-47

associated refined calculation reasonable because it represents a more realistic CUF for 

60 years of operation that is based on the actual plant operating practices at LGS Units 1 and 2.

The applicant stated that the location reported in LRA Table 4.3.3-1 for the support skirt (RPV 

shell ID location adjoining skirt) is for a wetted surface inside the vessel shell at the location 

where the support skirt attaches to the vessel. The applicant explained that the highest fatigue 

location documented in the NEDO-33484 report was at the bottom of the skirt that rests on the 

concrete, which is not in contact with reactor coolant. The staff noted that the applicant 

appropriately considered the corresponding inside surface location within the RPV for EAF 

when the analyzed outside support skirt location is not in contact with reactor coolant. 

The applicant stated that the CUF value reported in the LRA for the CS nozzle forging was 

based upon the original RPV stress report and did not address changes to the nozzle forging 

CUF value provided in subsequent reanalyses. The applicant also stated that the 

environmental fatigue analysis has been revised to address the changes introduced in the later 

reanalyses, including new loads, however, since the previously analyzed location is on the 

outside surface of the nozzle forging that does not contact reactor coolant, the revised 

environmental fatigue analysis evaluated the inside surface location at the clad-to-base metal 

interface directly below the limiting outside surface location. The applicant stated that this 

location was selected to represent the wetted internal surface of the forging but takes no credit 

for the presence of the cladding. The staff noted that the applicant’s February 29, 2012,

response to RAI 4.3-5 revised the ASME Code CUF value for CS nozzle (forging) from 0.097 to 

0.0016 in LRA Table 4.3.3-1. However, when considering the applicant’s response that this 

location was not originally analyzed for fatigue, it was not clear to the staff what the value 

of 0.0016 represents. The staff also noted that for the CS piping in LRA Table 4.3.3-2, the 

difference in Fen values between LGS Units 1 and 2 is substantial, but the applicant did not 

provide the basis for the large difference. By letter dated April 17, 2012, the staff issued 

followup RAI 4.3-9.1 requesting the applicant to provide the basis for the ASME Code CUF 

value of 0.0016 for the CS nozzle (forging) in LRA Table 4.3.3-1 and to justify why the difference 

in Fen values for the CS piping between LGS Units 1 and 2. 

In its response dated May 4, 2012, the applicant stated that the original RPV stress report 

evaluated the CS nozzle forging with a CUF value of 0.097 for node 22, located on the external 

surface of the nozzle. This report did not report a CUF value for node 17, located on the inside 

surface of the nozzle. However, it did report that the number of allowable cycles for node 17 is 

300,000 cycles, based on the ASME Code fatigue curve. The report also showed that the total 

number of design cycles for this location is 485 cycles. During development of the 

environmental fatigue analysis for node 17, the original ASME CUF value was determined to be 

485 ÷ 300,000 = 0.0016. The staff finds this explanation of the CUF value acceptable because 

the cumulative usage factor is equal to the design number of cycles divided by the allowable 

cycles; thus the CUF value of 0.0016 is appropriate for node 17 of the CS nozzle forging. 

In addition, the applicant stated that the Fen values for the LGS Unit 1 and LGS Unit 2 CS piping 

were each computed consistent with the NUREG/CR-6909 methodology. An individual Fen 

value was computed for each transient pairing within each analysis and the NUREG/CR-6909 

Fen value reported in LRA Table 4.3.3-2 is a weighted average value determined by dividing the 

CUFen value for the analysis by the NUREG/CR-6909 CUF value. The applicant further stated 

that the individual Fen values computed for LGS Unit 1 assume the worst-case value for strain 

rate of 0.0004 percent/second provided in NUREG/CR-6909, which the staff finds to be 

conservative, with a resulting average “6909 Fen” value of 4.36 and CUFen value of 0.856. 
4-48

However, in the LGS Unit 2 analysis, the Fen value uses a computed strain rate value of 

0.0484 percent/second, which is appropriate since this transient pair is associated with safety 

relief valve and operational basis earthquake (OBE) cycles; the average 6909 Fen value is 2.89 

and the CUFen value is 0.786. For LGS Unit 2, the staff finds this method to be appropriate 

because the applicant used the actual conditions to compute the strain rate value, rather than 

using the worst-case scenario outlined in NUREG/CR-6909.

The staff finds the applicant’s responses to RAI 4.3-9 and 4.3-9.1 acceptable because the 

applicant justified the differences of the CUF values between LRA Table 4.3.3-1 and Table 3-7 

of NEDO-33484, Revision 0, which the staff evaluated individually above, and reconciled the 

differences in CUF values for the CS nozzle (forging) and Fen values for the CS piping between 

Units 1 and 2. The staff concerns identified in RAI 4.3-9 and followup RAI 4.3-9.1 are resolved.

LRA Table 4.3.3-2 states that the CUF values of 0.3505 and 0.1056 for the reactor recirculation 

piping were calculated using the fatigue design curve in NUREG/CR-6909 for LGS Units 1 

and 2, respectively. In addition, it states that the CUF values of 0.0211 and 0.0798 for the MSIV 

drains were calculated using the fatigue design curve in ASME Code, Section III for LGS Units 1 

and 2, respectively. The staff noted that there is a difference of approximately a factor of three 

between the CUF values reported for these components between the two units; however, the 

LRA did not explain the reason for the large difference. In addition, it is not clear to the staff 

why the nodal locations are different between the two units for CS piping, MSIV drains, MSIV 

drain and test, RCIC steam supply, head vent, and safeguard piping fill systems. 

By letter dated January 31, 2012, the staff issued RAI 4.3-7 requesting the applicant to explain 

and justify the difference in reported CUF values for the reactor recirculation piping and MSIV 

drains between the two units. In addition, for each component in LRA Table 4.3.3-2 that 

indicated different nodal locations between the two units, the staff requested the applicant to 

describe the configuration and justify the difference between the two units.

In its response dated February 29, 2012, the applicant stated that the differences between the 

CUF values reported for LGS Units 1 and 2 piping systems are caused by differences in piping 

configuration or other inputs to stress analyses. The applicant explained that the main reason 

for the difference in CUF values reported for the reactor recirculation piping is that different Sm

(allowable stress) values were used in the original stress reports for the two units. The 

difference in Sm values between the two units leads to a difference in the elastic-plastic 

correction factor (Ke), which results in a higher alternating stress and higher CUF value for the 

LGS Unit 1 analysis. In addition, the applicant stated that the LGS Unit 2 fatigue analysis was 

revised to account for increased piping loads associated with a locked snubber condition on the 

recirculation piping line, which did not apply to LGS Unit 1. This condition also contributed to 

the difference in CUF values between the two units. The staff finds it reasonable that different 

Sm values and Ke factors in the two units and the operating experience in LGS Unit 2 reactor 

recirculation piping associated with the locked snubber would result in the large difference in 

CUF values between the two units.

The applicant also explained that the difference in nodal locations for the aforementioned 

systems between the two units and the staff’s review of each of these nodal location differences 

is individually documented below.

The applicant stated that the difference in CUF values reported for the MSIV drain piping is 

caused by a difference in the piping support configuration downstream of the outboard isolation 
4-49

valves. On LGS Unit 1, the limiting nodes 41 and 261 are inside containment on the inboard of 

the MSIV drains header, and on LGS Unit 2, the limiting node 145 is outside containment 

immediately upstream of the HV-041-2F016 valve. In addition, the piping immediately 

downstream of the HV-041-1F016 valve on LGS Unit 1 includes a vertical restraint that is not 

present on LGS Unit 2. These differences between the two units resulted in a calculated CUF 

value of 0.0211 for nodes 41 and 261 on LGS Unit 1 and a computed CUF value of 0.0798 at 

node 145 on LGS Unit 2. The staff finds it reasonable that a different piping support 

configuration between the two units results in different applied forces, moments, and stresses, 

which equates to a different calculated CUF value.

For the CS system, the applicant stated that LGS Unit 1 had a locked snubber condition on one 

of the CS piping lines for a period of time before it was discovered and repaired; which resulted 

in a revision of the fatigue analysis. This condition resulted in an increased fatigue usage and a 

change in the limiting node in LGS Unit 1 when compared to LGS Unit 2. The staff finds it 

reasonable that the operating experience in LGS Unit 1 associated with the locked snubber 

would result in different calculated CUF values and limiting nodes between the two units.

For the MSIV drain and test piping (MSIV leakage control system), the applicant described the 

configuration for node 265 and node 517 for LGS Units 1 and 2, respectively. In addition, the 

applicant explained that node 265 was located on the 1-inch DBA-111 piping connected to 

‘D’ Main steam line that was removed from the system by a modification. The applicant stated 

that the piping configuration for the MSIV leakage control system was substantially different 

between LGS Units 1 and 2 before and after the modifications, resulting in the different node 

locations and CUF values. The staff finds it reasonable that the design differences in piping 

configuration for the MSIV leakage control system and the modification to the LGS Unit 1

system would result in different calculated CUF values and limiting nodes between the two 

units.

For the RCIC steam supply piping, the applicant stated the stress analyses performed for power 

rerate in 1993 for LGS Unit 2, and in 1994 for LGS Unit 1, determined the different bounding 

locations and CUF values. The staff approved the LGS Unit 2 rerate by letter dated 

February 16, 1995, and the LGS Unit 1 rerate by letter dated January 24, 1996. The staff’s SE 

determined that the applicant’s submittal shows that the design of piping, components, and their 

supports is adequate to maintain the structural and pressure boundary integrity of the reactor 

coolant piping and supports in the power uprate conditions, and is, therefore, acceptable. The 

staff finds it reasonable that the difference in piping support configuration between the LGS 

Unit 1 and LGS Unit 2, RCIC steam supply system would result in different bounding nodal 

locations and calculated CUF values.

For the head vent piping, the applicant stated that the current CUF values for LGS Unit 1

(node 28 – 0.0891) and LGS Unit 2 (node 292 – 0.5044) are obtained from the ASME Code, 

Section lll, Class 1 Stress Analysis Reports. For the safeguard piping fill systems, the applicant 

stated that the current CUF values for LGS Unit 1 (node 276 – 0.0047) and LGS Unit 2

(node 890 – 0.0021) are also obtained from the ASME Code, Section lll, Class 1 Stress Analysis 

Reports. The applicant determined for both systems the causes of the difference in bounding 

values and locations are that the piping support configurations are different between the units. 

The staff finds this reasonable because a different piping support configuration between the two 

units would result in different applied forces, moments, and stresses, which equates to a 

different calculated CUF value.
4-50

The staff finds the applicant’s response to RAI 4.3-7 acceptable because the applicant justified, 

as discussed above, the large differences in reported CUF values for the reactor recirculation 

piping and MSIV drains between LGS Units 1 and 2. In addition, the applicant justified, as 

described above, the differences in bounding nodal locations and CUF values for the CS piping, 

MSIV drains, MSIV drain and test, RCIC steam supply, head vent, and safeguard piping fill 

systems. The staff’s concern described in RAI 4.3-7 is resolved. 

LRA Section 4.3.3 states that to ensure that any other locations that may not be bounded by the 

NUREG/CR-6260 locations were evaluated, environmental fatigue calculations were performed 

for each RPV component location that has a reported CUF value in the stress report and for 

each ASME Code, Section III, Class 1 RCPB piping system in each unit. UFSAR Table 3A-27 

identifies fatigue usage factors for components in the MSRV discharge lines in the wetwell air 

space. UFSAR Table 3.6-12 identifies cumulative usage factors for different locations of the 

reactor vessel drain piping. Table 3-7 of NEDO-33484, Revision 0, provides 40-year CUF 

values for the core differential-pressure and liquid control nozzle, closure bolts, and stabilizer 

bracket. The staff noted that LRA Table 4.3.3-1 and 4.3.3-2 did not identify any components in 

the MSRV discharge lines, reactor vessel drain piping, core differential-pressure and liquid 

control nozzle, closure bolts, and stabilizer bracket for the effects of reactor coolant 

environment. Therefore, it is not clear to the staff whether these component locations were 

considered when evaluating EAF.

By letter dated January 31, 2012, the staff issued RAI 4.3-8 requesting the applicant to justify 

why EAF does not need to be considered for the aforementioned components. In addition, the 

applicant was requested to identify and provide justifications for other RPV components and 

ASME Code, Section III, Class 1 RCPB piping systems that had reported CUF values but have 

not considered EAF.

In its response dated February 29, 2012, the applicant explained why an evaluation was or was 

not performed for the MSRV discharge lines, reactor vessel drain piping, core 

differential-pressure and liquid control nozzle, closure bolts, and stabilizer bracket. The staff’s 

review of each explanation is documented below.

For the MSRV discharge lines, the applicant stated that these lines do not require evaluation for 

EAF because they are ASME Code, Section III, Class 3 components that are not within the 

RCPB and do not contact reactor coolant. Similarly, the applicant stated that the RPV closure 

bolts are located within the containment air space outboard of the RPV main flange seals and 

are not in contact with reactor coolant. The staff finds it acceptable that MSRV discharge lines 

and RPV closure bolts were not evaluated for the environmental fatigue because, consistent 

with GALL Report AMP X.M1, those components that are not part of the RCPB or not exposed 

to a reactor water environment and would not be included in the sample set of components that 

consider EAF. 

For the reactor vessel drain piping, the applicant explained that this piping is included within the 

ASME Code, Class 1 stress report for the reactor water cleanup system and therefore, this 

piping was included within the environmental fatigue analysis for the reactor water cleanup 

system. The staff reviewed UFSAR Section 3.6.1.2.1.6 and confirmed that the reactor vessel 

drain piping is connected to the RWCU suction line in the drywell. Since the applicant 

considered the EAF for the reactor vessel drain piping as part of the reactor water cleanup 

system, the staff finds this acceptable.
4-51

For the core differential pressure and liquid control nozzle, the applicant stated that this 

component was analyzed for EAF; however, the EAF analysis determined that the alternating 

stress value is below the endurance limit for the material, resulting in a CUF value of 0.000 and 

CUFen value of 0.000. The staff noted that if the alternating stress value is below the endurance 

limit for the material, there is no contribution of fatigue usage to the CUF value from transients 

that affect the component. Thus, the staff noted that the resulting CUF value and CUFen value is 

zero and finds it reasonable that the applicant addressed EAF for the core differential pressure 

and liquid control nozzle.

For the RPV stabilizer bracket, the applicant stated that EAF was evaluated, as shown in LRA 

Table 4.3.3-1 for the “RPV Shell at Stabilizer Bracket.” It was explained that the stabilizer 

bracket is welded to the outside surface of the RPV shell and the RPV stress report includes a 

fatigue analysis of the stabilizer bracket along with a segment of the RPV shell where the 

bracket is attached. The analysis provides a CUF value for a location on the inside surface of 

the RPV shell, which contacts reactor coolant, which was evaluated for EAF. Consistent with 

the recommendations of GALL Report AMP X.M1, the staff finds it acceptable that the applicant 

addressed EAF for the RPV stabilizer bracket location on the inside surface of the RPV shell 

since it is in contact with reactor coolant.

The applicant stated that components that are not in contact with reactor coolant are not 

required to be evaluated for EAF. In addition, piping systems with a dry steam internal 

environment were evaluated and shown to have a Fen value of 1.0 just to demonstrate that all 

ASME Code, Class 1, piping systems were evaluated. The staff finds it acceptable that the 

applicant applied a Fen value of 1.0 for components exposed to dry steam internal environment 

because EAF, as discussed in the GALL Report, is applicable to those components exposed to 

a reactor coolant environment. Additional information regarding this area of effects from a dry 

steam internal environment is documented in the staff’s review of RAI 4.3-12.

The staff finds the applicant’s response to RAI 4.3-8 acceptable because for those components 

identified in RAI 4.3-8, EAF was considered for all RCPB components exposed to a reactor 

coolant environment, consistent with the GALL Report and SRP-LR. The staff’s review of the 

applicant’s methodology for determining additional locations to manage EAF of the RPV and 

RCPB piping components exposed to reactor coolant is documented in its evaluation of 

RAI 4.3-6. The staff’s concern described in RAI 4.3-8 is resolved.

LRA Table 4.3.3-2 shows that for the RCIC steam supply system, head vent system and HPCI 

steam supply system the Fen factor is 1.0 for both units. The LRA included footnote 8, which 

states that the Fen multiplier of 1.0 is used because the internal environment is dry steam. It 

was not clear to the staff why the LRA considered locations that are exposed to dry steam when 

addressing EAF and whether this was appropriate. 

By letter dated January 31, 2012, the staff issued RAI 4.3-12 requesting the applicant to clarify 

whether there are other locations, which are not exposed to dry steam, within these systems 

that would be more appropriate when addressing the effects of reactor coolant environment. 

In its response dated February 29, 2012, to RAI 4.3-12, the applicant stated that since the RCIC 

steam supply system, head vent system and HPCI steam supply system include only a dry 

steam environment, the Fen value of 1.0 was applied, which indicates that there is no increase in 

fatigue usage caused by environmental effects. The applicant confirmed that there are no other 

locations within the ASME Code, Section III, Class 1 boundary for these systems that would be 
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more appropriate to evaluate for environmental fatigue effects. The staff noted that UFSAR 

Section 3.6.1.2.1.7, 3.6.1.2.1.8, and 3.6.1.2.1.10 indicate that HPCI steam supply line, RCIC 

steam supply line, and head vent, respectively, are connected from the main steam line, which 

confirms that these piping systems are exposed to dry steam only.

The staff finds the applicant’s response to RAI 4.3-12 acceptable because the staff confirmed 

that the piping systems in HPCI steam supply line, RCIC steam supply line, and head vent are 

exposed to dry steam only, and thus, it is acceptable to use a Fen value of 1.0 for these systems. 

In addition, the staff finds that the applicant performed a thorough evaluation of its plant-specific 

configuration by including these piping systems exposed to dry steam to ensure that no ASME 

Code, Class 1, piping systems were overlooked when considering EAF. The staff’s concern 

described in RAI 4.3-12 is resolved.

LRA Table 4.3.3-2 indicates that the 40-year CUF value for the feedwater piping is 0.8011 at 

node 100 for both units. It was not apparent to the staff whether node 100 for LGS Unit 1 in 

LRA Table 4.3.3-2 refers to the same nodal location described in UFSAR Table 3.6-8 with a 

CUF value of 0.3651 or the LRA denotes that node 100 for the feedwater piping of LGS Unit 2

bounds LGS Unit 1.

By letter dated January 31, 2012, the staff issued RAI 4.3-11 requesting the applicant to clarify 

and justify the entry of the CUF value for the LGS Unit 1 feedwater piping in LRA Table 4.3.3-2. 

In addition, the applicant was requested to identify any other components or locations in LRA

Tables 4.3.3-1 and 4.3.3-2 in which a CUF value for one unit was used to bound the same 

component/location in the other unit.

In its response dated February 29, 2012, to RAI 4.3-11 the applicant stated that the locations 

and CUF values shown in LRA Table 4.3.2-2 for LGS Units 1 and 2, feedwater piping are 

applicable to both units. Stress analysis documentation shows that the locations and CUF 

values for the feedwater piping system are the same between the units. The applicant also 

stated that the RHR supply and return, recirculation drain, main steam (line c), instrumentation, 

and HPCI steam supply in LRA Table 4.3.3-2 used the same CUF value for the same 

component location on both units because the values from the current stress analyses are 

identical for both units. 

The applicant further explained that the CS nozzle (safe end) and CS nozzle (forging) are the 

only cases where the bounding location and CUF values for LGS Unit 1 are applied for Unit 2. 

The applicant stated that LGS Unit 1 bounds LGS Unit 2 because of a historical locked-snubber 

condition on the LGS Unit 1 CS piping, which resulted in increased applied loads from the piping 

system to the safe end and nozzle, which in turn would increase the CUF value. LRA 

Table 4.3.3-1 was revised to include a note to indicate that the bounding LGS Unit 1 ASME CUF 

values for the CS nozzle (safe end) and CS nozzle (forging) are used for LGS, Unit 2. The staff 

finds this reasonable because a locked snubber condition would result in different applied 

forces, moments, and stresses, which resulted in a different calculated CUF value.

The staff finds the applicant’s response to RAI 4.3-11 acceptable because the applicant clarified 

that the calculated CUF values in the stress analyses between LGS Units 1 and 2 are identical 

in the feedwater piping, RHR supply and return, recirculation drain, main steam (line c), 

instrumentation, and HPCI steam supply is caused by identical piping configurations. In 

addition, the staff finds the applicant’s explanation that the LGS Unit 1 CS nozzle safe end and 
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forging bound the LGS Unit 2 configuration based on the locked snubber operating experience 

in LGS Unit 1 to be reasonable. The staff’s concern described in RAI 4.3-11 is resolved. 

LRA Section 4.3.3 states that to ensure that other locations that may not be bounded by the 

NUREG/CR-6260 were evaluated, environmental fatigue calculations were performed for each 

RPV component location that has a reported CUF value in the stress report in each unit. In 

addition, each ASME Code, Section III, Class 1 RCPB piping system from each unit that has a 

reported CUF value in the stress report was evaluated. These calculations were performed for 

the limiting location for each material within the component or system that contacts reactor 

coolant. The applicant’s criteria for selecting locations to evaluate EAF were not clear; 

therefore, the staff was not able to determine whether other locations not provided in the LRA 

should have been considered. It was also not clear whether the applicant considered ASME 

Code, Section III, Class 1 valves when addressing EAF. By letter dated January 31, 2012, the 

staff issued RAI 4.3-6 requesting the applicant to (Part 1) justify its methodology for selecting 

locations to evaluate EAF, (Part 2) discuss whether the variation of certain parameters (thermal 

transient loadings, water chemistry conditions, etc.), were considered, and (Part 3) clarify 

whether Class 1 valves were also considered in this methodology.

In its response dated February 29, 2012, to Part 3, the applicant stated that ASME Code, 

Section III, Class 1 valve design reports were reviewed and representative valves were 

evaluated for environmental fatigue effects, based on the formulation in NUREG/CR-6909. The 

applicant explained that ASME Code design requirements specified in NB-3500 for ASME 

Code, Section III, Class 1 valves are different than the requirements for the ASME Code, 

Section III, Class 1 piping systems. Specifically, Subsection NB-3552 allows certain cycles to 

be excluded from valve cyclic loading analysis. However, the applicant stated that its ASME 

Code, Section III, Class 1 valve fatigue analyses did not always exclude these cycles and,

therefore, have conservative fatigue usage results in many cases. The environmental fatigue 

analyses performed for the ASME Code, Section III, Class 1 valves removed conservatism from 

the original analyses by removing events that meet the exclusion criteria in 

Subsection NB-3552. Consistent with Subsection NB-3552, the staff finds it reasonable that the 

applicant reduced the calculated CUF values in the original analyses by removing events that 

meet the ASME Code exclusion criteria. The applicant stated that Fen values were developed 

based upon temperatures associated with the evaluated transients and environmental 

conditions appropriate for the system; the resulting CUFen values were determined to be less 

than the design limit of 1.0. As part of the applicant’s response to RAI 4.3-6, a table containing 

the results of the EAF evaluations for ASME Code, Section III, Class 1 valves was provided; the 

staff noted that all CUFen values were less than 1.0.

The staff noted that some valves are represented by an analyzed valve that is bounding. In 

these instances, the analyzed valves and the unanalyzed valves were located in the same 

system and have the same valve size, material and pressure classification, except for the 

12-inch stainless steel RHR shutdown cooling (RHR-SDC), RHR-LPCI, and CS valves rated at 

900 lbs. Except for these 12-inch valves, the staff finds it reasonable that the applicant used a 

bounding analysis because the valves being represented have the same characteristics 

(e.g., size, material and pressure classification) and experience the same transients as the 

analyzed valve. For the 12-inch stainless steel RHR-SDC, RHR-LPCI, and CS injection valves 

rated at 900 lbs the applicant stated that the RHR-SDC system valves are exposed to transients 

associated with shutdown cooling operations that are not experienced by the RHR-LPCI and CS 

injection valves. In addition, the applicant also stated that the RHR-LPCI and CS injection 

valves are only exposed to transients that are also experienced by the RHR shutdown cooling 
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return valves. Based on this description, it was not clear to the staff what transients were 

associated with the RHR-SDC, RHR-LPCI, and CS valves; therefore, the staff was not able to 

determine whether it was reasonable that these valves were evaluated collectively. By letter 

dated April 17, 2012, the staff issued followup RAI 4.3-6.2 requesting the applicant to clarify 

which transients are experienced by these 12-inch stainless steel RHR-SDC, RHR-LPCI, and 

CS valves. 

In its response dated May 4, 2012, the applicant stated that the RHR-SDC valves and 

RHR-LPCI and CS injection valves are analyzed for the same numbers and types of design 

transients as those listed in LRA Tables 4.3.1-1 and 4.3.1-2 (except for those that only apply to 

the RPV), and the thermal profile of the shutdown transient is different for the SDC valves than 

for the other valves. The applicant stated that the thermal profile for the shutdown transient 

applicable to the RHR-LPCI and CS injection valves is a cooldown from reactor temperature to 

ambient at a rate not exceeding 100 °F/hr and there is no flow through these valves during a 

shutdown transient, so they slowly cool down with RPV temperature. However, the thermal 

profile for the shutdown transient applicable to the RHR-SDC valves is different because there 

is flow through the RHR-SDC valves during a shutdown transient, which includes a step change 

from 553 °F to 100 °F associated with SDC operation when cold water in the piping is assumed 

to flow through the hot valve. The fatigue usage associated with this step change accounts for 

approximately two thirds of the total fatigue usage in the analysis. Based on the applicant’s 

clarification, the staff finds it reasonable that the environmental fatigue analysis of the RHR-SDC 

valve bounds the RHR-LPCI and CS injection valves because the transients experienced by the 

RHR-SDC are more severe than the other valves and, thus, the RHR-SDC valve incurs more 

fatigue usage.

The staff finds the applicant’s response to followup RAI 4.3-6.2 acceptable because the 

applicant clarified the transients associated with the RHR SDC valve are more severe than 

those experienced by RHR LPCI and CS injection valves; such that the EAF analysis for the 

RHR SDC valves is bounding for these components. The staff’s concern identified in followup

RAI 4.3-6.2 is resolved.

In addition, the staff noted that LRA Sections 4.3.3 and A.4.3.3 were not updated to include the 

results and description of the evaluation of EAF for ASME Code Class 1 valves. Therefore, it 

was not clear to staff whether these EAF evaluations are also dispositioned in accordance with 

10 CFR 54.21(c)(1)(iii) and will be managed by the Fatigue Monitoring program. By letter dated 

April 17, 2012, the staff issued followup RAI 4.3-6.1 requesting the applicant to confirm the 

disposition of the EAF evaluations for the ASME Code Class 1 valves or make appropriate 

revisions to the LRA.

In its response dated May 4, 2012, the applicant stated the environmental fatigue analyses 

prepared for ASME Code Class 1 valves will be managed by the Fatigue Monitoring program in 

the same manner as all other Class 1 environmental fatigue analyses discussed in LRA 

Sections 4.3.3 and A.4.3.3. Specifically, the program will ensure that the cumulative number of 

occurrences of each transient type is maintained below the number of cycles used in the most 

limiting fatigue analysis, including these Class 1 valve environmental fatigue analyses. The 

applicant confirmed that the Class 1 valve environmental fatigue analyses are included within 

the disposition of 10 CFR 54.21(c)(1)(iii), provided in LRA Sections 4.3.3 and A.4.3.3.

The staff finds the applicant’s response to followup RAI 4.3-6.1 acceptable because the 

applicant confirmed that the disposition of 10 CFR 54.21(c)(1)(iii) identified in LRA 
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Sections 4.3.3 and A.4.3.3 is applicable to the environmental fatigue analyses for ASME Class 1

valves, such that the Fatigue Monitoring program will ensure that the environmentally assisted 

fatigue of these valves will be managed through the period of extended operation. The staff’s 

review of the Fatigue Monitoring program is documented in SER Section 3.0.3.2.20. The staff’s 

concern identified in followup RAI 4.3-6.1 is resolved.

In response to the staff’s concern in RAI 4.3-6, Part 1, regarding its methodology for selecting 

the locations to evaluate EAF in LRA Tables 4.3.3-1 and 4.3.3-2, the applicant provided a 

detailed explanation of its methodology, which the staff evaluates below in the following 

categories: NUREG/CR-6260 RPV component locations, NUREG/CR-6260 RCPB piping 

locations, other RPV component locations, and other RCPB locations. 

The applicant stated that the RPV component locations identified in NUREG/CR-6260 for a 

newer-vintage BWR plant design include the RPV shell and lower head (including CRD housing, 

stub tube, and vessel shell adjacent to stabilizer bracket), feedwater nozzle and safe end, 

recirculation inlet and outlet nozzle and safe end, CS nozzle and safe end, and LPCI nozzle and 

safe end. In addition, the EAF analyses for these components were performed using the 

formulation in NUREG/CR-6909, as described in LRA Section 4.3.3. Consistent with SRP-LR 

Section 4.3.2.1.3, the applicant considered the sample set of RPV component locations 

identified in NUREG/CR-6260 for a new vintage GE plant; therefore, the staff finds it acceptable. 

In addition, the use of NUREG/CR-6909 to determine the Fen factor is consistent with SRP-LR 

Section 4.3.2.1.3; therefore, the staff finds it acceptable.

The applicant stated that the RCPB piping locations identified in NUREG/CR-6260 for its plant 

design include the RHR return piping, LPCI piping, feedwater piping, CS piping, and reactor 

recirculation piping. Each location was analyzed by the applicant for reactor coolant 

environmental effects using Fen factor determined for the location. The staff noted that these 

analyses were performed using the formulation in NUREG/CR-6909, as described in LRA 

Section 4.3.3. Consistent with SRP-LR Section 4.3.2.1.3, the applicant considered the sample 

set of RCPB piping locations identified in NUREG/CR-6260 for a new vintage GE plant; 

therefore, the staff finds it acceptable. In addition, the use of NUREG/CR-6909 to determine the 

Fen factor is consistent with SRP-LR Section 4.3.2.1.3; therefore, the staff finds it acceptable.

The applicant stated that additional environmental fatigue analyses were performed to 

determine if any other RPV component locations beyond those identified in NUREG/CR-6260 

are limiting. For the RPV, the remaining RPV locations (i.e., locations not identified in 

NUREG/CR-6260) that have a reported CUF value in the design stress report were evaluated. 

The applicant stated that this does not include locations identified in the stress report as having 

met the exemption requirements of ASME Code Section III. The staff finds this acceptable 

because the applicant demonstrated as part of its CLB that fatigue, as defined by the ASME 

Code, is not applicable to these exempted locations. The applicant stated that for each RPV 

component with a reported CUF value, a further review was performed to identify each material 

type within the component in contact with reactor coolant (not including cladding), and for each 

material type, the location with the highest CUF value was evaluated for environmental fatigue. 

The staff finds it conservative that the applicant considered each material type for component 

locations with a reported CUF value in the design stress report because no component locations 

were eliminated, without justification, from consideration for selecting additional EAF locations. 

The staff finds it reasonable that the applicant disregarded the cladding because the cladding 

thickness would not typically be considered when satisfying cyclic stress requirements, 
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consistent with ASME Code, Section III, Subsection NB-3122, since the base metal is providing 

the pressure-boundary function.

The applicant stated that it reviewed the stress report for each ASME Code Class 1 RCPB 

piping system in order to determine other RCPB piping locations to consider. The applicant 

explained that the stress reports for systems that only have dry steam inside were included to 

demonstrate that no ASME Code Class 1 piping system was overlooked. The staff finds that 

the applicant performed a thorough evaluation of its plant-specific piping configuration by 

including these piping systems exposed only to dry steam to ensure that no ASME Code 

Class 1 piping systems were overlooked when considering EAF. The applicant stated that the 

location within each ASME Code Class 1 stress report with the highest CUF value was selected 

for an environmental fatigue evaluation, even though, in some cases, a single stress report 

includes coupled piping from more than one system. In addition, the applicant stated that its 

approach in selecting and evaluating the highest CUF is valid because the entire system, 

including the coupled piping, would be analyzed for the same thermal and pressure transients. 

The staff finds the applicant’s justification acceptable because, during the design of the plant, all 

locations within a particular ASME Code Class 1 piping system were analyzed on a consistent 

basis (e.g., transient severity and applied loadings), which allows for an equal comparison of 

CUF values within that system and selection of a critical location based on the highest CUF 

value. The applicant further explained that, for cases where multiple materials were included 

within the stress report, calculations were performed for the limiting location for each wetted 

material type. The staff finds the consideration of all the different wetted material types 

appropriate because the effects of EAF are different between carbon steel, low-alloy steel, 

stainless steel, and nickel alloys.

In response to the staff’s concerns in RAI 4.3-6, Part 2, provided by letter dated 

February 29, 2012, related to the analyzed transients, material, and effects of connected piping 

on a component location, the applicant stated that each ASME Code Class 1 stress report 

evaluates the components within its scope for the same transients plus the applied loadings 

from interfacing systems. As described previously for ASME Code Class 1 piping systems, the 

staff finds this rationale acceptable, which is also applicable to RPV component locations. The 

applicant stated that dissolved oxygen concentrations were determined for each region within 

the RPV and for each ASME Code Class 1 piping system based upon reactor vessel water 

chemistry data for each of three operating regimes, i.e., normal water chemistry (NWC), 

hydrogen water chemistry (HWC), and HWC with noble metal chemical addition (NMCA). Since 

the Fen value is dependent on dissolved oxygen levels, the staff finds it appropriate that the 

applicant considered the different operating regimes for water chemistry conditions at its plant 

based on the reactor vessel water chemistry data for the applicable RPV locations and ASME 

Class 1 piping when accounting for EAF.

The staff noted that the applicant’s methodology for selecting additional locations to manage 

EAF considered its plant-specific configuration. Specifically, the applicant considered the 

following: the specific transients that affect the RPV component and ASME Code Class 1 piping 

system; each material type, if applicable, for the RPV component and ASME Code Class 1 

piping system; applicable water chemistry conditions (i.e., dissolved oxygen level) at the RPV 

component and ASME Class 1 piping location; the different water chemistry operating regimes 

since initial plant operation (i.e., NWC, HWC ,and HWC with NMCA) and the attached piping to 

the component or system, as considered in the original design stress report.
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The staff finds the applicant’s response to all parts of RAI 4.3-6 acceptable because, consistent 

with recommendations in the GALL Report and the SRP-LR, the applicant considered the 

effects of reactor coolant environment on metal life for the sample locations identified in 

NUREG/CR-6260 and additional locations beyond NUREG/CR-6260 that are based on the 

applicant’s plant-specific configuration. In addition, the applicant demonstrated that its review 

considered all RCPB component location in contact with reactor coolant when identifying 

additional locations to consider EAF, which is comprehensive. The staff’s concerns described in 

RAI 4.3-6 are resolved.

The staff’s review of the applicant’s Fatigue Monitoring program is documented in SER 

Section 3.0.3.2.20. The staff determined that the program monitors and tracks the number of 

critical thermal, pressure, and seismic transients to assure that the cumulative number of 

occurrences of each transient type is maintained below the number of cycles used in fatigue 

evaluations. In addition, the program requires comparison of the actual event parameters to the 

applicable design transient definitions to assure the actual transients are bounded by the design 

transients. If a transient approaches an action limit, which the applicant has set to 80 percent of 

the cycle limit, corrective actions are initiated for repair, replacement, or reanalysis of the 

component, in accordance with the Fatigue Monitoring program. The staff determined that 

these characteristics of the applicant’s Fatigue Monitoring program are consistent with GALL 

Report AMP X.M1. The staff noted that the applicant’s method for managing these ASME Code 

Class 1 fatigue analyses is conservative, because corrective actions are initiated when one 

transient type approaches 80 percent of the cycle limit, when typically an ASME Code Class 1 

fatigue analysis includes more than one transient type.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of reactor coolant environment on component fatigue life will be adequately managed by 

the Fatigue Monitoring program for the period of extended operation. Additionally, the 

applicant’s demonstration meets the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because 

the applicant is crediting its Fatigue Monitoring program, which the staff has determined is 

consistent with GALL Report AMP X.M1, to manage EAF by monitoring transient occurrences to 

ensure that the assumptions in the EAF analyses remain valid during the period of extended 

operation; otherwise, the applicant will take corrective actions in accordance with its program.

4.3.3.3 UFSAR Supplement 

LRA Section A.4.3.3 provides the UFSAR supplement summarizing evaluations of the effects of 

the reactor coolant environment on fatigue life of piping and components. The staff reviewed 

LRA Section A.4.3.3, consistent with the review procedures in SRP-LR Section 4.3.3.2, which 

states 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 evaluations for the effects 

of the reactor coolant environment on fatigue life of piping and components. 

Based on its review of the UFSAR supplement, the staff finds that the supplement 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 effects of 

reactor coolant environment on component fatigue life, as required by 10 CFR 54.21(d).
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4.3.3.4 Conclusion 

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration, in accordance with 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 also concludes that the UFSAR supplement contains an appropriate 

summary description of the evaluations, as required by 10 CFR 54.21(d).

4.3.4 Reactor Vessel Internals (RVI) Fatigue Analyses

4.3.4.1 Summary of Technical Information in the Application 

LRA Section 4.3.4 describes the applicant’s metal fatigue TLAA for RVIs. The LRA states that 

the reactor internals were designed and procured before the issuance of ASME 

Code Section III, Subsection NG. However, an earlier draft of the ASME Code was used as a 

guide in the design of the reactor internals, and subsequent to the issuance of Subsection NG,

comparisons were made to ensure that the pre-NG design meets the equivalent level of safety 

as presented by Subsection NG. The applicant determined that these fatigue analyses have 

been identified as TLAAs that require evaluation for the period of extended operation.

The applicant dispositioned the fatigue TLAA for RVIs in accordance with 10 CFR 54.21(c)(1)(i)

to demonstrate that the analyses remain valid during the period of extended operation.

4.3.4.2 Staff Evaluation

The staff reviewed the applicant’s metal fatigue TLAAs for RVIs and the corresponding 

disposition of 10 CFR 54.21(c)(1)(i), consistent with the review procedures in SRP-LR 

Section 4.3.3.1.1.1, which states 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.

LRA Section 4.3.4 states that the fatigue analyses performed for the RVIs are based upon the 

same set of design transients as those used in the fatigue analyses for the RPV. Furthermore, 

as previously shown on Tables 4.3.1-1 and 4.3.1-2, transient cycle projections were prepared 

that demonstrate these design transient cycle limits will not be exceeded in 60 years; therefore, 

these analyses remain valid through the period of extended operation. However, since this 

TLAA relies on 60-year projections that are dependent on the Fatigue Monitoring program 

(i.e., managing the number of cycles), the staff was not clear on implications for cases where 

the Fatigue Monitoring program may determine that a transient cycle count reaches a cycle 

limit. By letter dated November 18, 2011, the staff issued RAI B.3.1-1, requesting the applicant 

to provide clarification.

In its response dated December 7, 2011, the applicant confirmed that the TLAA for RVIs is 

within scope of the Fatigue Monitoring program and based on the same set of design transients 

that this program monitors and trends. As such, the applicant confirmed that its procedure 

requires its engineers to initiate corrective action to demonstrate the design limit will not be 

exceeded before or during the period of extended operation; otherwise, further action for repair 

or replacement of the component, or other methods approved by the staff will be taken. As 

described in SER Section 3.0.3.2.20 the staff determined that the applicant ensures that the 
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results from its 60-year projections, which are used to disposition the TLAA for RVIs in 

accordance with 10 CFR 54.21(c)(1)(i), will remain valid during the period of extended 

operation, otherwise corrective actions will be taken.

In the applicant’s submittal dated March 25, 2010, “Request for License Amendment Regarding

Measurement Uncertainty Recapture Power Uprate,” a non-proprietary report NEDO–33484, 

Revision 0, “Safety Analysis Report for Limerick Generating Station Units 1 & 2 Thermal Power 

Optimization” was provided. Section 3.3.2 of this report states that the loads considered in the 

evaluation of the RVIs include the safety relief valve (SRV) transients. LRA Sections 4.3.4 and 

A.4.3.4 state that the fatigue analyses performed for the RVIs are based upon the same set of 

design transients as those used in the fatigue analyses for the RPV; however, the staff noted 

that transients related to SRV are not included in LRA Tables 4.3.1-1 and 4.3.1-2. 

It was not clear to the staff whether the transients related to the SRVs were used in the fatigue 

analyses for the RVIs. In addition, the LRA does not provide CUF values for the RVIs; thus, the 

staff cannot determine whether the CUF for any location will exceed the allowable limit during 

the period of extended operation. By letter dated January 31, 2012, the staff issued RAI 4.3-10 

requesting the applicant to clarify the discrepancy between the LRA and the non-proprietary 

report and identify the RVIs with CUF values.

In its response dated February 29, 2012, the applicant stated that SRV transients were 

considered in the fatigue evaluation of the RVIs, as stated in NEDO–33484, Revision 0. As 

indicated in UFSAR Section 3.9.1.1.9, at least 7,700 SRV cycles are considered to account for 

the pool dynamic loads for the RPV and RVIs and that these cycles are based on 

1,100 actuations of all MSRVs times seven stress cycles per actuation. The staff noted that 

these pool dynamic loads are associated with the suppression pool and are defined in UFSAR 

Section 3.9.3.3.1. The applicant stated that details regarding 60-year projections of the MSRV 

cycles, the addition of MSRV actuation cycles to the Fatigue Monitoring program, and related 

changes to the LRA are discussed in its response to RAI 4.6.8-1. The staff’s review of the 

applicant’s response to RAI 4.6.8-1 is documented in SER Section 4.6.8. The staff confirmed 

that the applicant amended the LRA to include Transient No. 20, MSRV Actuations, into the 

Fatigue Monitoring program and finds this acceptable because the applicant will be able to 

manage fatigue by ensuring that the assumptions in its TLAA for RVIs remain valid during the 

period of extended operation.

As part of the applicant’s February 29, 2012, response, LRA Table 3.1.2-3 was revised to add 

aging management review (AMR) items for the core shroud, core plate, LPCI coupling, CS lines 

and spargers, orificed fuel support, and jet pump, all to be managed for cumulative fatigue 

damage. The staff finds the applicant’s revision acceptable because the LRA was amended to 

include those systems, structures and components subject to an AMR in accordance with 

10 CFR 54.21(a)(1). 

The applicant also stated that in order to ensure that the transient cycle projections used in 

evaluating the RVIs fatigue TLAAs remain bounding through the period of extended operation, 

the disposition for these TLAAs in LRA Sections 4.3.4 and Section A.4.3.4 is revised from 

10 CFR 54.21(c)(1)(i) to 10 CFR 54.21(c)(1)(iii), crediting the Fatigue Monitoring program with 

managing fatigue through the period of extended operation.

The staff’s review of the applicant’s Fatigue Monitoring program is documented in SER 

Section 3.0.3.2.20. The staff determined that the program monitors and tracks the number of 
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critical thermal, pressure, and seismic transients to assure that the cumulative number of 

occurrences of each transient type is maintained below the number of cycles used in the most 

limiting ASME Code, Class 1 fatigue analysis. In addition, the program requires comparison of 

the actual event parameters to the applicable design transient definitions to assure the actual 

transients are bounded by the applicable design transients. If a transient approaches an action 

limit, which the applicant has set to 80 percent of the cycle limit, corrective actions are initiated 

for repair, replacement, or reanalysis of the component, in accordance with its Fatigue 

Monitoring program. The staff determined that these characteristics of the applicant’s Fatigue 

Monitoring program are consistent with GALL Report AMP X.M1. 

The staff also reviewed the CUF values provided by the applicant in response to RAI 4.3-10 and 

confirmed that the design CUF values for the components associated with the RVIs are less 

than the design limit of 1.0. The applicant also indicated that the steam dryer, steam dryer 

support brackets, and control rod guide tube are “exempt.” The applicant did not explain why 

these three components are exempt from a fatigue analysis. By letter dated April 17, 2012, the 

staff issued followup RAI 4.3-10.1 requesting the applicant clarify why these three components 

are exempt and identify the provisions in the ASME Code, Section III, that allowed the 

exemption of the required fatigue analysis for these components. 

In its response dated May 4, 2012, the applicant stated that the steam dryer support brackets 

were evaluated in the RPV stress report and the report stated that "exemption from fatigue 

analysis per N-415.1 (of the design Code) is satisfied." The design code of the brackets was 

the 1968 Edition of the ASME Code Section III with Addenda through Summer 1969. The 

response also indicated that the control rod guide tube was exempted from fatigue analysis per 

Paragraph NG-3222.4(d) of the ASME Code, Section III. 

The staff noted that the fatigue waiver provisions in N-415.1 indicated that fatigue analyses 

were not required when all of four specific conditions were met. In particular, the staff noted that 

Condition (a) of N-415.1 required that the specified numbers of times (including startup and 

shutdown) that the pressure will be cycled from atmospheric pressure to the operating pressure 

and back to atmospheric pressure shall not exceed certain requirements. Therefore, the staff 

noted that such cycling indicates that Condition (a) of N-415.1 is a time-dependent parameter. 

The response to RAI 4.3-10.1 did not provide a justification of why the fatigue waivers were not 

identified as TLAAs in the LRA. By letter dated June 12, 2012, the staff issued followup RAI 

4.3-10.2 requesting the applicant justify whether or not the fatigue waivers for the control rod 

guide tube and the steam dryer support brackets should be identified as TLAAs for the LRA and 

confirm that all fatigue waiver provisions in the ASME Code, Section III, have been identified as 

TLAAs, as applicable. 

In its response dated June 19, 2012, the applicant stated that fatigue exemptions (or fatigue 

waivers) are TLAAs because they meet all six TLAA criteria defined in 10 CFR 54.3. The 

applicant stated that Criterion 3 is met because the time-limited assumptions are based upon an 

evaluation of the thermal and pressure transients defined for 40 years in the design 

specifications for ASME Code Section III Class 1 and RVI components. The applicant also 

revised LRA Sections 4.3.1 and 4.3.4 to clarify that all fatigue exemptions have been identified 

as TLAAs and are managed by the Fatigue Monitoring program. The applicant also stated that 

UFSAR supplement Sections A.4.3.1 and A.4.3.4 and Appendix B, Section B.3.1.1 were revised 

with conforming changes. 
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The staff confirmed that the fatigue exemption provisions, for Class 1 components, in N-415.1 of 

the 1968 ASME Code Section III and Paragraph NB-3222.4(d) of the 1971 and later ASME 

Code Section III depended on the assumption of the number of occurrence of transients (such 

as startup and shutdown) that is a time-dependent parameter. The staff also confirmed that the 

fatigue exemption provisions, for RVI components, in Paragraph NG-3222.4(d) of the ASME 

Code Section III depended on a similar assumption. The staff concluded that the applicant 

appropriately identified the fatigue exemption as a TLAA in accordance with 

10 CFR 54.21(c)(1). 

The staff finds the applicant’s responses to RAI 4.3-10, followup RAIs 4.3-10.1 and 4.3-10.2 

acceptable because the applicant (1) clarified the discrepancy between the LRA and the 

non-proprietary report; (2) identified the RVI components with CUF values and those that were 

exempted from fatigue analyses; and (3) identified and dispositioned fatigue exemptions in 

accordance with 10CFR 54.21 (c)(1). The staff concerns identified in RAI 4.3-10, followup 

RAIs 4.3-10.1 and 4.3-10.2 are resolved. The staff’s review of the revised LRA Section 4.3.4 is 

documented below.

The staff noted that the applicant credits its Fatigue Monitoring program to disposition the 

fatigue analyses and fatigue exemptions TLAAs for RVI components. The staff’s review of the 

Fatigue Monitoring program is documented in SER Section 3.0.3.2.20. The staff determined 

that the program monitors and tracks the number of critical thermal, pressure, and seismic 

transients to assure that the cumulative number of occurrences of each transient type is 

maintained below the number of cycles used in the analyses. In addition, the program requires 

comparison of the actual event parameters to the applicable design transient definitions to 

assure the actual transients are bounded by the applicable design transients. If a transient 

approaches an action limit, which the applicant has set to 80 percent of the cycle limit, 

corrective actions are triggered for repair, replacement, or reanalysis of the component, in 

accordance with its Fatigue Monitoring program. The staff determined that these characteristics 

of the Fatigue Monitoring program are consistent with GALL Report AMP X.M1. 

Based on its review, the staff finds the applicant has demonstrated in accordance with 

10 CFR 54.21(c)(1)(iii) that the effects of metal fatigue on the intended functions of the RVIs 

components analyzed in accordance with ASME Code Section III, Subsection NG requirements 

will be adequately managed by the Fatigue Monitoring program for the period of extended 

operation. Additionally, the analysis meets the acceptance criteria in SRP–LR 

Section 4.3.2.1.1.3 because the applicant is crediting its Fatigue Monitoring program, which the 

staff has determined is consistent with GALL Report AMP X.M1, to manage metal fatigue by 

monitoring transient occurrences to assure that the assumptions in the fatigue analyses and 

fatigue exemptions remain valid 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, as amended by letters dated February 29, 2012 and June 19, 2012, 

provides the UFSAR supplement summarizing the metal fatigue TLAAs for RVIs. The staff 

reviewed LRA Section A.4.3.4, consistent with the review procedure in SRP-LR Section 4.3.3.2, 

which states 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 TLAAs. 
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Based on its review of the UFSAR supplement, the staff finds that the supplement 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 RVI metal 

fatigue and fatigue exemption TLAAs, as required by 10 CFR 54.21(d).

4.3.4.4 Conclusion 

On the basis of its review the staff concludes that the applicant provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that effects of metal fatigue for RVIs 

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 adequate 

summary description of the evaluated TLAAs, as required by 10 CFR 54.21(d).

4.3.5 High-Energy Line Break (HELB) Analyses Based Upon Fatigue

4.3.5.1 Summary of Technical Information in the Application 

LRA Section 4.3.5 describes the applicant’s TLAA for HELB analyses based upon fatigue. The 

LRA states that HELB analyses used the CUF values from the ASME Code, Class 1 fatigue 

analyses as input in determining intermediate break locations. Furthermore, locations with a 

CUF value less than 0.1 did not always require a break to be postulated. Therefore, since the 

HELB analyses are based on the CUF values in ASME Code Class 1 fatigue analyses, they 

have also been identified as TLAAs.

The applicant dispositioned the TLAA for the HELB analyses based upon fatigue in accordance 

with 10 CFR 54.21(c)(1)(i), that the analysis remains valid during the period of extended 

operation.

4.3.5.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for HELB analyses based upon fatigue and the 

corresponding disposition of 10 CFR 54.21(c)(1)(i), consistent with the review procedure in 

SRP-LR Section 4.3.3.1.1.1, which states 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 staff noted that UFSAR Section 3.6 contains information associated with the applicant’s 

HELB analyses, which rely on the CUF that was calculated for the ASME Code, Section III, 

Class 1 requirements. LRA Section 4.3.5 states that transient cycle projections were performed 

and determined that the 40-year transient cycle limits will not be exceeded in 60 years of 

operation. The staff’s evaluation of the applicant’s cycle projection is documented in SER 

Section 4.3.1. LRA Section 4.3.5 states that since the ASME Code, Class 1 piping fatigue 

analyses were demonstrated to remain valid for the period of extended operation, the HELB 

break determinations based upon these fatigue analyses will also remain valid for the period of 

extended operation. 

However, since this TLAA relies on 60-year projections that are dependent on the Fatigue 

Monitoring program (i.e., managing the number of cycles), the staff was not clear on 

implications for cases where the Fatigue Monitoring program may determine that a transient 
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cycle count reaches a cycle limit. By letter dated November 18, 2011, the staff issued 

RAI B.3.1-1, requesting the applicant to provide clarification.

In its response dated December 7, 2011, the applicant confirmed that the TLAA for HELB 

analyses is within scope of the Fatigue Monitoring program and is based on the same set of 

design transients that the program monitors and trends. As such, the applicant confirmed that 

its procedure requires its engineers to initiate corrective action to demonstrate the design limit 

will not be exceeded before or during the period of extended operation; otherwise, further action 

for repair of the component; replacement of the component, or other methods approved by the 

staff will be taken. The staff determined in SER Section 3.0.3.2.20, that the applicant 

continually ensures that the results from its 60-year projections used to disposition the HELB 

TLAA in accordance with 10 CFR 54.21(c)(1)(i), will remain valid during the period of extended 

operation; otherwise, corrective actions will be taken.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the TLAA for HELB analyses based upon fatigue, remain valid for the period of extended

operation. Additionally, the applicant meets the acceptance criteria in SRP-LR 

Section 4.3.2.1.2.1 because the projected number of transient cycles over the period of 

extended operation is not expected to exceed the design cycle limit used in the HELB analyses. 

However, in any event, the applicant confirmed that these analyses are within the scope of the 

Fatigue Monitoring program, which will ensure that the results from its projections used to 

disposition this TLAA will remain valid during the period of extended operation, otherwise 

corrective actions will be taken.

4.3.5.3 UFSAR Supplement 

LRA Section A.4.3.5 provides the UFSAR supplement summarizing the TLAA for HELB 

analyses based upon fatigue. The staff reviewed LRA Section A.4.3.5, consistent with the 

review procedures in SRP-LR Section 4.3.3.2, which states 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 TLAA. 

Based on its review of the UFSAR supplement, the staff finds that the supplement 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 of 

HELB analyses based upon fatigue, 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 provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the HELB analyses based upon fatigue

remain valid for the period of extended operation. The staff also concludes that the UFSAR 

supplement contains an adequate summary description of the evaluated TLAAs, as required by 

10 CFR 54.21(d).
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4.4 Environmental Qualification of Electric Equipment

4.4.1 Summary of Technical Information in the Application 

LRA Section 4.4 describes the applicant’s TLAA for the evaluation of environmentally qualified 

electrical equipment for the period of extended operation. The applicant stated the EQ program

manages component thermal, radiation, and cyclical aging, as applicable, through the use of 

aging evaluations based on 10 CFR 50.49(f) qualification methods.

LRA Section 4.4 discusses the component reanalysis attributes, including analytical models, 

data collection and reduction methods, underlying assumptions, acceptance criteria, and 

corrective actions. 

The applicant dispositioned the EQ of Electric Components TLAA in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions will be adequately 

managed for the period of extended operation.

4.4.2 Staff Evaluation 

The staff reviewed LRA Section 4.4, “Environmental Qualification of Electric Components,”

TLAA to verify, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended 

functions will be adequately managed for the period of extended operation.

The staff reviewed the applicant’s TLAA and the corresponding disposition, consistent with the 

review procedure in SRP-LR Section 4.4.3.1.3, which states that the reviewer verifies that the 

applicant has stated that its environmental qualification program contains the same program 

elements that the staff evaluated and relied upon in approving the corresponding generic 

program in the GALL Report.

The environmental qualification requirements established by 10 CFR Part 50, Appendix A, 

Criterion 4, and 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. The EQ of electrical 

components is a TLAA for purposes of license renewal. The TLAA of the EQ of electrical 

components includes all long-lived, passive, and active electrical and instrumentation and 

controls (I&C) components that are important to safety and are located in a harsh environment. 

The harsh environments of the plant are those areas subject to environmental effects by a 

LOCA, a HELB, or post-LOCA environment. EQ equipment comprises safety-related and 

nonsafety-related equipment, the failure of which could prevent satisfactory accomplishment of 

any safety-related function, and necessary post-accident monitoring equipment.

The staff reviewed LRA Sections 4.4 and B.3.1.2, plant basis documents, 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 TLAA evaluation to demonstrate that the aging 

effects of EQ equipment will be adequately managed during the period of extended operation. 

Based on 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 AMP X.E1, “Environmental Qualification (EQ) of Electric Components,” provides a 

means to meet the requirements of 10 CFR 54.21(c)(1)(iii). The staff reviewed the applicant’s 
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EQ program to determine whether it will assure that 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 component qualifications focused on how the EQ program

manages the aging effects to meet the requirements in 10 CFR 50.49. The staff conducted an 

audit of the information provided in LRA Sections 4.4 and B.3.1.2 and the program basis 

documents. On the basis of its audit, and as described in SER Section 3.0.3.1.25, the staff 

found that the Environmental Qualification of Electric Components program, 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. Therefore, the staff concludes that 

the applicant’s Environmental Qualification of Electric Components TLAA is implemented per 

the requirements of 10 CFR 54.21(c)(1)(iii). 

The staff finds the applicant has demonstrated in accordance with 10 CFR 54.21(c)(1)(iii) that 

the effects of aging on the intended functions of the Environmental Qualification of Electric 

Components TLAA will be adequately managed for the period of extended operation. 

Additionally, it meets the acceptance criteria in SRP-LR Section 4.4.2.1 because the 

Environmental Qualification of Electric Components 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.

4.4.3 UFSAR Supplement 

LRA Section A.4.4 provides the UFSAR supplement summarizing the Environmental 

Qualification 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 states 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 TLAA. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.4.1.3. Additionally, the staff determines that the applicant provided an 

adequate summary description of its actions to address the Environmental Qualification of 

Electric Components TLAA for the period of extended operation, 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, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of aging on the 

intended functions of the Environmental Qualification of Electric Components TLAA will be 

adequately managed 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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4.5 Containment Liner Plate and Penetration Fatigue Analyses

4.5.1 Summary of Technical Information in the Application 

LRA Section 4.5 describes the applicant’s TLAA of the containment liner and penetrations 

fatigue analysis. The LRA states that the primary containment liner plate and anchorage 

system (welds and anchors) were analyzed for transient cycles caused by mechanical loads 

(MSRV discharge and chugging) to occur over 40 years. Stresses (primary, secondary 

membrane, and bending) were evaluated in accordance with ASME Code, Section III, 

Subsection NE-3222.2, and fatigue strength in accordance with ASME Code, Section III, 

Subsection NE-3222.4. Allowable design stress intensity values, design fatigue curves, and 

material properties used in the evaluation conform to ASME Code, Subsection NA, Appendix I. 

The LRA also states that the liner plate fatigue analysis has been identified as a TLAA.

The LRA further states that penetrations include the drywell head assembly, the equipment 

hatches, the personnel lock, the suppression chamber access hatches, the CRD removal hatch, 

and piping and electrical penetrations. The LRA also states that penetrations are designed per 

ASME Code Class MC steel components of the concrete containment since they form part of 

the pressure boundary not backed by structural concrete. A portion of each of the penetration 

sleeves extends beyond the containment wall. The entire length of any penetration sleeve is 

considered a Class MC component. The fatigue analyses for ASME Code Class MC 

components have been identified as TLAAs. 

ASME Code Class 1 fatigue analyses were also performed for flued-head penetrations 

associated with the following piping systems: main steam, RCIC Steam, HPCI Steam, RHR 

supply and return, reactor water cleanup, standby liquid control (SLC), and LPCI injection. 

These fatigue analyses are based upon the same design transients as the ASME Code Class 1 

piping systems they are associated with and have been identified as TLAAs.

LRA Tables 4.3.1-1 and 4.3.1-2 show the results of 60-year transient cycle projections. The 

applicant stated that the tables demonstrate that the 40-year transient cycle limits will not be 

exceeded in 60 years based upon the average rate of occurrence to-date. This includes startup 

and shutdown cycles and DBA events. The applicant further stated that an operational review 

was performed for the MSRV lift cycles that concluded the total number of cycles projected for 

60 years, will not exceed the number analyzed for 40 years. Therefore, the analyses based 

upon these transients will remain valid for the period of extended operation. 

The applicant dispositioned the TLAAs for the containment liner and containment penetrations 

in accordance with 10 CFR 54.21(c)(1)(i), that the analyses remain valid for the period of 

extended operation.

4.5.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the containment liner and penetrations fatigue 

analyses and the corresponding disposition of 10 CFR 54.21(c)(1)(i), that the analyses remain 

valid for the period of extended operation, consistent with the review procedures in Section 

4.6.3.1.1.1 of the SRP-LR. The SRP-LR states that the number of assumed transients used in 

the existing CUF calculations for the current operating term is compared to the extrapolation to 

60 years of operation of the number of operating transients experienced to-date.
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The staff reviewed LRA Section 4.5.1 for the containment liner and confirmed that UFSAR 

Section 3A.6.4, “Liner Plate Capability Assessment Criteria,” states that stresses in the liner 

plate and anchorage system (welds and anchors) from mechanical loads such as SRV 

discharge and chugging are evaluated in accordance with ASME Code, Section III, Division 1, 

(1974). In addition the staff confirmed that UFSAR Section 3A.6.4 states that primary plus 

secondary membrane plus bending stresses are evaluated in accordance with ASME Code, 

Subsection NE-3222.2, “Primary-Plus-Secondary Stress Intensity,” of the ASME Code of record. 

The staff also confirmed that the fatigue strength evaluation is based on Subsection NE-3222.4, 

“Analysis for Cyclic Operation,” of the ASME Code of record. The staff confirmed that UFSAR 

Section 3A.6.4 states that allowable design stress intensity values, design fatigue curves, and 

material properties follow Subsection NA, Appendix I of the ASME Code of record.

The staff also reviewed UFSAR Section 3.8.2, “ASME Class MC Steel Components of the 

Containment” and confirmed that the concrete containment has the following ASME Class MC 

steel components: (1) drywell head assembly, (2) the equipment hatches, (3) the personnel 

lock, (4) the suppression chamber access hatches, (5) the CRD removal hatch, and (6) piping 

and electrical penetrations. The staff confirmed in UFSAR Section 3.8.2 that these components 

form a portion of the containment pressure boundary and are not backed by structural concrete. 

The staff then reviewed LRA Tables 4.3.1-1, “60-Year Transient Cycle Projections for LGS 

Unit 1,” and 4.3.1-2, “60-Year Transient Cycle Projections for LGS Unit 2,” of the LRA and 

confirmed that LGS Units 1 and 2 have limited the number of design cycles for startup to 120 

cycles and shutdown to 120 cycles. For 60 years of operation the LRA tables indicate that the 

projected cycles are 112 startup transients and 109 shutdown transients for LGS Unit 1. The 

projected cycles for 60 years of operation are 90 startup transients and 88 shutdown transients

for LGS Unit 2. The staff then confirmed per UFSAR Section 3.8.2.3.4, “Thermal Loads,” that 

the ASME Class MC components are designed for startup and shutdown of 500 thermal cycles 

and for one DBA cycle. The staff also confirmed that UFSAR Sections 3.8.2.3, “Loads and 

Loading Combinations” and 3.8.2.4, “Design and Analysis Procedures,” state that the ASME 

Code Class MC components include the effects of Mark II hydrodynamic load assessments 

caused by MSRV discharge and LOCA phenomena. 

The staff then reviewed the UFSAR for flued-head penetrations for the following systems: main 

steam, RCIC steam, HPCI steam, RHR supply and return, reactor water cleanup, SLC, and 

LPCI injection. The staff confirmed that UFSAR Section 3.8.2.4.3, “Piping and Electrical 

Penetrations,” states that Nuclear Class 1 design and analysis flued head penetrations comply 

with ASME Code Section III, Subsection B of the ASME Code of record. The staff also 

reviewed LRA Tables 4.3.1-1 and 4.3.1-2, which were evaluated in SER Section 4.3.1.2, and 

noted that cycle counting records from pre-operational startup testing through January 2011 

indicate that projected transient cycles for 60 years of operation are less than the design cycle 

limits specified in UFSAR Section 5.6, “Component Cyclic or Transient Limit,” of LGS Units 1 

and 2, and in UFSAR Tables 3.9-2, "Design Events," and 5.2-9, “RCPB Operating Thermal 

Cycles.”

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(i), that the 

analyses for the containment liner and penetrations fatigue analyses remain valid for the period 

of extended operation.
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4.5.3 UFSAR Supplement 

LRA Section A.4.5.1 provides the UFSAR supplement summarizing the containment liner and 

penetrations fatigue analyses. The staff reviewed LRA Section A.4.5.1 consistent with the 

review procedures in SRP-LR Section 4.6.3.2, which states that the number of assumed 

transients used in the existing CUF calculations for the current operating term should be

compared to the extrapolation to 60 years of operation of the number of operating transients 

experienced to date. The comparison confirmed that the number of transients in the existing 

analyses would not be exceeded during 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 4.6.2.2 and SRP-LR Section 4.6.3.2. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the TLAA of the 

fatigue design of the containment penetrations, 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)(i), that the containment liner and penetrations 

fatigue analyses remain 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 Other Plant-Specific TLAAs

LRA Section 4.6 summarizes the evaluation of the following plant-specific TLAAs:

 • reactor enclosure crane cyclic loading analysis

 • EDG enclosure cranes

 • RPV core plate rim hold-down bolt loss of preload

 • main steam line flow restrictors erosion

 • jet pump auxiliary spring wedge assembly

 • jet pump restrainer bracket pad repair clamps

 • refueling bellows and support cyclic

 • downcomers and MSRV discharge piping

 • jet pump slip joint repair clamps

4.6.1 Reactor Enclosure Crane Cyclic Loading Analysis 

4.6.1.1 Summary of Technical Information in the Application 

LRA Section 4.6.1 describes the applicant’s TLAA for the reactor enclosure crane. The reactor 

enclosure crane is common to both units and was designed to meet the fatigue requirements of 

the Crane Manufacturers Association of America (CMAA) Specification 70 for a Class A, 

Standby or Infrequent Service Crane. The applicant stated that the evaluation of the reactor 
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enclosure crane cyclic load limit TLAA included (1) reviewing the existing 40-year design basis

to determine the number of load cycles considered in the design of the crane, (2) developing a 

60-year projection for load cycles for the crane, and (3) comparing the 60-year projected 

number of cycles to the 40-year design cycles. The applicant further stated that the 60-year 

projected number of cycles is less than 20 percent of the minimum allowable design value of 

20,000 cycles; therefore, the reactor enclosure crane load cycle fatigue analysis remains valid 

for 60 years of plant operation.

The applicant dispositioned the TLAA for the reactor enclosure crane in accordance with 

10 CFR 54.21(c)(1)(i), that the analysis remains valid for the period of extended operation.

4.6.1.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the reactor enclosure crane and the corresponding 

disposition, consistent with the review procedures in SRP-LR Section 4.7.3.1.1, which states 

that the existing analyses should be shown to be bounding during the period of extended 

operation. The SRP-LR also states that the applicant should describe the TLAA with respect to 

the objectives of the analysis, assumptions used in the analysis, conditions, acceptance criteria, 

relevant aging effects, and intended functions. 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 acceptance criteria are maintained to provide reasonable assurance 

that the intended functions are maintained for renewal.

The staff reviewed LRA section 4.6.1, UFSAR Section 9.1.5, and CMAA Specification 70 and 

found that the reactor enclosure crane was designed to meet the fatigue requirements for a 

Class A, Standby or Infrequent Service Crane. The UFSAR states that the structural members 

of the reactor enclosure crane are designed for a fatigue loading of 20,000-100,000 cycles. The 

UFSAR further states that the reactor enclosure crane serves both units and is designed to be 

used normally during maintenance and refueling operations. LRA Table 4.6.1-1 shows the 

estimated total number of loading cycles for the 60-year projection, based on the existing 

40-year design basis. The 60-year total load cycles is projected to be 3,468, which is less than 

20 percent of the minimum design range of 20,000-100,000 cycles.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the analysis for the reactor enclosure 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 showed that the existing analysis remains valid for the period 

of extended operation.

4.6.1.3 UFSAR Supplement 

LRA Section A.4.6.1 provides the UFSAR supplement summarizing the reactor enclosure crane 

cyclic loading analysis. The staff reviewed LRA Section A.4.6.1 consistent with the review 

procedures in SRP-LR Section 4.7.3.2, which states that the applicant should provide

information to be included in the UFSAR supplement that includes a summary description of the 

evaluation of each TLAA. SRP-LR Section 4.7.3.2 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 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 is, therefore, acceptable. Additionally, the staff determines that 

the applicant provided an adequate summary description of its actions to address the reactor 

enclosure crane cyclic loading analysis, as required by 10 CFR 54.21(d).

4.6.1.4 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 analysis for the reactor 

enclosure crane 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).

4.6.2 Emergency Diesel Generator Enclosure Cranes

4.6.2.1 Summary of Technical Information in the Application 

LRA Section 4.6.2 describes the applicant’s TLAA for the EDG enclosure cranes. These eight 

EDG enclosure cranes were designed to meet or exceed the design fatigue requirements of 

CMAA Specification 70 for Class A, Standby or Infrequent Service Cranes. The applicant stated 

that the EDG enclosure cranes were evaluated for the period of extended operation by 

developing 60-year projections for crane load cycles and comparing these to the number of 

cycles evaluated for the design life of the cranes. The applicant also stated that a conservative 

estimate, as determined from review of station procedures and personnel knowledgeable on the 

use of these cranes, results in approximately 3,500 load cycles, which is less than 20 percent of 

the allowable design value of 20,000 cycles. Therefore, the analysis remains valid for the 

period of extended operation

The applicant dispositioned the TLAA for the emergency diesel generator enclosure cranes in 

accordance with 10 CFR 54.21(c)(1)(i), 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 EDG enclosure cranes and the corresponding 

disposition, consistent with the review procedures in SRP-LR Section 4.7.3.1.1, which states 

that the existing analyses should be shown to be bounding even during the period of extended 

operation. The SRP-LR also states that the applicant describes the TLAA with respect to the 

objectives of the analysis, assumptions used in the analysis, conditions, acceptance criteria, 

relevant aging effects, and intended functions. The SRP-LR further states that the applicant 

shows that conditions and assumptions used in the analysis already address the relevant aging 

effects for the period of extended operation, and acceptance criteria are maintained to provide 

reasonable assurance that the intended functions are maintained for renewal.

The staff reviewed LRA Section 4.6.2 and CMAA Specification 70 and found that the EDG 

enclosure cranes were designed to meet the fatigue requirements for a Class A, Standby or 

Infrequent Service Crane, which allows for a range of 20,000-100,000 load cycles. The 

applicant developed the 60-year projections for these cranes based on a review of station 

procedures and personnel knowledgeable on the use of these cranes. This estimate accounts 

for an estimated 500 load cycles during original construction and 50 load cycles per year during 
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diesel generator maintenance. The total estimated 3,500 load cycles per crane, projected for 

60 years, is less than 20 percent of the minimum design range of 20,000-100,000 cycles.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the analysis for the emergency diesel generator enclosure cranes 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 showed that the existing analysis 

remains valid for the period of extended operation.

4.6.2.3 UFSAR Supplement 

LRA Section A.4.6.2 provides the UFSAR supplement summarizing the EDG enclosure cranes 

cyclic loading analysis. The staff reviewed LRA Section A.4.6.2 consistent with the review 

procedures in SRP-LR Section 4.7.3.2, which states that the applicant should provide 

information to be included in the UFSAR supplement that includes a summary description of the 

evaluation of each TLAA. SRP-LR Section 4.7.3.2 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 and that the description should contain information that the TLAAs have been

dispositioned for 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 is, therefore, acceptable. Additionally, the staff determines that 

the applicant provided an adequate summary description of its actions to address the EDG

enclosure cranes cyclic loading analysis, 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, in accordance with 10 CFR 54.21(c)(1)(i), that the analysis for the EDG 

enclosure cranes 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 RPV Core Plate Rim Hold-down Bolt Loss of Preload 

4.6.3.1 Summary of Technical Information in the Application 

LRA Section 4.6.3 describes the applicant’s loss of preload TLAA for the RPV core plate rim 

hold-down bolts. The RPV core plate is attached to the core support structure by stainless steel 

hold-down bolts that are preloaded during initial installation. These bolts are subject to stress 

relaxation (loss of preload) caused by irradiation effects. Since these bolts were evaluated for 

fluence expected to occur in 40 years, this analysis has been identified as a TLAA that requires 

evaluation for the period of extended operation. 

The applicant dispositioned the TLAA for the RPV core plate rim hold-down bolts in accordance 

with 10 CFR 54.21(c)(1)(i), indicating that the analysis remains valid for the period of extended 

operation.
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4.6.3.2 Staff Evaluation 

The staff reviewed LRA Section 4.6.3 on the loss of preload TLAA for RPV core plate rim 

hold-down bolts, 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. The SRP–LR states that the staff should 

review the justification provided by the applicant to verify that the existing analyses are valid 

even during the period of extended operation. 

LRA Section 4.6.3 states that a reduction in preload as high as 19 percent for these bolts is 

acceptable to meet the design requirements. In addition, an evaluation determined that the 

maximum relaxation value of 19 percent corresponds to an average fluence level of 

8.0 E+19 n/cm2

. The staff noted that as long as the 60-year projected fluence level is less than 

8.0 E+19 n/cm2

, than the original analysis remains valid. LRA Section 4.2.1 identifies that the 

EFPY at the end of 60 years of operation are 55 and 57 for LGS Units 1 and 2, respectively, but 

the applicant conservatively evaluated LGS Unit 1 for 57 EFPY for consistency with LGS Unit 2. 

The applicant stated in LRA Section 4.6.3 that it calculated the 57 EFPY fluence value using the 

RAMA fluence methodology. The staff noted that LRA Section 4.2.1 indicates that the high 

energy (>1 MeV) neutron fluence was calculated for the RPV beltline welds and shells using 

RAMA, which is consistent with RG 1.190. The staff’s evaluation of the applicant’s 57 EFPY 

fluence projections is documented in SER Section 4.2.1.2. The staff noted that the applicant 

calculated the 57 EFPY fluence value for the bolts by integrating along the length of the bolt. 

The resulting fluence value is 3.37 E+19 n/cm2 for both the LGS Units 1 and 2 RPV core plate 

rim hold-down bolts. The staff noted that this calculated fluence value for the bolts is less than 

half of the original design value of 8.0 E+19 n/cm2

.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the loss of preload TLAA for the RPV core plate rim hold-down bolts analysis, remains valid for 

the period of extended operation. Additionally, the applicant’s analysis meets the acceptance 

criteria in SRP–LR Section 4.7.2.1 because the projected 60-year fluence value, 

3.37 E+19 n/cm2

, for the RPV core plate rim hold-down bolts does not exceed the 40-year 

allowed fluence value in the original design, 8.0 E+19 n/cm2

, with margin to account for 

unanticipated irradiation effects.

4.6.3.3 UFSAR Supplement 

LRA Section A.4.6.3 provides the UFSAR supplement summarizing the loss of preload TLAA for 

the RPV core plate rim hold-down bolts. The staff reviewed LRA Section A.4.6.3, consistent 

with the review procedures in SRP–LR Section 4.7.3.2, which states 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. 

Based on its review of the UFSAR supplement, the staff finds that the supplement meets the 

acceptance criteria in SRP-LR Section 4.7.2.2. Additionally, the staff determines that the 

applicant provided an adequate summary description of its analysis of the loss of preload TLAA 

for the RPV core plate rim hold-down bolts, 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 provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(i), that the loss of preload TLAA for the 
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RPV core plate rim hold-down bolts remains valid for the period of extended operation. The 

staff also concludes that the UFSAR supplement contains an adequate summary description of 

the evaluated TLAA, as required by 10 CFR 54.21(d).

4.6.4 Main Steam Line Flow Restrictors Erosion 

4.6.4.1 Summary of Technical Information in the Application 

LRA Section 4.6.4 describes the applicant’s TLAA of the main steam line flow restrictor erosion 

analysis for the stainless steel venturi-type nozzles welded into each main steam line pipe. The 

LRA states that, in response to a main steam line break outside of primary containment, the 

steam flow restrictors are designed to limit reactor coolant loss, to maintain core cooling, and to 

limit the release of radiological material to the environment. The LRA refers to UFSAR 

Section 5.4.4, which indicates that very slow erosion of the flow restrictors occurs with time, and 

that the resistance of stainless steel to erosion at similar steam velocities has been 

substantiated by turbine inspections at another BWR plant, which found no noticeable effects.

The LRA states calculations indicate that even with erosion rates as high as 0.004 inch per 

year, the increase in choked flow would be no more than 5 percent after 40 years of operation. 

The LRA also states that the steam line break analysis for LGS calculated an integrated mass of 

coolant leaving the reactor as 108,785 lbs, which is less than the bounding value of 140,000 lb 

used in the analysis as provided in SRP 15.6.4, Paragraph III.2.a for a GESSAR-251 plant. The 

LRA further states that postulating additional erosion, which would increase the choked flow rate 

5 percent more, or a total increase of 10 percent, would not challenge the use of 140,000 lb 

coolant release as the bounding input to the dose calculation. 

The applicant dispositioned the TLAA for the main steam line flow restrictor erosion analysis, in 

accordance with 10 CFR 54.21(c)(1)(i), that the analysis remains valid for the period of 

extended operation.

4.6.4.2 Staff Evaluation 

The staff reviewed LRA Section 4.6.4 and the Main Steam Line Flow Restrictor Erosion Analysis 

TLAA, to verify pursuant to 10 CFR 54.21(c)(1)(i), that the analysis remains valid for the period 

of extended operation. The staff reviewed the applicant’s TLAA for the main steam line flow 

restrictor erosion analysis and the corresponding disposition that the analysis remains valid for 

the period of extended operation, consistent with the review procedure in SRP-LR 

Section 4.7.3.1.1, which states that no reanalysis is necessary if (a) conditions and assumptions 

used in the analysis already address the relevant aging effects for the period of extended 

operation, and (b) acceptance criteria are maintained to provide reasonable assurance that the 

intended functions are maintained for renewal.

The staff reviewed the applicant’s analysis as documented in UFSAR Section 5.4.4 and noted 

the large margin between the bounding assumption of 140,000 lbs total integrated mass leaving 

the reactor vessel through the steam line break and the calculated amount of 108,785 lbs in 

UFSAR Section 15.6.4, “Steam System Piping Break Outside of Primary Containment.” The 

staff also noted the applicant had conservatively assumed that the additional erosion during the 

20 years of extended operation would be the same amount as the first 40 years, which would 

result in an additional 5 percent increase, or a total of 10 percent above the calculated amount. 

The staff further noted that this conservative assumption would yield a total integrated mass 
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leaving the reactor vessel of less than 120,000 lbs, which is still bounded by the original 

assumption of 140,000 lb.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the analysis for the main steam line flow restrictor erosion remains valid for the period of 

extended operation. Additionally, the analysis meets the criteria of SRP-LR Section 4.7.3.1.1 

because the bounding assumptions used in the original analysis will remain valid by assuming 

additional erosion during the next 20 years is the same amount assumed during the first 

40 years, and no reanalysis is necessary. 

4.6.4.3 UFSAR Supplement 

LRA Section A.4.6.4 provides the UFSAR supplement summarizing the main steam line flow 

restrictor erosion analysis. The staff reviewed the LRA Section A.4.6.4 consistent with the 

review procedures in SRP-LR Section 4.7.3.2, which states that the information to be included 

in the UFSAR supplement should include 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 is, therefore, 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). 

4.6.4.4 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)(i), that the analysis for the main steam 

flow restrictor erosion 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).

4.6.5 Jet Pump Auxiliary Spring Wedge Assembly 

4.6.5.1 Summary of Technical Information in the Application 

LRA Section 4.6.5 describes the applicant’s TLAA for the jet pump auxiliary spring wedge 

assemblies, which were designed and installed to maintain lateral support for the jet pump inlet 

mixer. The LRA states that the design analysis considered potential aging effects from fatigue 

usage and relaxation in preload caused by neutron fluence based on a 40-year design. The first 

assembly was installed in LGS Unit 1 in March 2004 and the first assembly was installed in LGS 

Unit 2 in March 2005.

Regarding fatigue usage, the LRA states that the jet pump auxiliary spring wedge assembly is 

not an ASME Code component; however, the ASME Code was used as a guideline to evaluate 

stress and fatigue limits. As such, the assembly was designed for cumulative fatigue usage for 

applicable Service Level B loads to be less than the allowable limit of 1.0. The LRA also states 

that the original design basis load cycles from the reactor vessel thermal cycle diagram were 

applied and these transients are the same as in UFSAR Table 3.9-2, “Plant Events.” The 

resulting fatigue usage for the 40-year design was determined to be 0.77, which is below the 

allowable limit of 1.0. LRA Tables 4.3.1-1 and 4.3.1-2 show the 60-year transient projections for 
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LGS and demonstrate that these transient cycle limits will not be exceeded in 60 years of 

operation.

Regarding relaxation in preload caused by neutron fluence, the LRA states that the original 

design analysis included an evaluation based on an integrated neutron fluence of 

1.4 E+20 n/cm2 for a 40-year design life. In order to evaluate relaxation in preload for the period 

of extended operation, fluence projections for the jet pump riser brace welds at the RS-9 

locations were determined with the RAMA computer code. The LRA states that the fluence 

projections for the RS-9 weld locations bound projections for the auxiliary spring wedge 

assemblies, because the RS-9 welds are located at approximately the 304-inch elevation, while 

the auxiliary spring wedge assemblies are located at approximately the 230-inch elevation 

where fluence values are lower. The fluence projections through the period of extended 

operation were determined to be 1.30 E+20 n/cm2 for LGS Unit 1 and 1.33 E+20 n/cm2 for LGS 

Unit 2, which are both less than the 1.4 E+20 n/cm2 fluence value used in the original design.

The applicant dispositioned the TLAA for the jet pump auxiliary spring wedge assemblies, in 

accordance with 10 CFR 54.21(c)(1)(i), indicating that the analysis remains valid for the period 

of extended operation.

4.6.5.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the jet pump auxiliary spring wedge assemblies 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, which state that the existing analyses should be shown to be 

bounding during the period of extended operation.

Concerning fatigue usage, the applicant’s analysis is based on its projections that the number of 

design cycles will not be exceeded during the period of extended operation. The applicant 

stated that the number of cycles used in the design of the auxiliary spring wedge assemblies is 

from UFSAR Table 3.9-2. LRA Section 4.6.5 states LRA Tables 4.3.1-1 and 4.3.1-2 show the 

60-year transient projections and demonstrate that these transient cycle limits will not be 

exceeded in 60 years of operation. However, since this TLAA relies on 60-year projections that 

are dependent on the Fatigue Monitoring program (i.e., managing the number of cycles), the 

staff was not clear on the implications for cases in which the Fatigue Monitoring program may 

determine that a transient cycle count reaches a cycle limit. By letter dated November 18, 2011, 

the staff issued RAI B.3.1-1, requesting the applicant provide clarification.

In its response dated December 7, 2011, the applicant confirmed that the TLAA for the jet pump 

auxiliary spring wedge assembly is within scope of the Fatigue Monitoring program and based 

on the same set of design transients that this program monitors and trends. As such, the 

applicant confirmed that its procedures require its engineers to initiate corrective action to 

demonstrate the design limit will not be exceeded before or during the period of extended 

operation; otherwise, further action for repair or replacement of the component, or other 

methods approved by the staff will be taken. The staff determined in SER Section 3.0.3.2.20, 

that the applicant ensures that the results from its 60-year projections used to disposition the 

TLAA for RVI in accordance with 10 CFR 54.21(c)(1)(i), will remain valid during the period of 

extended operation, otherwise corrective actions will be taken.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the TLAA 

for the jet pump auxiliary spring wedge assembly based on fatigue, remain valid for the period of 
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extended operation. Additionally, it meets the acceptance criteria in SRP-LR Section 4.7.2.1 

because the projected number of transient cycles over the period of extended operation is not 

expected to exceed the design cycle limit used in the jet pump auxiliary spring wedge assembly 

fatigue analysis. The applicant also confirmed that this analysis is within the scope of the 

Fatigue Monitoring program, which ensures that the results from its projections used to 

disposition this fatigue TLAA will remain valid during the period of extended operation;

otherwise, corrective actions will be taken.

Concerning relaxation in preload caused by neutron fluence, the applicant’s analysis is based 

on demonstrating that the projected fluence values (using RAMA) at the RS-9 weld, which 

attaches the riser brace to the riser pipe and part of the jet pump assembly in the reactor vessel 

internals, bounds the fluence at the auxiliary spring wedge assemblies. The staff approved the 

use of RAMA for BWR pressure vessel fluence projections, but its use for reactor vessel 

internals applications is subject to staff’s review on a case-by-case basis. Therefore, it was not 

clear why the use of RAMA is appropriate to project fluence at the RS-9 weld and why the 

fluence values at the auxiliary spring wedge assemblies would be lower than the fluence values 

at the RS-9 weld. By letter dated December 15, 2011, the staff issued RAI 4.6.5-1 requesting 

the applicant justify the use of RAMA for the RS-9 welds and why the fluence values at this 

location is bounding for the auxiliary spring wedge assemblies. 

In its response dated January 24, 2012, the applicant stated that the staff evaluated use of 

RAMA for RPV and internal components of BWR plants in an SE dated May 13, 2005. The 

applicant indicated that the safety evaluation further states that, “if a licensee qualifies RAMA for 

calculating, for example, helium generation at one location (e.g., the core shroud), this qualifies 

RAMA for the same reactor and purpose at other reactor internals locations (e.g., the jet 

pumps).” 

As documented in the NRC SE dated February 7, 2008, the staff reviewed EPRI 

Report 1011694, “BWR Vessel and Internals Project, Evaluation of Susquehanna Unit 2 Top 

Guide and Core Shroud Material Samples Using RAMA Fluence Methodology (BWRVIP-145),” 

dated November 2005, for its suitability in applying the RAMA fluence methodology to the 

calculation of fast neutron fluence values for BWR vessel internals, specifically the core shroud 

and top guide. The applicant highlighted a passage in the summary of this SE, which states 

that “the staff finds that for applications such as IASCC, crack propagation rates, and weldability 

determinations, the RAMA methodology can be used in determining fast neutron fluence values 

in the core shroud and top guide.” The applicant also compared its case to that of 

Susquehanna Steam Electric Station (SSES) Unit 2. Specifically, LGS Units 1 and 2 are of the 

GE Type 4 BWR design, which is the same as SSES Unit 2, with 251-inch inside diameter 

reactors, 764 fuel bundles, and core shrouds with a 207-inch outside diameter. The applicant 

stated that since RAMA may be used at SSES Unit 2, for core shroud and top guide 

applications, it may also be used for the same applications at LGS Units 1 and 2.

The staff reviewed and addressed the applicant’s use of RAMA methodology separately in 

Section 4.2.1.2 of this SER. The following evaluation covers the applicant’s justification for the 

use of fluence projection at the RS-9 weld location to bound analysis for the jet pump auxiliary 

spring wedge assemblies.

The applicant stated in its response to RAI 4.6.5-1 dated January 24, 2012, that there are five 

jet pump welds located at different elevations in the reactor vessel. For each of these welds the 

applicant provided the associated elevation in the reactor vessel and the projected fluence 
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values at 57 EFPY calculated using RAMA. The staff noted that the data show that the fluence 

decreases as elevation decreases below the 304-inch elevation where the RS-9 weld is located. 

The staff noted that the jet pump auxiliary spring wedge assemblies are located at the 230-inch 

elevation, which is in between the RS-9 weld and RS-2 weld; therefore, the staff finds that this 

data adequately demonstrates that fluence values at the RS-9 weld location will be higher than 

at the jet pump auxiliary spring wedge assemblies through 57 EFPY. Thus, use of the fluence 

at the RS-9 weld location is conservative for the jet pump auxiliary spring wedge assemblies.

The applicant also stated that the jet pump auxiliary spring wedge assemblies for LGS Units 1 

and 2 were installed in March 2004 and March 2005, respectively. As a result, they will be 

exposed to fluence of 30 EFPY and 33.6 EFPY, respectively, through the period of extended 

operation. The applicant explained that the fluence values described in LRA Section 4.6.5 were 

derived from the 57 EFPY fluence values for the RS-9 weld by subtracting the fluence that had 

occurred before the installation dates. The staff finds the calculation of fluence values for the jet 

pump auxiliary spring wedge assemblies based on subtracting the fluence before installation of 

the assemblies from the fluence projected through 57 EFPY acceptable because the 

assemblies were not exposed to fluence before their installation. The staff noted that the 

fluence projections through the period of extended operation were determined to be 

1.30 E+20 n/cm2 for LGSUnit 1 and 1.33 E+20 n/cm2 for LGS Unit 2. In addition, the applicant 

stated in its response that the fluence value used in the original design is 1.4 E+20 n/cm2

.

The staff finds the applicant’s response acceptable, related to use of RAMA fluence 

methodology, because the fluence values used to demonstrate validity of the auxiliary spring 

wedge assemblies analysis are conservative, as described above, and these conservative 

fluence values are less than the fluence value used in the original design of these components. 

The staff’s concerns described in RAI 4.6.5-1 are resolved. 

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the TLAA for the jet pump auxiliary spring wedge assemblies remain valid for the period of 

extended operation. Additionally, the analysis meets the acceptance criteria in SRP-LR 

Section 4.7.2.1 because the fluence values for the jet pump auxiliary spring wedge assemblies 

at the end of the period of extended operation is less than the value used in the design 

specification for these components that analyzed relaxation of preload.

4.6.5.3 UFSAR Supplement 

LRA Section A.4.6.5 provides the UFSAR supplement summarizing the TLAA for fatigue usage 

and relaxation in preload caused by neutron fluence of the jet pump auxiliary spring wedge 

assemblies. The staff reviewed LRA Section A.4.6.5 consistent with the review procedures in 

SRP-LR Section 4.7.3.2, which state 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.

Based on its review of the UFSAR supplement, the staff finds that the supplement meets the 

acceptance criteria in SRP-LR Section 4.7.2.2. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the fatigue usage 

and relaxation in preload caused by neutron fluence of the jet pump auxiliary spring wedge 

assembly TLAAs, as required by 10 CFR 54.21(d).
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4.6.5.4 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 analyses for the jet pump 

auxiliary spring wedge assemblies remain 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).

4.6.6 Jet Pump Restrainer Bracket Pad Repair Clamps

4.6.6.1 Summary of Technical Information in the Application 

LRA Section 4.6.6 describes the applicant’s TLAA for the jet pump restrainer bracket pad repair 

clamps. The LRA states that the repair clamps have been designed and installed to replace the 

support function of the restrainer bracket pad and end-of-life preload relaxation for 40 years was 

considered in the design analysis. The repair clamp uses four clamping bolts, which in order to 

maintain clamping under all operating conditions, must have a preload larger than the limiting 

lateral load of 2,059 lbs. In addition, the LRA states that fatigue was considered in the design 

analysis; however, the stress amplitude for cyclic loads was determined to be well below the 

ASME Code limit of 13,600 psi for 1011 cycles and less than the 10,000 psi limit for flow-induced 

vibration.

The applicant dispositioned the TLAA for the jet pump restrainer bracket pad repair clamps in 

accordance with 10 CFR 54.21(c)(1)(ii), indicating that the analysis has been projected to the 

end of the period of extended operation.

4.6.6.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the jet pump restrainer bracket pad repair clamps 

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, which state that the results of the revised analysis 

should be reviewed to verify that their period of evaluation is extended, such that they are valid 

for the period of extended operation.

Loss of Preload

The applicant’s analysis is based on the assumption that the preload will decrease 5 percent 

over an additional 20 years of operation, which is the same decrease predicted over the 

40 years considered in the original design analysis; however, the LRA does not provide a 

justification for this assumption. By letter dated December 15, 2011, the staff issued 

RAI 4.6.6-1 requesting the applicant to justify this assumption.

In its response dated January 24, 2012, the applicant amended the LRA to provide a revised 

TLAA for the jet pump restrainer bracket pad repair clamps and changed the disposition to 

10 CFR 54.21(c)(1)(i). For the revised TLAA, the applicant stated that a fluence value of 

1.0 E+19 n/cm2 was used in the design analysis to determine loss of preload, and this value is 

5 percent higher than the 9.5 E+18 n/cm2 value calculated for a 40-year service life. Therefore, 

the applicant concludes that the design analysis includes an allowance for loss of preload that is 

valid for 105 percent of 40 years (i.e., 42 years). The applicant stated that no clamps have been 

installed in LGS Unit 1 and the first clamps were installed in LGS Unit 2 in April 2009. Since the 
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period of extended operation for LGS Unit 2 ends on June, 22, 2049, the applicant stated that 

the clamps will have a maximum service life of 40.25 years, which is less than 42 years.

The fluence value of 1.0 E+19 n/cm2 used to determine the loss of preload and the calculated 

fluence value of 9.5 E+18 n/cm2 for a 40-year service life were part of the original design 

analysis for the jet pump restrainer bracket pad repair clamps. The staff noted that in the design 

analysis the applicant used a larger fluence value to determine the loss of preload than was 

expected after a 40-year service life for these components. Thus, the staff finds it reasonable 

that the amount of time to accumulate the fluence used in the design analysis (1.0 E+19 n/cm2

) 

would be more than 40 years.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the fluence TLAA for the jet pump restrainer bracket pad repair clamps remains valid for the 

period of extended operation. Additionally, the applicant meets the acceptance criteria in 

SRP-LR Section 4.7.2.1 because the time needed to accumulate the fluence used in the design 

analysis to determine loss of preload (i.e., 42 years) is greater than the amount of time the 

pump auxiliary spring wedge assemblies will be in service through the period of extended 

operation (i.e., 40.25 years).

With respect to the applicant’s calculation of the fluence projections, the staff’s review of the 

applicant’s use of the RAMA fluence methodology is documented in SER Section 4.2.1.2.

Fatigue

The applicant’s analysis is based on the determination in the design that the stress amplitude 

for cyclic loads is below the ASME Code limit of 13,600 psi for 1011 cycles and less than the 

10,000 psi limit for flow-induced vibration. The staff reviewed LRA Section 4.6.6 and noted that 

one disposition was provided, which states that the analysis has been projected to the end of 

the period of extended operation. However, for fatigue, it is not clear how the applicant 

projected the analysis because it did not describe the changes to any parameters of the original 

analysis. By letter dated December 15, 2011, the staff issued RAI 4.6.6-2 requesting the 

applicant to provide and justify the disposition for the fatigue portion of this TLAA.

In its response dated January 24, 2012, the applicant dispositioned the fatigue analysis under 

10 CFR 54.21(c)(1)(i) and stated that the clamping loads do not cycle except for the load 

changes associated with startup and shutdown temperature changes. The largest alternating 

stress amplitude resulting from these temperature changes is 7,781 psi. In addition, the 

restrainer bracket is fabricated from Type 304 stainless steel, which has a stress intensity limit 

of 16,000 psi at 550 °F and yield strength of 17,750 psi at 550 °F. The applicant stated that the 

ASME Code stress limit is 13,600 psi for 1011 cycles and the GE Hitachi design limit for 

flow-induced vibration stress cycles is 10,000 psi. Thus, the applicant concluded that the 

fatigue usage will be insignificant since the cyclic loads of 7,781 psi are less than both of these 

limits.

The staff noted that a material exhibits an endurance limit in which fatigue damage is not 

expected to occur, which occurs when an alternating stress value is independent of the number 

of loading cycles. The staff finds the applicant’s response acceptable because the applicant 

demonstrated that the alternating stresses in the jet pump restrainer bracket pad repair clamps 

are below the applicable endurance limits specified in the ASME Code and, therefore, fatigue 

damage will not occur. The staff’s concern described in RAI 4.6.6-2 is resolved. 
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The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the fatigue TLAA for the jet pump restrainer bracket pad repair clamps remains valid for the 

period of extended operation. Additionally, the applicant meets the acceptance criteria in 

SRP-LR Section 4.7.2.1 because the alternating stresses experienced by these components are 

less than the endurance limit specified in the ASME Code for this material and less than the 

design limit for flow-induced vibrations.

4.6.6.3 UFSAR Supplement 

LRA Section A.4.6.6 provides the UFSAR supplement summarizing the TLAA for the jet pump 

restrainer bracket pad repair clamps. The staff reviewed LRA Section A.4.6.5 consistent with 

the review procedures in SRP-LR Section 4.7.3.2, which state 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.

LRA Section A.4.6.6 provides the UFSAR supplement summary description for the TLAA 

evaluation of the jet pump restrainer bracket pad repair clamps described in LRA Section 4.6.6. 

However, a summary description for the analysis of fatigue was not provided. By letter dated 

December 15, 2011, the staff issued RAI 4.6.6-3 requesting the applicant to provide a summary 

description of the TLAA evaluation for fatigue of the jet pump restrainer bracket pad repair 

clamps in the UFSAR supplement.

In its response dated January 24, 2012, the applicant revised LRA Section A.4.6.6 to include a 

summary description of the TLAA evaluation for fatigue. The staff reviewed the revised LRA 

Section A.4.6.6 and finds it acceptable because it provides a summary description of the 

evaluation for fatigue consistent with the applicant’s response to RAI 4.6.6-2. The staff’s 

concern described in RAI 4.6.6-3 is resolved. 

Based on its review of the UFSAR supplement, the staff finds that the supplement meets the 

acceptance criteria in SRP-LR Section 4.7.2.2. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address loss of preload 

and fatigue of the jet pump restrainer bracket pad repair clamp TLAAs, as required by 

10 CFR 54.21(d).

4.6.6.4 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 analyses for the jet pump 

restrainer bracket pad repair clamps remain 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).

4.6.7 Refueling Bellows and Support Cyclic Loading Analysis

4.6.7.1 Summary of Technical Information in the Application 

LRA Section 4.6.7 describes the applicant’s TLAA for the refueling bellows that provides a 

flexible seal to prevent leakage from the reactor well during refueling operations when it is 

flooded to permit fuel movement. The LRA states that the refueling bellows and refueling 
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bellows support were analyzed for cycles predicted to bound 40 years of operation and that the 

fatigue analysis was identified as a TLAA that requires evaluation for 60 years. Since the 

refueling outages are scheduled once every 2 years, the 123 cycles will remain bounding for 

60-years of operation. Furthermore, the LRA referred to section 4.3.1 that describes the 

applicant’s TLAA for ASME Code, Section III, Class 1 fatigue analyses. 60-year transient 

projections were developed by using transient cycle monitoring data from the Fatigue Monitoring 

program. The projections show that the current design cycle limits will not be exceeded during 

60 years of plant operation for LGS Unit 1 and LGS Unit 2. The Fatigue Monitoring program will 

also be used to monitor and track transient cycle occurrences through the end of the period of 

extended operations to ensure that these limits are not exceeded. The program includes 

requirements that trigger corrective action if a transient approaches a cycle limit. 

The applicant dispositioned the TLAA for the refueling bellows and refueling bellows support in 

accordance with 10 CFR 54.21(c)(1)(i), that the analyses remain valid for the period of extended 

operation.

4.6.7.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the refueling bellows and refueling bellows support 

cyclic loading analysis and the corresponding disposition of 10 CFR 54.21(c)(1)(i), consistent 

with the review procedure in SRP–LR Section 4.7.3.1.1, which states that the existing analyses 

should be shown to be bounding even during the period of extended operation. In some 

instances, the applicant may identify activities to be performed to verify the assumption basis of 

the calculation, such as cycle counting.

LRA Section 4.3.1 states that the projections show that the current design cycle limits will not be 

exceeded during 60 years of plant operation for LGS Units 1 and 2; therefore, none of the 

transient types are expected to be exceeded during the period of extended operation and the 

ASME Code, Section III, Class 1 fatigue analyses will remain valid for the period of extended 

operation. The staff noted that since the applicant’s assumption relies on the fact that the rate 

of cycle occurrence in the future will not exceed the average rates of occurrence of past cycles, 

the applicant trended each transient projection to determine if recent rates of occurrence could 

be higher than the overall average rates of occurrence. The applicant demonstrated, through

such trending, that recent transient occurrence rates are bounded by the average occurrence 

rates. However, the staff noted that in order to assure that this conclusion and basis remains 

valid for transient projections and trending, the Fatigue Monitoring program will be used to 

monitor and track transient cycle occurrences through the end of the period of extended 

operation to ensure that these limits are not exceeded.

However, since this TLAA relies on the 60-year projections that the Fatigue Monitoring program 

is assuring will remain valid throughout the period of extended operation, it is not clear to the 

staff if the validity of this TLAA will be confirmed if the program determines that a transient cycle 

count reaches a cycle limit. By letter dated November 18, 2011, the staff issued RAI B.3.1-1, 

requesting the applicant provide clarification.

In its response dated December 7, 2011, the applicant confirmed that the refueling bellows 

TLAA is within the scope of the Fatigue Monitoring program and is based on the same set of 

design transients that this program monitors and trends. The applicant confirmed that its 

procedures require its engineers to initiate corrective action to demonstrate the design limit will 

not be exceeded before or during the period of extended operation; otherwise, further action for 

repair of the component, replacement of the component, or other methods approved by the 
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NRC will be taken. The staff determined in SER Section 3.0.3.2.20, that the applicant

continually ensures that the results from its 60-year projections used to disposition the refueling 

bellows TLAA in accordance with 10 CFR 54.21(c)(1)(i), will remain valid during the period of 

extended operation, otherwise corrective actions will be taken.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the TLAA 

for the refueling bellows and refueling bellows support analyses based upon fatigue, remain 

valid for the period of extended operation. Additionally, the applicant meets the acceptance 

criteria in SRP-LR Section 4.7.3.1.1 because the projected number of transient cycles over the 

period of extended operation is not expected to exceed the design cycle limits. The applicant 

also is crediting its Fatigue Monitoring program to assure that the assumptions in the Class 1 

fatigue analyses remain valid during the period of extended operation; otherwise the applicant 

will take corrective actions in accordance with its program. 

4.6.7.3 UFSAR Supplement 

LRA Section A.4.6.7 provides the UFSAR supplement summarizing the refueling bellows and 

supports TLAA. The staff reviewed LRA Section A.4.6.7, consistent with the review procedures 

in SRP–LR Section 4.7.3.2, which states 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 each TLAA. 

Based on its review of the UFSAR supplement, the staff finds that the supplement meets the 

acceptance criteria in SRP–LR Section 4.7.3.2. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to demonstrate that the 

refueling bellows and refueling bellows support 40-year cycle limits will not be exceeded in 

60 years based on the average rate of occurrence to-date, as required by 10 CFR 54.21(d).

4.6.7.4 Conclusion 

On the basis of its review the staff concludes that the applicant provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the analysis for the refueling bellows and 

refueling bellows support remain valid for the period of extended operation. The staff also 

concludes that the UFSAR supplement contains an adequate summary description of the 

evaluated TLAAs, as required by 10 CFR 54.21(d).

4.6.8 Downcomers and MSRV Discharge Piping 

4.6.8.1 Summary of Technical Information in the Application 

LRA Section 4.6.8 describes the applicant’s fatigue TLAA for the downcomers and MSRV 

discharge piping. MSRV cycles were considered to account for the pool dynamic loads, which 

are based on 1,100 actuations of all MSRVs. In addition, the MSRV quenchers were analyzed 

for opening and closing cycles and irregular condensation load cycles. Since the piping and 

components were evaluated for transient cycles expected to occur in 40 years, these analyses 

have been identified as TLAAs that require evaluation for the period of extended operation. The 

applicant dispositioned the fatigue TLAA for the downcomers and MSRV discharge piping in 

accordance with 10 CFR 54.21(c)(1)(i) to demonstrate that the analysis remains valid for the 

period of extended operation.
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4.6.8.2 Staff Evaluation 

The staff reviewed LRA Section 4.6.8 and the fatigue TLAA for the downcomers and MSRV 

discharge piping 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. The SRP-LR provides guidance for the staff to 

review the justification provided by the applicant to verify that the existing analyses are valid for 

the period of extended operation. 

LRA Section 4.6.8 states that a minimum of 7,700 MSRV cycles were considered to account for 

the pool dynamic loads. In addition, for the most frequently actuated MSRVs, the analysis was 

based on three stress cycles per each of the 4,700 actuations (14,100 total cycles). The LRA 

states the total number of MSRV lift cycles has been projected, and it will not exceed the 

number analyzed for 40 years. The applicant did not provide its current accumulated number of 

MSRV cycles or the 60-year projected number of MSRV cycles; therefore, the staff could not 

verify the adequacy of the applicant’s TLAA disposition. The staff reviewed LRA Tables 4.3.1-1 

and 4.3.1-2 and could not determine the transient associated with the MSRV cycle. By letter 

dated January 31, 2012, the staff issued RAI 4.6.8-1 requesting the applicant to identify the 

transients used in the fatigue analysis for the downcomers, including the current accumulated 

number and 60-year projected number for each transient.

In its response dated February 29, 2012, the applicant stated that two types of loads were 

considered in the fatigue evaluation of the downcomers and bracing: (1) seismic effects and 

cyclic loads caused by hydrodynamic effects, including MSRV actuations; and (2) LOCA-related 

condensation oscillation and chugging cycles. These components were analyzed for a 

minimum of 7,700 MSRV stress cycles to account for the pool hydrodynamic loads, which was 

based on seven stress cycles per each of the 1,100 actuations. The applicant also stated that 

these components were also evaluated for 3,000 chugging cycles that occur following a LOCA 

event, 50 operational basis earthquakes (OBE) cycles (5 events with 10 stress cycles per 

event), and 10 safe-shutdown earthquakes (SSE) cycles (1 event with 10 cycles). The staff 

confirmed that UFSAR Figure 3A-394 indicates that the cycles associated with chugging, OBEs, 

and SSEs are included in the fatigue analysis for the downcomers.

Based on its review, the staff finds the applicant’s response to this portion of RAI 4.6.8-1 

acceptable because the applicant identified all the transients used as an input to the fatigue 

analysis of the downcomers and bracing, which will be monitored by the Fatigue Monitoring 

program to ensure that these fatigue analyses remain valid during the period of extended 

operation.

Also, in its response to RAI 4.6.8-1, the applicant addressed the historical cycle accumulation 

and future cycle projection for the transients discussed above. The applicant stated that MSRV 

actuation cycles were not monitored since original plant startup and an operational review 

during the development of the LRA was performed to determine when each MSRV was 

actuated. The applicant stated that it reviewed surveillance tests that actuated MSRVs, monthly 

operating reports that documented operational MSRV actuations, and the fatigue monitoring 

data for other events that resulted in MSRV actuations. 

Based on a review of its operating history, the applicant determined that the cumulative number 

of MSRV actuations for LGS Unit 1 through January 2011 was 90 (56 actuations during startup 

testing before commercial operation, 30 actuations caused by surveillance testing performed 

following the first 6 refueling outages, and 4 actuations during normal operation). The 
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applicant’s surveillance test required each of the five automatic depressurization system ADS 

valves to be opened once during each startup after a refueling outage; however, the applicant 

stated that this surveillance test requirement was eliminated in 1997. The applicant stated the 

60-year projection for LGS Unit 1 MSRV actuations is 211, which is based upon a linear 

extrapolation of the MSRV actuation data using the average rate of occurrence through 

January 2011. Similarly, the applicant determined the cumulative number of MSRV actuations 

for LGS Unit 2 through January 2011 was 49 (32 actuations during startup testing before

commercial operation, 15 caused by surveillance testing following the first three refueling 

outages before1997, and 2 actuations during normal operation). Similar to LGS Unit 1, the

surveillance test for LGS Unit 2 was also eliminated. The 60-year projection for LGS Unit 2

MSRV actuations is 138, which is based on a linear extrapolation of the MSRV actuation data 

using the average rate of occurrence through January 2011.

The applicant stated that LOCA-related loads include condensation oscillation and 

3,000 chugging cycles that account for pulsating condensation of the steam flow exiting the 

downcomers. The staff noted that UFSAR 3A.7.1.1.1.1.5.2 explains that the main LOCA-related 

forcing functions are the condensation oscillation and chugging cycles. Thus, the staff finds it 

reasonable that the applicant monitors the occurrence of the LOCA event to account for the 

condensation oscillation and chugging cycles. The applicant monitors Transient No. 18, 

“Faulted Condition – Pipe Rupture and Blowdown,” which corresponds with a large-break 

LOCA. The applicant also stated that no such event has occurred in either unit and that its 

records also show that no OBE or SSE event has occurred. The applicant stated that since 

there have been no occurrences for these transients, the design limits of one LOCA-related 

event, one OBE event, and one SSE event in LRA Tables 4.3.1-1 and 4.3.1-2 are not projected 

to be exceeded in 60 years for LGS Units 1 or 2.

The staff finds the applicant’s estimated number of accumulated cycles through January 2011 

for MSRV actuation to be reasonable because it is based on pre-operational and surveillance 

tests, which are no longer performed. In addition, the use of a linear extrapolation is 

conservative because the applicant considered the time period when it experienced frequent 

transient occurrences and did not consider only the time period when it discontinued the 

surveillance test. The staff noted that the number of cycles through the period of extended 

operation for both units is expected to be no more than 20 percent of the 1,100 allowable cycle 

limit; therefore, there is a significant margin to account for unanticipated cycles of the MSRV 

actuations through the period of extended operation. 

Based on its review, the staff finds this portion of the applicant’s response to RAI 4.6.8-1 

acceptable because the past occurrences for the transients used in these fatigue analyses were 

reconciled based on documented operating data and records and the applicant’s 60-year 

projections are conservative, as described above.

In its response to RAI 4.6.8-1, the applicant also revised LRA Tables 4.3.1-1 and 4.3.1-2 to 

include Transient No. 20, “MSRV Actuations,” with a limit of 1,100 MSRV actuations. In 

addition, these tables were also revised to include the monitoring results for the faulted 

condition events already monitored by the Fatigue Monitoring program, which include Transient 

No. 18, “Pipe Rupture and Blowdown,” and Transient No. 19, “Safe Shutdown Earthquake at 

Rated Operating Conditions.” The applicant further explained that since the Fatigue Monitoring 

program monitors each of the transients analyzed for the downcomers, or in the case of 

condensation oscillation and chugging cycles, it monitors correlated LOCA events, the 

disposition of the fatigue TLAA for the downcomers in LRA Section 4.6.8 and UFSAR 
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supplement Section A.4.6.8 is revised from 10 CFR 54.21(c)(1)(i) to 10 CFR 54.21(c)(1)(iii). 

The staff’s review of the Fatigue Monitoring program is documented in SER Section 3.0.3.2.20. 

The staff determined that the program monitors and tracks the number of critical thermal, 

pressure, and seismic transients to assure that the cumulative number of occurrences of each 

transient type is maintained below the number of cycles used in the fatigue analysis. 

Based on its review, the staff finds this portion of the applicant’s response to RAI 4.6.8-1 

acceptable because the applicant’s TLAA credits the Fatigue Monitoring program to monitor the 

transients assumed in the analysis, thus, ensuring that the MSRV downcomers fatigue analysis

remains valid during the period of extended operation. The staff’s concerns described in 

RAI 4.6.8-1 are resolved. 

LRA Section 4.6.8 states the quenchers were analyzed for 7,000 SRV opening and closing 

cycles and LOCA-related irregular condensation load cycles. The applicant did not provide the 

accumulated and 60-year projected numbers for the SRV cycles and irregular condensation 

load cycles; therefore, the staff cannot verify the adequacy of the TLAA disposition in 

accordance with 10 CFR 54.21(c)(1)(i). The staff reviewed LRA Tables 4.3.1-1 and 4.3.1-2 and 

could not determine the transients associated with these two transient cycles.

By letter dated January 31, 2012, the staff issued RAI 4.6.8-2 requesting the applicant to identify 

the transients used in the fatigue analysis for the MSRV discharge piping and quenchers, 

including the accumulated number and 60-year projected number for each transient.

In its response dated February 29, 2012, the applicant stated that two types of loads were 

considered in the fatigue evaluations, which include thermal and pressure transients and cyclic 

loads (i.e., MSRV actuations, LOCA-related condensation oscillation and chugging, and seismic 

effects). The applicant stated that the thermal transients used in the fatigue analysis include 

those identified in LRA Tables 4.3.1-1 and 4.3.1-2. The staff reviewed UFSAR 

Section 3A.7.1.5.1.1 and confirmed that these transients were used in the fatigue evaluations 

for the MSRV discharge piping and quenchers. 

The applicant also stated that the MSRV discharge loads include a minimum of 7,700 MSRV 

stress cycles to account for the pool hydrodynamic loads, which is based on 1,100 actuations of 

all MSRVs. The LOCA-related loads include condensation oscillation loads and 3,000 chugging 

cycles. The seismic loads include 50 OBE cycles (5 events with 10 stress cycles per event), 

and 10 SSE cycles (1 event with 10 cycles). The applicant stated that the quenchers at the 

ends of the MSRV discharge lines were analyzed for 7,000 MSRV actuations and one million 

irregular condensation cycles. Based on its review, the staff finds this portion of the applicant’s 

response acceptable because the applicant identified all the transients used in the fatigue 

analyses of the MSRV discharge piping and quenchers and the Fatigue Monitoring program 

monitors these transients to ensure these fatigue analyses will remain valid during the period of 

extended operation. 

In its response to RAI 4.6.8-2, the applicant also addressed the historical cycle accumulation 

and future cycle projection for these transients. The applicant stated that the thermal transients 

described previously other than MSRV actuations have been monitored since original plant 

startup, as shown in LRA Tables 4.3.1-1 and 4.3.1-2. As discussed in the response to 

RAI 4.6.8-1, MSRV actuation cycles were not monitored since original plant startup and an 

operational review during development of the LRA was performed to determine when each 

MSRV was actuated during preoperational startup testing and during all past plant operations 
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for each unit. The 60-year projections of the MSRV actuation are 211 for LGS Unit 1 and 138 

for LGS Unit 2, and the projection methodology is also discussed in the response to RAI 4.6.8-1. 

The staff’s review of the applicant’s estimate of the historical occurrences and future projections 

are documented in the review of RAI 4.6.8-1. The staff noted that the number of cycles through 

the period of extended operation for both units is expected to be no more than 20 percent of the 

1,100 allowable cycles; therefore, there is a significant margin to account for unanticipated 

cycles of the MSRV actuations. 

The applicant further stated that it does not directly monitor chugging cycles or irregular 

condensation cycles. Rather, it monitors Transient No. 18, “Faulted Condition – Pipe Rupture 

and Blowdown,” which corresponds with a large-break LOCA. UFSAR Section 3B.4.1.3.5 

explained that the LOCA-related forcing function on the quenchers consists of 

1,000,000 irregular condensation cycles. Thus, the staff finds it reasonable that the applicant 

monitors the occurrence of the LOCA event instead of 1,000,000 irregular condensation cycles. 

The applicant stated no LOCA event has occurred in either unit and records also show that no 

OBE or SSE event has occurred. Since no transients that cause chugging and irregular 

condensation cycles have occurred to-date in either unit, the staff finds it reasonable to 

conclude that no chugging and irregular condensation cycle have occurred either. The 

applicant stated that since there has been zero occurrences for these transients, the design 

limits of one LOCA-related event, one OBE event and one SSE event in LRA Tables 4.3.1-1 

and 4.3.1-2 are not projected to be exceeded in 60 years for LGS Units 1 or 2.

Based on its review, the staff finds this portion of the applicant’s response to RAI 4.6.8-2 

acceptable because the past occurrences for the transients used in these fatigue analyses were 

reconciled based on documented operating data and records and the applicant’s 60-year 

projections are conservative, as described above.

Finally, in its response to RAI 4.6.8-2, the applicant revised LRA Tables 4.3.1-1 and 4.3.1-2 to 

include Transient No. 20, “MSRV Actuations.” The disposition of the MSRV discharge piping 

and quenchers fatigue TLAA in LRA Section 4.6.8 and UFSAR supplement Section A.4.6.8 is 

also revised from 10 CFR 54.21(c)(1)(i) to 10 CFR 54.21(c)(1)(iii), crediting the Fatigue 

Monitoring program for managing the effects of fatigue. The staff’s review of the Fatigue 

Monitoring program is documented in SER Section 3.0.3.2.20. The staff determined that the 

program monitors and tracks the number of critical thermal, pressure, and seismic transients to 

ensure that the cumulative number of occurrences of each transient type is maintained below 

the number of cycles used in the fatigue analysis. 

Based on its review, the staff finds the remainder of the applicant’s response to RAI 4.6.8-2, 

acceptable because the applicant credits the Fatigue Monitoring program to monitor the 

transients assumed in the analysis, thus, ensuring the validity of the MSRV discharge piping 

and quenchers fatigue analysis during the period of extended operation. The staff’s concerns 

described in RAI 4.6.8-2 are resolved. 

The staff determined that the Fatigue Monitoring program monitors and tracks the number of 

critical thermal, pressure, and seismic transients to ensure that the cumulative number of 

occurrences of each transient type is maintained below the number of cycles used in the fatigue 

analysis. The staff noted that the program requires comparison of the actual event parameters 

to the applicable design transient definitions to ensure that the actual transients are bounded by 

the applicable design transients. If a transient approaches an action limit, which the applicant 

has set to 80 percent of the cycle limit, corrective actions are initiated for repair, replacement, or 
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reanalysis of the component, in accordance with its Fatigue Monitoring program. The staff 

determined that these characteristics of the Fatigue Monitoring program are consistent with 

GALL Report AMP X.M1.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of fatigue of the downcomers and MSRV discharge piping will be adequately 

managed for the period of extended operation. Additionally, the applicant has met the 

acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because it is crediting its Fatigue Monitoring 

program, which the staff has determined is consistent with GALL Report AMP X.M1, to manage 

metal fatigue by ensuring the assumptions in these fatigue analyses remain valid for the period 

of extended operation.

4.6.8.3 UFSAR Supplement 

LRA Section A.4.6.8, as amended by letter dated February 29, 2012, provides the UFSAR 

supplement summarizing the fatigue TLAA for the downcomers and MSRV discharge piping. 

The staff reviewed LRA Section A.4.6.8, consistent with the review procedures in SRP-LR 

Section 4.7.3.2, which states 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. 

Based on its review of the UFSAR supplement, the staff finds that the supplement meets the 

acceptance criteria in SRP-LR Section 4.7.2.2. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the fatigue TLAA 

for the downcomers and MSRV discharge piping, as required by 10 CFR 54.21(d).

4.6.8.4 Conclusion 

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that effects of fatigue for the 

downcomers and MSRV discharge piping will be adequately managed for the period of 

extended operation. The staff also concludes that the UFSAR supplement contains an 

adequate summary description of the evaluated TLAA, as required by 10 CFR 54.21(d).

4.6.9 Jet Pump Slip Joint Repair Clamps 

4.6.9.1 Summary of Technical Information in the Application 

LRA Section 4.6.9 describes the applicant’s TLAA for the jet pump slip joint repair clamps. The 

LRA states that the repair clamps minimize vibration and wear of the jet pump assemblies by 

applying a lateral preload to the slip joint between the exit end of the inlet-mixer and the 

entrance end of the diffuser. The LRA states that the jet pumps and repair hardware will be 

periodically inspected under the BWR Vessel Internals program and aging effects included 

within the scope of these inspections include cracking, wear, and bolt loosening. As such, the 

loss of preload will be managed during the period of extended operation.

The applicant dispositioned the TLAA for the jet pump slip joint repair clamps in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of loss of preload caused by neutron fluence on the 

intended functions will be adequately managed by the BWR Vessel Internals program for the 

period of extended operation.
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4.6.9.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the jet pump slip joint repair clamps 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, which state that the applicant’s AMP should be reviewed 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.

The jet pump slip joint repair clamps are subject to a loss of preload caused by neutron fluence 

and the LRA states that this loss of preload will be managed through periodic inspections under 

the BWR Vessel Internals program. The staff reviewed GALL Report AMP XI.M9 and found that 

it does not manage loss of preload; therefore, it is not clear how the applicant’s program will 

manage this aging effect. By letter dated December 15, 2011, the staff issued RAI 4.6.9-1 

requesting the applicant to provide the specific details as to how the BWR Vessels Internals 

program manages loss of preload.

In its response dated January 24, 2012, the applicant stated that it re-evaluated the TLAA and 

determined that the existing design analysis remains valid through the period of extended 

operation because the fluence value used to determine loss of preload will not be exceeded. 

The applicant revised the disposition of the TLAA to 10 CFR 54.21(c)(1)(i) and stated that 

RAMA fluence projections were prepared to determine the maximum fluence received during 

the service life for these slip joint clamps. Furthermore, since the core shroud is closer to the 

reactor core than the jet pumps, the applicant stated that the peak fluence received on the outer 

surface of the core shroud is higher than the fluence at the same elevation on the jet pumps, 

caused by the extra shielding provided by the reactor coolant in the space between the shroud 

and the jet pumps. 

As such, the applicant stated that the peak fluence on the outer surface of the core shroud at 

the 207.3-inch elevation of the slip joint clamps was used to provide a conservative estimate of 

the fluence at the highest point on the slip repair joint clamps. The resulting fluence projections 

are 1.24 E+18 n/cm2 and 1.28 E+18 n/cm2 for the slip joint repair clamps of LGS Units 1 and 2,

respectively. The staff finds it conservative that the applicant used the fluence values for the 

core shroud in its evaluation of the fluence values for the jet pump slip joint repair clamps 

because the core shroud is closer to the reactor core than the jet pumps. In addition, the staff 

finds it reasonable that the peak fluence received on the outer surface of the core shroud is less 

than the fluence at the same elevation on the jet pumps because of the extra shielding from the 

reactor coolant in the space between the core shroud and the jet pumps. 

The staff finds the applicant’s response acceptable because the projected fluence values for 

these components are less than the fluence value used in the design specification for the 

structural evaluation of the repair clamps that analyzed loss of preload. In addition, as 

described above, the staff finds the values used by the applicant to demonstrate that the jet 

pump slip joint repair clamps remains valid for the period of extended operation to be 

reasonable. The staff’s concern described in RAI 4.6.9-1 is resolved. 

With respect to the applicant’s calculation of the fluence projections, the staff’s review of the 

applicant’s use of the RAMA fluence methodology is documented in SER Section 4.2.1.2.
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The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the TLAA for the jet pump restrainer pad repair clamps remains valid for the period of extended 

operation. Additionally, the applicant meets the acceptance criteria in SRP-LR Section 4.7.3.1.1 

because the fluence value for the jet pump restrainer pad repair clamps at the end of the period 

of extended operation is less than the design value used in the design specification for the 

structural evaluation of the repair clamps that analyzed loss of preload.

4.6.9.3 UFSAR Supplement 

LRA Section A.4.6.9 provides the UFSAR supplement summarizing the TLAA for loss of preload 

of the jet pump slip joint repair clamps. The staff reviewed LRA Section A.4.6.9 consistent with 

the review procedures in SRP-LR Section 4.7.3.2, which state 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. 

Based on its review of the UFSAR supplement, as amended by letter dated January 24, 2012, 

the staff finds it meets the acceptance criteria in SRP-LR Section 4.7.2.2 and is, therefore,

acceptable. Additionally, the staff determines that the applicant provided an adequate summary 

description of its actions to address loss of preload of the jet pump slip joint repair clamps, as 

required by 10 CFR 54.21(d).

4.6.9.4 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 analysis for the jet pump slip 

joint repair clamps 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).

4.6.10 Fuel Pool Girder Loss of Prestress

4.6.10.1 Summary of Technical Information in the Application 

During its review the staff noted that the prestressed concrete girders that provide the main 

support for the LGS Units 1 and 2 spent fuel pools use grouted tendons. Since the tendons are 

grouted, conventional inspection procedures (e.g., lift-off tests to indicate the level of 

prestressing force) used to evaluate the structural integrity of ungrouted tendon systems cannot 

be used. The continued presence of elevated temperatures, creep and shrinkage of the 

concrete, and relaxation of the prestressing tendon steel could, through losses of prestressing 

force, produce increased deflections of the girders and have a negative effect on associated 

safety-related SCs. Increased deflections also can lead to cracking of the concrete that may 

impact the structural integrity of the prestressed girders (e.g., provide access for environments 

that may cause corrosion of the tendon steel) and the spent fuel pools. Therefore, by letter 

dated January 30, 2012 the staff issued RAI B.2.1.35-1 requesting the applicant to provide a 

plant-specific TLAA or a plant-specific inspection/monitoring program to provide assurances that 

the capability of the prestressed concrete girders associated with the spent fuel pool will 

continue to meet their intended function(s) during the period of extended operation.

By letter dated February 28, 2012, the applicant responded to RAI B.2.1.35-1 and added LRA 

Section 4.6.10, which describes the applicant’s TLAA for the loss of prestress associated with 
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the post-tensioned concrete fuel pool girders. The revised LRA states that “[t]he original design 

analysis for the fuel pool girders evaluated loss of prestress caused by stress relaxation of the 

steel tendons, caused by creep and shrinkage of the concrete, and other factors. Since stress 

relaxation of the steel tendons is based upon a time-limited assumption, this analysis has been 

identified as a TLAA that requires evaluation for the period of extended operation.”

The applicant stated that stress relaxation of the steel tendons was based on stress relaxation 

values obtained from three tests and projected to girder life of 114 years, which bound the 

extended service life of approximately 71 years from the construction of the girder until the end 

of the period of extended operation. The applicant also stated that there are several other 

factors that contribute to loss of prestress; however, these losses were accounted for by 

assigning an overall reduction in prestress during the design phase and are considered 

bounding for the life of the component. 

The applicant dispositioned the TLAA for the fuel pool girder in accordance with 

10 CFR 54.21(c)(1)(i), that the analysis remains valid for the period of extended operation.

4.6.10.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the fuel pool girders 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, which state that the staff should verify that the existing analyses are valid and 

bounding for the period of extended operation.

The staff reviewed the applicant’s TLAA, as well as its response to RAI B.2.1.35-1, and noted 

that the majority of prestressing losses were either accounted for during the design of the 

girders or are not time-dependent. Creep and shrinkage losses are both time-dependent; 

however, they reach limiting values either before the application of postensioning (shrinkage) or 

immediately after the initial loading (creep). Creep was accounted for during the design of the 

girders and is considered bounding for the life of the component. The time-dependent loss that

continues throughout the life of the component is the stress relaxation of the steel tendons,

which is estimated to be four percent and is accounted for in the original girder prestress design. 

This four percent loss value was based on testing and corresponds to 1,000,000 hours, or 

approximately 114 years of operation. Since the design uses a value associated with 

114 years, which is greater than the approximately 71-year service life at the end of the period 

of extended operation, the staff finds the applicant has demonstrated pursuant to 

10 CFR 54.21(c)(1)(i), that the analysis for the fuel pool girder remains valid for the period of 

extended operation. Additionally, it meets the acceptance criteria in SRP-LR Section 4.7.3.1.1 

because the analysis remains valid and the original analysis bounds the service life of the 

girders at the end of the period of extended operation. 

In addition, the applicant has included the fuel pool girders within the scope of the Structures 

Monitoring program, which means they will be visually inspected for cracking, deflections, and 

indications of corrosion on a 5-year frequency. Additional discussion on the aging management 

of the fuel pool girders can be found in the staff’s review of the Structures Monitoring program, 

SER Section 3.0.3.2.17.
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4.6.10.3 UFSAR Supplement 

By letter dated February 28, 2012, in response to RAI B.2.1.35-1, the applicant added LRA 

Section A.4.6.10, which provides the UFSAR supplement summarizing the fuel pool girder loss 

of prestress TLAA associated with the post-tensioned concrete fuel pool girders. The staff 

reviewed LRA Section A.4.6.10 consistent with the review procedures in SRP-LR Section 

4.7.3.2, which state that the staff should verify that the summary description in the UFSAR 

supplement should contain appropriate information, including the TLAA disposition.

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 is, therefore, acceptable. Additionally, the staff determines that 

the applicant provided an adequate summary description of its actions to address the 

post-tensioned concrete fuel pool girder prestress losses caused by tendon relaxation, as 

required by 10 CFR 54.21(d).

4.6.10.4 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)(i), that the analysis for the post-tensioned 

concrete fuel pool girders 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).

4.6.11 RHR and Core Spray Suction Strainer Fatigue Analysis 

4.6.11.1 Summary of Technical Information in the Application 

By letter dated March 13, 2012, in response to RAI 3.2.2.1.1-1, the applicant added LRA 

Section 4.6.11, which describes the applicant’s TLAA for RHR and CS suction strainer. The 

LRA states that the original RHR and CS suction strainers were replaced with larger passive 

strainer designs. The design stress analyses for the replacement strainers include fatigue 

analyses for the stainless steel bolting and strainer assemblies; therefore, these fatigue 

analyses have been identified as TLAAs that require evaluation for 60 years.

The applicant dispositioned the TLAA for RHR and CS suction strainer in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of fatigue on the intended functions of the RHR and CS 

suction strainer bodies and bolting will be managed by the Fatigue Monitoring program for the 

period of extended operation.

4.6.11.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the RHR and CS suction strainers 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, which states that the staff should verify that the applicant has 

identified the appropriate program as described and evaluated in the GALL Report and includes 

an assessment of the TLAA information against relevant design basis and CLB information.

In its response dated March 13, 2012, to RAI 3.2.2.1.1-1 regarding the staff’s separate review of 

bolting in engineered safety feature (ESF) systems, the applicant determined that the RHR and 

CS suction strainer stress analysis includes fatigue analyses for the stainless steel bolting 
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materials and for the stainless steel strainer assembly. The staff’s review of RAI 3.2.2.1.1-1 is 

documented in SER Section 3.2.2.1. Consistent with identification of these TLAAs, the following 

LRA sections were added by the applicant: LRA Section 4.6.11, “RHR and Core Spray Strainer 

Fatigue Analyses,” and Appendix A, Section A.4.6.11, “RHR and Core Spray Strainer Fatigue 

Analyses.”

LRA Section 4.6.11 states that the replacement RHR and CS suction strainers were designed in 

accordance with ASME Code Section III and included fatigue analyses of the stainless steel 

bolting and strainer assembly, with resulting fatigue usage values less than 1.0. Specifically, 

these analyses were based upon 34,200 MSRV stress cycles (11,400 actuations),10 SSE 

stress cycles (1 event), 50 OBE cycles (5 events) and condensation oscillation and chugging 

cycles that would result from LOCA events. The applicant stated that these are the same types 

of transients analyzed for the downcomers, as described in revised LRA Section 4.6.8 which 

was provided in the response to RAI 4.6.8-1, by letter dated February 29, 2012.

The applicant’s response to RAI 4.6.8-1 amended LRA Tables 4.3.1-1 and 4.3.1-2 to include the 

following transients:

 • Transient No. 18 – Faulted Condition – Pipe Rupture and Blowdown (1,000 psig to 35 psig 

in 15 seconds)

 • Transient No. 19 – Faulted Condition – Safe Shutdown Earthquake at Rated Operating 

Conditions

 • Transient No. 20 – Main Steam Relief Valve Actuations 

As discussed in the applicant’s responses to RAIs 4.3-2 and 4.6.8-1, condensation oscillation 

and chugging cycles are the result of a LOCA, which corresponds to Transient No. 18. The staff 

noted that the 50 OBE cycles were already included in LRA Tables 4.3.1-1 and 4.3.1-2 as 

Transient No. 8a. Therefore, the staff finds that the Fatigue Monitoring program, as amended 

by letter dated February 29, 2012, is monitoring and tracking the transients used in the fatigue 

analyses of the RHR and CS suction strainers.

The staff’s review of the applicant’s Fatigue Monitoring program is documented in SER 

Section 3.0.3.2.20. The staff determined that the program monitors and tracks the number of 

critical thermal, pressure, and seismic transients to assure that the cumulative number of 

occurrences of each transient type is maintained below the number of cycles used in the most 

limiting ASME Code Class 1 fatigue analysis. In addition, the program requires comparison of 

the actual event parameters to the applicable design transient definitions to ensure that the 

actual transients are bounded by the applicable design transients. If a transient approaches an 

action limit, which the applicant has set to 80 percent of the cycle limit, corrective actions are 

initiated for repair, replacement, or reanalysis of the component, in accordance with its Fatigue 

Monitoring program. The staff determined that these characteristics of the applicant’s Fatigue 

Monitoring program are consistent with GALL Report AMP X.M1. The staff noted that the 

applicant’s method for managing these fatigue analyses is conservative because corrective 

actions are initiated when one transient type approaches 80 percent of the cycle limit, when 

typically a fatigue analysis includes more than one transient type.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of fatigue on RHR and CS suction strainers will be adequately managed for the 

period of extended operation. Additionally, the applicant’s TLAA meets the acceptance criteria 
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in SRP-LR Section 4.3.2.1.1.3 because the applicant’s Fatigue Monitoring program monitors the 

transient severity and tracks the number of design basis transients that will occur through the 

period of extended operation, and includes action limits and corrective actions that will ensure 

that the assumption made in the fatigue analyses for the RHR and CS suction strainer 

components will not be exceeded during the period of extended operation.

4.6.11.3 UFSAR Supplement 

By letter dated March 13, 2012, in response to RAI 3.2.2.1.1-1, the applicant added LRA 

Section A.4.6.11, which provides the UFSAR supplement summarizing the TLAA for the RHR 

and CS suction strainers. The staff reviewed LRA Section A.4.6.11, consistent with the review 

procedure in SRP-LR Section 4.3.3.2, which states 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. 

Based on its review of the UFSAR supplement, the staff finds that the supplement 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 of the 

RHR and CS suction strainers, as required by 10 CFR 54.21(d).

4.6.11.4 Conclusion 

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that effects of fatigue for the RHR 

and CS suction strainers components will be adequately managed for the period of extended 

operation. The staff also concludes that the UFSAR supplement contains an adequate 

summary description of the evaluated TLAAs, as required by 10 CFR 54.21(d).

4.7 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 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) that the effects of aging on the intended function(s) 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 descriptions of the TLAAs sufficient to satisfy the 

requirements of 10 CFR 54.21(d). In addition, the staff concludes that two plant-specific, 

TLAA-based exemptions are in effect and that the applicant has provided an adequate 

evaluation that justifies the continuation of these exemptions for the period of extended 

operation, as required by 10 CFR 54.21(c)(2).

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, in order to comply with 10 CFR 54.29(a), are 

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

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SECTION 5

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR 

SAFEGUARDS

The NRC staff issued its safety evaluation report (SER) with open items related to the renewal 

of operating license for the Limerick Generating Station (LGS), Units 1 and 2 on July 31, 2012. 

On September 5, 2012, the applicant presented its license renewal application, and the staff 

presented its review findings to the Advisory Committee on Reactor Safeguards (ACRS) Plant 

License Renewal Subcommittee. The staff reviewed the applicant’s comments on the SER and 

completed its review of the license renewal application. The staff’s evaluation is documented in 

an SER that was issued by letter dated January 10, 2013.

During the 601st meeting of the ACRS held on February 7-8, 2013, the ACRS completed its 

review of the LGS license renewal application and the NRC staff’s SER. The ACRS 

documented its findings in a letter to the Commission dated February 14, 2013. A copy of this 

letter is provided on the following pages of this SER section.
5-2

UNITED STATES

NUCLEAR REGULATORY COMMISSION

ADVISORY COMMITTEE ON REACTOR SAFEGUARDS

WASHINGTON, DC 20555 - 0001

February 14, 2013

The Honorable Allison M. Macfarlane

Chairman

U. S. Nuclear Regulatory Commission

Washington, DC 20555-0001

SUBJECT: REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL 

APPLICATION FOR LIMERICK GENERATING STATION, UNITS 1 AND 2

Dear Chairman Macfarlane:

During the 601st meeting of the Advisory Committee on Reactor Safeguards, February 7-8, 

2013, we completed our review of the license renewal application (LRA) for Limerick Generating 

Station (LGS), Units 1 and 2 and the final Safety Evaluation Report (SER) prepared by the NRC 

staff. Our Plant License Renewal Subcommittee also reviewed this matter during its meeting on 

September 5, 2012. During these reviews, we had the benefit of discussions with 

representatives of the NRC staff and the applicant, Exelon Generation Company, LLC. We also 

had the benefit of the documents referenced.

RECOMMENDATION AND CONCLUSIONS

1. The programs established and committed to by the applicant to manage age-related 

degradation provide reasonable assurance that LGS Units 1 and 2 can be operated in 

accordance with their current licensing bases for the period of extended operation 

without undue risk to the health and safety of the public.

2. The Exelon Generation Company, LLC application for renewal of the operating licenses 

for LGS Units 1 and 2 should be approved.

3. This is the first LRA that was prepared based on Revision 2 of the Generic Aging 

Lessons Learned (GALL) Report. The applicant and the staff agree that the new 

guidance improved the efficiency of the review.
5-3

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BACKGROUND AND DISCUSSION

LGS Units 1 and 2 are General Electric BWR/4 designs with Mark II containments. They are 

owned and operated by Exelon Generation Company, LLC. LGS is located on the east bank of 

the Schuylkill River in Limerick Township of Montgomery County, Pennsylvania and is 

approximately 4 miles down-river from Pottstown, 35 miles up-river from Philadelphia. LGS 

Units 1 and 2 both have a licensed power output of 3,515 megawatts thermal. Their current 

operating licenses expire on October 26, 2024, and June 22, 2029, respectively. Exelon 

Generation Company, LLC requested renewal of the operating licenses for LGS Units 1 and 2 

for 20 years beyond the current license terms.

In the final SER, the staff documented its review of the LRA and other information submitted by 

the applicant or obtained from the staff audits and inspection at the plant site. This is the first 

license renewal application that was prepared based on Revision 2 of the GALL Report. The 

applicant and the staff agree that the new guidance improved the efficiency of the review.

The staff reviewed the completeness of the applicant’s identification of the structures, systems, 

and components (SSCs) that are within the scope of license renewal; the integrated plant 

assessment process; the applicant’s identification of the plausible aging mechanisms 

associated with passive, long-lived components; the adequacy of the applicants Aging 

Management Programs (AMPs); and the identification and assessment of time-limited aging 

analyses (TLAAs) requiring review.

In the LGS Units 1 and 2 license renewal application, the applicant identified the SSCs that fall 

within the scope of license renewal. For these SSCs, the applicant performed a comprehensive 

aging management review. Based on this review, the applicant has identified 45 programs that 

are needed to manage aging during the period of license renewal. Thirty-four of these 

programs are existing programs and 11 are new programs. Twenty-one of the existing 

programs required enhancements to conform with the GALL Report. 

The applicant is also committed to an ongoing review of both plant-specific and industry 

operating experience to help ensure that the AMPs are effective in managing aging effects. An 

AMP may be enhanced or new AMPs developed, as appropriate, if it is determined that the 

effects of aging may not be adequately managed by the existing AMP.

The application either demonstrates consistency of the AMPs with the GALL Report or 

documents deviations to the approaches specified in the Report. The one exception to the 

GALL Report is associated with the reactor head closure stud bolting program. A preventive 

measure to reduce the potential for stress corrosion cracking for these components identified in 

the GALL Report is a limit on the yield strength of the bolting material to less than 150 ksi. 

Some of the studs for the Units 1 and 2 vessel heads are fabricated from materials with slightly 

higher yield stresses. The program is consistent with other aspects of preventive measures 

listed in the GALL Report; e.g., that an approved lubricant is applied to the studs and associated 

hardware. No recordable indications have been found in examinations of reactor head closure 

stud bolting components over the past 10 years, indicating that the current program has been 

effective in managing cracking. We have reviewed this exception and agree with the staff that it 

is acceptable. 
5-4

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The staff conducted two license renewal audits and an inspection at LGS. The audits verified 

the appropriateness of the scoping and screening methodology, aging management review, and 

associated AMPs. The site inspection verified that the license renewal requirements are 

appropriately implemented. Based on the audits, inspection, and staff reviews, the staff 

concluded in the final SER that the proposed activities will reasonably 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. We agree with this conclusion.

The Mark II containments at LGS Units 1 and 2 consist of 6- to 8-foot thick reinforced concrete 

structures with 250-mil thick metal liners which act as leakage barriers. The lower portion of the 

containment is filled with water, which is maintained close to neutral pH and below 90o F. It 

typically contains only trace amounts of chlorides (less than or equal to 2 parts per billion) and 

sulfates (less than or equal to 13 parts per billion). The metal liners at LGS Units 1 and 2 are 

carbon steel. An inorganic zinc coating is used to protect the carbon steel liner against 

corrosion from the water.

The environment and liner material in the LGS Units 1 and 2 containments are similar to those 

in Mark I torus shells. Literature results suggest that inorganic zinc coatings have a lifetime on 

the order of 15-20 years. Reactor operating experience is consistent with these results. At 

Duane Arnold and Cooper approximately 5% and 1.1%, respectively, of the liner areas have lost 

their protective coating. The corresponding losses at LGS Unit 1 and Unit 2 are 15.2% and 

4.2%, respectively. 

Measurements show that the average corrosion rate of unprotected carbon steel in the LGS 

environments is about 2 mils/year. Higher rates might occur under deposits where differential 

aeration cells could form and more aggressive local chemistries could be present. The staff 

cites literature results which suggest that a conservative estimate of the rates in such local 

areas could be up to 12 mils/year. 

In most of the areas where corrosion has occurred, the total metal loss is less than 25 mils. 

There are areas of localized corrosion with depths of 50-125 mils. Because the thickness of the 

liner is much greater than actually required for structural integrity, integrity and leak tightness 

can be maintained with a loss of up to 125 mils of material over a large area and up to 187.5 

mils over a local area (less than 2.5 inches in diameter).

The applicant intends to manage aging degradation of the coating and corresponding corrosion 

of the liner by enhanced in-service inspection based upon ASME Code Section XI, Subsection 

IWE and repair of the coating. Their existing ASME Code Section XI, Subsection IWE program 

will be enhanced to remove accumulated sludge in the suppression pool every refueling outage, 

to perform an examination of the submerged portion of the suppression pool at a maximum 

interval of four years (two refueling outages), and to use the results of the examination to 

implement a coating maintenance plan. Ultrasonic thickness measurements will be made on 

four areas of the liner that are affected by general corrosion to correlate with the loss of 

thickness measured using calibrated depth dial gauges. The criteria for the repair of the coating 

are based on conservative estimates of the corrosion rates possible in the suppression pool 

environment and will ensure integrity of the liner until the next inspection period. 
5-5

-4-

Based on this enhanced AMP, the staff concludes that the applicant has demonstrated that the 

effects of aging of the containment coatings will be adequately managed so that the intended 

functions will be maintained consistent with the current licensing bases (CLB) for the period of 

extended operation. We concur with the staff's conclusion. 

The staff has concluded that the applicant has demonstrated that the effects of aging at LGS 

Units 1 and 2 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). We concur with this conclusion. 

The applicant identified the systems and components requiring TLAAs and reevaluated them for 

the period of extended operation. The staff concluded that the applicant has provided an 

adequate list of TLAAs. Further, the staff concluded that the applicant has met the 

requirements of the License Renewal Rule by demonstrating that the TLAAs will remain valid for 

the period of extended operation, or that the TLAAs have been projected to the end of the 

period of extended operation, or that the aging effects will be adequately managed for the 

period of extended operation. 

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 LGS. The programs 

established and committed to by Exelon Generation Company, LLC provide reasonable 

assurance that LGS Units 1and 2 can be operated in accordance with their CLB for the period of 

extended operation without undue risk to the health and safety of the public. The Exelon 

Generation Company, LLC application for renewal of the operating licenses for LGS should be 

approved.

Dr. J. Sam Armijo did not participate in the Committee’s deliberations regarding this matter.

Sincerely,

/RA/

John W. Stetkar

Vice Chairman

References:

1. NRC Safety Evaluation Report Related to the License Renewal of Limerick Generating 

Station, Units 1 and 2, January 2013 (ML12354A349)

2. Exelon Generation Company, LLC, “Limerick Generating Station, Units 1 and 2 - License 

Renewal Application,” June 22, 2011 (ML11179A101)

3. NRC Scoping and Screening Audit Report, December 9, 2011 (ML11342A205)

4. NRC AMP Audit Report, February 28, 2012 (ML12018A332)
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5. NRC License Renewal Inspection Report 05000352/2012009 and 05000353/2012009, 

July 30, 2012 (ML12213A053) 

6. NRC NUREG-1800, Revision 2, “Standard Review Plan for Review of License Renewal 

Applications for Nuclear Power Plants,” December 2010 (ML103409036)

7. NRC NUREG-1801, Revision 2, “Generic Aging Lessons Learned Report,” December 

2010 (ML103409041)

8. NRC Information Notice 2011-15, “Steel Containment Degradation and Associated 

License Renewal Aging Management Issues,” August 1, 2011 (ML111460369)

9. Final License Renewal Interim Staff Guidance LR-ISG-2011-05, “Ongoing Review of 

Operating Experience,” March 9, 2012 (ML12044A215)
6-1

SECTION 6

CONCLUSION

The staff of the United States Nuclear Regulatory Commission (NRC, the staff) reviewed the 

license renewal application (LRA) for the Limerick Generating Station (LGS), Units 1 and 2, 

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. 

The standards for issuance of a renewed license are in accordance with Title 10 of the Code of 

Federal Regulations (10 CFR) 54.29, “Requirements for Renewal of Operating Licenses for 

Nuclear Power Plants.”

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, Subpart A, will be documented in a 

Draft supplement to NUREG-1437, “Generic Environmental Impact Statement for License 

Renewal of Nuclear Plants (GEIS).”

A-1

APPENDIX A

LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE 

RENEWAL COMMITMENTS

During the review of the Limerick Generation Station (LGS), Units 1 and 2 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) to manage aging effects for structures and 

components. The following table lists these commitments, along with the implementation 

schedules and sources for each commitment.
A-2

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

1 Existing ASME Code Section XI Inservice Inspection, Subsections 

IWB, IWC, and IWD program is credited.

A.2.1.1 Ongoing 

2 Existing Water Chemistry program is credited. A.2.1.2 Ongoing 

3 Existing Reactor Head Closure Stud Bolting program is credited. A.2.1.3 Ongoing 

4 Existing BWR Vessel ID Attachment Welds program is credited. A.2.1.4 Ongoing 

5 Existing BWR Feedwater Nozzle program is credited. A.2.1.5 Ongoing 

6 BWR Control Rod Drive Return Line Nozzle is an existing program 

that will be enhanced to:

1. Specify an extended volumetric inspection of the 

nozzle-to-cap weld to assure that the inspection includes 

base metal to a distance of one pipe wall thickness or 0.5 

inches, whichever is greater, on both sides of the weld.

A.2.1.6 Program to be 

enhanced before t

period of extended 

operation.

7 Existing BWR Stress Corrosion Cracking program is credited. A.2.1.7 Ongoing 

8 Existing BWR Penetrations program is credited. A.2.1.8 Ongoing 
A-3

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

9 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 Cast 

Austenitic Stainless Steel (CASS) to loss of fracture 

toughness caused by 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 caused by neutron irradiation 

embrittlement.

3. Specify the required periodic inspection of CASS 

components determined to be susceptible to loss of 

fracture toughness caused by thermal aging and neutron 

irradiation embrittlement.

A.2.1.9 Program to be 

enhanced before t

period of extended 

operation.

The initial 

inspections will be 

performed either 

before or within 

5 years after enter

the period of 

extended operatio

10 Existing Flow-Accelerated Corrosion program is credited A.2.1.10 Ongoing 
A-4

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

11 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 

components.

2. Prohibit the use of lubricants containing molybdenum 

disulfide for closure bolting for pressure retaining 

components.

3. Minimize the use of high-strength bolting (actual measured 

yield strength equal to or greater than 150 ksi) for closure 

bolting for pressure retaining components. High-strength 

bolting, if used, will be monitored for cracking.

4. Perform visual inspection of bolting for the residual heat 

removal system, core spray system, high-pressure coolant 

injection system, and reactor core isolation cooling system 

suppression pool suction strainers for loss of material and 

loss of preload during each ISI inspection interval.

A.2.1.11 Program to be 

enhanced before t

period of extended 

operation.
A-5

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

12 Open-Cycle Cooling Water System is an existing program that will 

be enhanced to:

1. Perform internal inspection of buried safety-related service 

water piping when it is accessible during maintenance and 

repair activities.

2. Perform periodic inspections for loss of material in the 

nonsafety-related service water system at a minimum of 

five locations on each unit once every refueling cycle.

3. Replace the supply and return piping for the core spray 

pump compartment unit coolers.

4. Replace degraded RHRSW piping in the pipe tunnel.

5. Perform periodic inspections for loss of material in the 

safety-related service water system at a minimum of 

10 locations every 2 years.

A.2.1.12 Program to be 

enhanced before t

period of extended 

operation.

Inspection schedu

as identified in the 

commitment.
A-6

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

13 Closed Treated Water Systems is an existing program that will be 

enhanced to:

1. Perform condition monitoring and performance monitoring, 

including periodic testing and opportunistic and periodic 

NDE, 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 and inspected at an interval not to 

exceed once in 10 years during the period of extended 

operation.

2. Perform condition monitoring for the loss of material 

caused by cavitation erosion in the reactor enclosure 

cooling water piping to the 2A reactor water cleanup 

system (RWCU) non-regenerative heat exchanger. An 

initial inspection frequency of 4 years has been 

established. The inspection frequency will be re-evaluated 

and adjusted as necessary based on trend data.

A.2.1.13 Program to be 

enhanced before t

period of extended 

operation.

Inspection schedu

as identified in the 

commitment.
A-7

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

14 Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems is an existing program that will be 

enhanced to:

1. Perform annual periodic inspections as defined in the 

appropriate ASME B30 series standard for all cranes, 

hoists, and equipment handling systems within the scope 

of license renewal. For handling systems that are 

infrequently in service, such as those only used during 

refueling outages, annual periodic inspections may be 

deferred until just before use.

2. Perform inspections of structural components and bolting 

for loss of material caused by corrosion, rails for loss of 

material caused by wear and corrosion, and bolted 

connections for loss of preload.

3. Evaluate loss of material caused by wear or corrosion and 

any loss of bolting preload on cranes, hoists, and 

equipment handling systems per the appropriate ASME 

B30 series standard.

4. Perform repairs to cranes, hoists, and equipment handling 

systems per the appropriate ASME B30 series standard.

A.2.1.14 Program to be 

enhanced before t

period of extended 

operation.

15 Compressed Air Monitoring is an existing program that will be 

enhanced to:

1. Perform periodic analysis and trending of air quality 

monitoring results.

A.2.1.15 Program to be 

enhanced before t

period of extended 

operation.

16 Existing BWR reactor water cleanup system is credited. A.2.1.16 Ongoing 
A-8

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

17 Fire Protection is an existing program that will be enhanced to:

1. Provide additional inspection guidance to identify 

degradation of fire barrier walls, ceilings, and floors for 

aging effects such as cracking, spalling and loss of 

material.

2. Provide additional inspection guidance for identification of 

excessive loss of material caused by corrosion on the 

external surfaces of the halon and carbon dioxide 

systems.

A.2.1.17 Program to be 

enhanced before t

period of extended 

operation.

18 Fire Water System is an existing program that will be enhanced to:

1. Replace sprinkler heads or perform 50-year sprinkler head 

testing using the guidance of NFPA 25 “Standard for the 

Inspection, Testing and Maintenance of Water-Based Fire 

Protection Systems” (2002 Edition), Section 5.3.1.1.1. 

This testing will be performed before the 50-year inservice 

date and every 10 years thereafter.

2. Inspect selected portions of the water based fire protection 

system piping located aboveground and exposed to the 

fire water internal environment by non-intrusive volumetric 

examinations. These inspections shall be performed 

before the period of extended operation and will be 

performed every 10 years thereafter.

A.2.1.18 Program to be 

enhanced before t

period of extended 

operation.
A-9

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

19 Aboveground Metallic Tanks is an existing program that will be 

enhanced to:

1. Include UT measurements of the bottom of the backup 

water storage tank. Tank bottom UT inspections will be 

performed within 5 years before entering the period of 

extended operation and every 5 years thereafter. If no 

tank bottom plate material loss is identified after the first 

two inspections, the remaining inspections will be 

performed whenever the tank is drained during the period 

of extended operation.

2. Provide visual inspections of the Backup Water Storage 

Tank external surfaces and include, on a sampling basis, 

removal of insulation to permit inspection of the tank 

surface. An inspection performed before entering the 

period of extended operation will include a minimum of 

25 locations to demonstrate that the tank painted surface 

is not degraded under the insulation. Subsequent tank 

external surface visual inspection will be conducted on a 

2-year frequency and include a minimum of four locations.

A.2.1.19 Program to be 

enhanced before t

period of extended 

operation.

Inspection schedu

as identified in the 

commitment.
A-10

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

20 Fuel Oil Chemistry is an existing program that will be enhanced to:

1. Periodically drain water from the fire pump engine diesel 

oil day tank and the fire pump diesel engine fuel tank.

2. Perform internal inspections of the fire pump engine diesel 

oil day tank, the fire pump diesel engine fuel tank, and the 

diesel generator day tanks, 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. Each diesel fuel tank will be drained, 

cleaned and the internal surfaces either volumetrically or 

visually inspected. If evidence of degradation is observed 

during visual inspections, the diesel fuel tanks will require 

followup volumetric inspection.

3. Perform periodic analysis for total particulate 

concentration and microbiological organisms for the fire 

pump engine diesel oil day tank and the fire pump diesel 

engine fuel tank.

4. Perform periodic analysis for water and sediment and 

microbiological organisms for the diesel generator diesel 

oil storage tanks.

5. Perform periodic analysis for water and sediment content, 

total particulate concentration, and the levels of 

microbiological organisms for the diesel generator day 

tanks.

6. Perform analysis of new fuel oil for water and sediment 

content, total particulate concentration and the levels of 

microbiological organisms for the fire pump engine diesel 

oil day tank and the fire pump diesel engine fuel tank.

7. Perform analysis of new fuel oil for total particulate 

concentration and the levels of microbiological organisms 

for the diesel generator diesel oil storage tanks.

A.2.1.20 Program to be 

enhanced before t

period of extended 

operation.

Inspection schedu

as described in the 

commitment.
A-11

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

21 Existing Reactor Vessel Surveillance program is credited A.2.1.21 Ongoing 

22 One-Time Inspection is a new program that will be used to verify 

the system-wide effectiveness of the Water Chemistry, Fuel Oil 

Chemistry and Lubricating Oil Analysis programs.

A.2.1.22 Program to be 

implemented befo

the period of 

extended operatio

One-time inspectio

will be performed 

within the 10 years 

before the period o

extended operatio

23 Selective Leaching is a new program that will include one-time 

inspections of a representative sample of susceptible components 

to determine if loss of material caused by selective leaching is 

occurring.

A.2.1.23 Program to be 

implemented befo

the period of 

extended operatio

One-time inspectio

will be performed 

within the 5 years 

before the period o

extended operatio

24 One-Time Inspection of ASME Code Class 1 Small-Bore Piping is a 

new program that will manage the aging effect of cracking in 

stainless steel and carbon steel Class 1 small-bore piping that is 

less than nominal pipe size (NPS) 4-inches, and greater than or 

equal to NPS 1-inch.

A.2.1.24 Program to be 

implemented befo

the period of 

extended operatio

One-time inspectio

will be performed 

within the 6 years 

before the period o

extended operatio
A-12

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

25 External Surfaces Monitoring of Mechanical Components is a new 

program that manages aging effects of metallic and elastomeric 

materials through periodic visual inspection of external surfaces for 

evidence of loss of material. Visual inspections are augmented by 

physical manipulation as necessary to detect hardening and loss of 

strength of elastomers

A.2.1.25 Program to be 

implemented befo

the period of 

extended operatio

26 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components is a new program that manages aging effects of 

metallic and elastomeric materials through visual inspections of 

internal surfaces for evidence of loss of material. Visual 

inspections are augmented by physical manipulation as necessary 

to detect hardening and loss of strength of elastomers.

A.2.1.26 Program to be 

implemented befo

the period of 

extended operatio

27 Existing Lubricating Oil Analysis is credited. A.2.1.27 Ongoing 
A-13

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

28 Monitoring of Neutron-Absorbing Materials Other than Boraflex is 

an existing program that will be enhanced to:

1. Perform test coupon analysis on a 10-year frequency, 

beginning no earlier than 2020 for Unit 1 and 2021 for 

Unit 2.

2. Initiate corrective action if coupon test result data indicates 

that acceptance criteria will be exceeded before the next 

scheduled test coupon analysis.

3. Resume the accelerated exposure configuration for the 

Boral coupons (surrounded by freshly discharged fuel 

assemblies) at each of five additional refueling cycles, 

beginning with the next refueling for each unit (2013 for 

Unit 2, 2014 for Unit 1).

4. Maintain the coupon exposure such that it is bounding for 

the Boral 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.

A.2.1.28 Program to be 

enhanced before t

period of extended 

operation.

Inspection schedu

as described in the 

commitment.

29 Buried and Underground Piping and Tanks is an existing program 

that will be enhanced to:

1. If adverse indications are detected during inspection of 

in-scope buried piping, inspection sample sizes within the 

affected piping categories are doubled. If adverse 

indications are found in the expanded sample, the 

inspection sample size is again doubled. This doubling of 

the inspection sample size continues as necessary.

A.2.1.29 Program to be 

enhanced before t

period of extended 

operation.

Inspection schedu

as described in the 

commitment.
A-14

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

29 (cont.)

2. Coat the underground emergency diesel generator system 

fuel oil piping before the period of extended 

operation. The coating will be in accordance with Table 1 

of NACE SP0169-2007 or Section 3.4 of NACE 

RP0285-2002.

3. Perform direct visual inspections and volumetric 

inspections of the underground emergency diesel 

generator system fuel oil piping and components during 

each 10-year period beginning 10 years before the entry 

into the period of extended operation. Before the period of 

extended operation all in scope emergency diesel 

generator system fuel oil piping and components located 

in underground vaults will undergo a 100 percent visual 

inspection. Volumetric inspections will also be 

performed. After entering the period of extended 

operation, 2 percent of the linear length of in scope 

emergency diesel generator system fuel oil piping and 

components located in underground vaults will undergo 

direct visual inspections and volumetric inspections every 

10 years. Inspection locations after entering the period of 

extended operation will be selected based on susceptibility 

to degradation and consequences of failure. Visual 

inspections will be performed by a NACE qualified 

inspector.

4. Perform two sets of volumetric inspections of the 

safety-related service water system underground piping 

and components during each 10-year period beginning 

10 years before the entry into the period of extended 

operation. Each set of volumetric inspections will assess 

either the entire length of a run of in scope safety-related 

service water system piping and components in the 

underground vault or a minimum of 10 feet of the linear 

length of in scope safety-related service water system 
A-15

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

piping and components in the underground 

vault. Inspection locations will be selected based on 

susceptibility to degradation and consequences of failure.

5. Specify that visual inspections of safety-related service 

water system underground piping and components will be 

performed by a NACE qualified inspector.

6. Perform trending of the cathodic protection testing results 

to identify changes in the effectiveness of the system and 

to ensure that the rectifiers required to protect in scope 

piping are reliable 90 percent of the time.

7. Modify the yearly cathodic protection survey acceptance 

criterion to meet NACE SP0169-2007 standards and add 

a statement that, if negative polarized potential 

exceeds -1100mV relative to copper or copper sulfate 

electrode, an issue report will be entered into the 

corrective action program.

30 ASME Code Section XI, Subsection IWE is an existing program 

that will be enhanced to:

1. Manage the suppression pool liner and coating system to:

a. Remove any accumulated sludge in the 

suppression pool every refueling outage.

b. Perform an ASME IWE examination of the 

submerged portion of the suppression pool each 

ISI period.

c. Use the results of the ASME IWE examination to 

implement a coating maintenance plan to

perform the following prior to the period of 

extended operation (PEO):

• Local areas (less than 2.5 inches in 

diameter) of general corrosion that are 

A.2.1.30 Program to be 

enhanced before t

period of extended 

operation.

Inspection schedu

as described in the 

commitment.
A-16

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

greater than 50 mils plate thickness loss 

will be recoated in the outage they are 

identified. This plate thickness loss 

criterion for local areas will also be used to 

determine when the submerged portions 

of the liner require augmented inspection 

in accordance with ASME Section XI, 

Subsection IWE, Category E-C.

• Areas of general corrosion greater than 25 

mils average plate thickness loss will be 

recoated based on ranking of affected 

surface area, high to low. This plate 

thickness loss criterion for areas of 

general corrosion will also be used to 

determine when the submerged portions 

of the liner require augmented inspection 

in accordance with ASME Section XI, 

Subsection IWE, Category E-C.

• For plates with greater than 25 percent 

coating depletion, the affected area will be 

recoated based on ranking of affected 

surface area depleted and metal thickness 

loss.
A-17

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

d. Use the results of the ASME IWE examination to 

implement a coating maintenance plan to perform 

the following during the PEO:

• Local areas (less than 2.5 inches in 

diameter) of general corrosion that are 

greater than 50 mils plate thickness loss 

will be recoated in the outage they are 

identified. This plate thickness loss 

criterion for local areas will also be used to 

determine when the submerged portions 

of the liner require augmented inspection 

in accordance with ASME Section XI, 

Subsection IWE, Category E-C.

• Areas of general corrosion greater than 25 

mils average plate thickness loss will be 

recoated in the outage they are identified. 

This plate thickness loss criterion for areas 

of general corrosion will also be used to 

determine when the submerged portions 

of the liner require augmented inspection 

in accordance with ASME Section XI, 

Subsection IWE, Category E-C.

• For plates with greater than 25 percent 

coating depletion, the affected area will be 

recoated no later than the next scheduled 

inspection.

The coating maintenance plan will continue through the 

period of extended operation to ensure the coating 

protects the liner to avoid significant material loss.

2. Use the results of the ASME IWE inspection of the 

submerged portions of the suppression pool downcomers 
A-18

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

to perform the following:

• Local areas (less than or equal to 5.5 inches in 

any direction) that have 40 mils or more metal 

thickness loss will be recoated. This downcomer 

metal thickness loss criteria for local areas will 

also be used to determine when the submerged 

portions of the downcomers require augmented 

inspection in accordance with ASME Section XI, 

Subsection IWE, Category E-C.

• Areas of general corrosion (greater than 5.5 

inches in any direction) that have 30 mils or more 

metal thickness loss will be recoated. This 

downcomer metal thickness loss criteria for areas 

of general corrosion will also be used to 

determine when the submerged portions of the 

downcomers require augmented inspection in 

accordance with ASME Section XI, Subsection 

IWE, Category E-C.

3. When IWE examinations are conducted, perform 

ultrasonic thickness measurements on four areas of 

submerged suppression pool liner affected by general 

corrosion.

4. 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.

31 ASME Code Section XI, Subsection IWL is an existing program that 

will be enhanced to:

1. Include second-tier acceptance criteria of ACI 349.3R.

A.2.1.31 Program to be 

enhanced before t

period of extended 

operation.
A-19

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

32 ASME Code Section XI, Subsection IWF 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.

A.2.1.32 Program to be 

enhanced before t

period of extended 

operation.

33 Existing 10 CFR Part 50, Appendix J program is credited A.2.1.33 Ongoing 

34 Masonry Walls is an existing program that will be enhanced to:

1. Add the following structures with masonry walls to the 

program scope: 

a. administration building warehouse 

b. fuel oil pumphouse 

c. transformer foundation dike walls

2. Provide additional guidance for inspection of masonry 

walls for shrinkage, separation, and for gaps between the 

supports and walls that could impact the wall’s intended 

function.

3. Require an inspection frequency of not greater than 

5 years.

4. Require that personnel performing inspections and 

evaluations meet the qualifications specified within 

ACI 349.3R.

A.2.1.34 Program to be 

enhanced before t

period of extended 

operation.

Inspection schedu

as described in the 

commitment.

35 Structures Monitoring is an existing program that will be enhanced 

to: A.2.1.35 Program to be 

enhanced before t
A-20

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

35 (cont.)

1. Add the following structures:

a. admin building warehouse

b. fuel oil pumphouse

c. service water pipe tunnel

d. yard structures

• aux fire water storage tank foundation

• backup fire pump house and foundation

• well pump #3 enclosure and foundation

• railroad bridge

• manholes 001 and 002

• fuel oil storage tank dike

• transformer foundations and dikes

2. 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, and other enclosures

d. sliding surfaces

e. sump and pool liners

f. electrical cable trays and conduits

g. electrical duct banks

h. tube tracks

i. doors

period of extende

operation.

Inspection schedu

as described in the 

commitment.
A-21

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

j. penetration seals

k. blowout panels

l. permanent drywell shielding

m. roof scuppers

3. Monitor groundwater chemistry on a frequency not to 

exceed 5 years for pH, chlorides, and sulfates and verify 

that it remains nonaggressive, or evaluate results 

exceeding criteria to assess impact, if any, on below-grade 

concrete.

4. 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. Revise storage requirements for 

high-strength bolts to include recommendations of 

Research Council on Structural Connections (RSCS) 

Specification for Structural Joints Using High Strength 

Bolts, Section 2.0.

5. Monitor concrete for areas of abrasion, erosion, and 

cavitation degradation, drummy areas that can exceed the 

cover concrete thickness in depth, popouts and voids, 

scaling, and passive settlements or deflections.

6. Perform inspections on a frequency not to exceed 5 years.

7. Perform inspections of subdrainage sump pit internal 

concrete on a 5-year frequency as a leading indicator the 

condition of below grade concrete exposed to ground 

water.
A-22

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

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Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

35 (cont.) 8. Require that personnel performing inspections and 

evaluations meet the qualifications specified within 

ACI 349.3R.

9. Perform inspection of elastomeric vibration isolation 

elements and structural seals for cracking, loss of material 

and hardening. Visual inspections of elastomeric vibration 

isolation elements are to be supplemented by 

manipulation to detect hardening when vibration isolation 

function is suspect.

10. Monitor accessible sliding surfaces to detect significant 

loss of material caused by wear, corrosion, debris, or dirt, 

which could result in lock-up or reduced movement.

11. Perform opportunistic inspection of below grade portions 

of in-scope structures in the event of excavation that

exposes normally inaccessible below grade concrete.

12. Include applicable acceptance criteria from ACI 349.3R.

13. Clarify that loose bolts and nuts and cracked high-strength 

bolts are not acceptable unless accepted by engineering 

evaluations.

36 RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants is an existing program that will be enhanced 

to:

1. Require inspection of structural bolting integrity (loss of 

material and loosening of the bolts).

2. Require monitoring of aging effects for increase of porosity 

and permeability of concrete structures and loss of 

material for steel components.

3. Require the proper functioning of dike drainage systems.

A.2.1.36 Program to be 

enhanced before t

period of extended 

operation.

Inspection schedu

as described in the 

commitment.
A-23

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

36 (cont.)

4. Require increased inspection frequency if the extent of the 

degradation is such that the structure or component may 

not meet its design basis if allowed to continue 

uncorrected until the next normally scheduled inspection.

5. Require (a) 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, and (b) examination of the 

exposed portions of the below-grade concrete when 

excavated for any reason.

6. Monitor raw water chemistry at least once every 5 years 

for pH, chlorides, and sulfates and verify that it remains 

nonaggressive, or evaluate results exceeding criteria to 

assess impact, if any, on submerged concrete.

7. Require visual examinations of the Spray Pond and 

Pumphouse submerged wetwell concrete for signs of 

degradation during maintenance activities. If significant 

concrete degradation is identified, a plant-specific aging 

management program should be implemented to manage 

the concrete aging during the period of extended 

operation.

8. Require that active cracks in structural concrete or extent 

of corrosion in steel are documented and trended, until the 

condition is no longer occurring or until a corrective action 

is implemented.

9. Require acceptance and evaluation of structural concrete 

using quantitative criteria based on Chapter 5 of 

ACI 349.3R. 

10. Provide guidance for proper specification of bolting 

material, lubricant and sealants, and installation torque or 

tension to prevent or mitigate degradation and failure of 
A-24

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

structural bolting. Revise storage requirements for 

high-strength bolts to include recommendations of 

Research Council on Structural Connections (RSCS) 

Specification for Structural Joints Using High Strength 

Bolts, Section 2.0.

37 Protective Coating Monitoring and Maintenance Program is an 

existing program that will be enhanced to:

1. Create the position of Nuclear Coatings Specialist 

qualified to ASTM D 7108 standards.

A.2.1.37 Program to be 

enhanced before t

period of extended 

operation.

38 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 aging 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.

A.2.1.38 Program and initia

inspections to be 

implemented befo

the period of 

extended operatio

Inspection schedu

as described in the 

commitment.

39 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 aging of non-EQ cable and connection insulation of the 

in scope portions of the process radiation monitoring and neutron 

monitoring systems.

Calibration and cable tests will be performed and results will be 

assessed for reduced insulation resistance before the period of 

extended operation and at least once every 10 years during the 

period of extended operation.

A.2.1.39 Program and initia

assessment of 

calibration and tes

results to be 

implemented befo

the period of 

extended operatio

Assessment 

schedule identified 

commitment.
A-25

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

40 Inaccessible Power Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements is a new program that 

will be used to manage the aging effects and mechanisms of 

non-EQ, in scope, inaccessible power cables.

Cables will be tested using a proven test for detecting reduced 

insulation resistance of the cable’s insulation system. The cables 

will be tested at least once every 6 years. More frequent testing 

may occur based on test results and operating experience.

Periodic actions will be taken to prevent inaccessible cables from 

being exposed to significant moisture. 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. Before 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 

confirmed before any known or predicted heavy rain or flooding 

event. During the period of extended operation, the inspections will 

occur at least annually.

A.2.1.40 Program and initia

tests and inspectio

to be implemented 

before the period o

extended operatio

Test and Inspectio

schedule identified 

commitment.

41 Metal Enclosed Bus is a new program that will be used to manage 

aging of in scope metal enclosed bus. The internal portions of bus 

enclosure assemblies, bus insulation, bus insulating supports and 

elastomers will be visually inspected. A sample (20 percent with a 

maximum sample size of 25) of the accessible metal enclosed bus 

bolted connection population will be tested using thermography. 

The inspections and thermography will be performed at least once 

every 10 years for indications of aging degradation.

A.2.1.41 Program and initia

tests and inspectio

to be implemented 

before the period o

extended operatio

Test and inspectio

schedule identified 

commitment.
A-26

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

42 Fuse Holders aging management program is a new program that 

applies to fuse holders located outside of active devices that have 

been identified as susceptible to aging effects. 

Fuse holders subject to increased resistance of connection or 

fatigue, will be tested, by a proven test methodology, at least once 

every 10 years for indications of aging degradation. Visual 

inspection is not part of this program.

A.2.1.42 Program and initia

tests to be 

implemented befo

the period of 

extended operatio

Test schedule 

identified in 

commitment.

43 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 aging of metallic 

cable connections does not occur or that the existing preventive 

maintenance program is effective such that a periodic inspection 

program is not required.

A.2.1.43 Program and 

one-time tests to b

implemented befo

the period of 

extended operatio

44 Fatigue Monitoring is an existing program that will be enhanced to:

1. Monitor additional plant transients that are significant 

contributors to fatigue usage and to impose administrative 

transient cycle limits corresponding to the limiting numbers 

of cycles used in the environmental fatigue calculations.

A.3.1.1 Program to be 

enhanced before t

period of extended 

operation.

45 Existing Environmental Qualification (EQ) of Electric Components 

program is credited.

A.3.1.2 Ongoing 
A-27

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMMITM

Item Commitment UFSAR

Supplement Section/

LRA Section

Enhancement 

Implementatio

Schedule

46 The Operating Experience program is an existing program that will 

be enhanced to:

1. Explicitly require the review of operating experience for 

aging-related degradation.

2. Establish criteria to define aging-related degradation.

3. Establish identification coding for use in identification, 

trending, and communications of aging-related 

degradation.

4. Require communication of significant internal 

aging-related degradation, associated with SSCs in the 

scope of license renewal, to other Exelon plants and to the 

industry. Criteria will be established for determining when 

aging-related degradation is significant.

5. Require review of external operating experience for 

information related to aging management, and evaluation 

of such information for potential improvements to LGS 

aging management activities.

6. Provide training to those responsible for screening, 

evaluating and communicating operating experience items 

related to aging management.

A.1.6 Program to be 

enhanced no later 

than the date that 

renewed operating 

licenses are issued

47 Re-evaluate the flaw in the Unit 1 RPV nozzle to safe-end weld 

VRR-1RD-1A-N2H in accordance with ASME Code Section XI, 

subsection IWB-3600 for the 60-year service period corresponding 

to the LR term.

Appendix C Before the period o

extended operatio

B-1

APPENDIX 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). This appendix also lists other correspondence on the staff’s review of 

the Limerick Generating Station (LGS) license renewal application (LRA) (under Docket Nos. 

50-352 and 50-353).

APPENDIX B: CHRONOLOGY

Date Subject

June 22, 2011 Letter from Gallagher M., Exelon Generation Co., LLC, to U.S. NRC Document Control 

Desk, “Limerick Generating Station, Units 1 and 2 - Application for Renewed Operating 

Licenses.” (ADAMS Accession No. ML11179A096)

June 22, 2011 Exelon Generation Co., LLC. “Limerick Generating Station, Units 1 & 2 - License Renewal 

Application.” (ADAMS Accession No. ML11179A101)

June 22, 2011 Exelon Generation Co., LLC. “Limerick Generating Station, Units 1 and 2 - Applicant's 

Environmental Report Operating License Renewal Stage.” (ADAMS Accession No. 

ML11179A104)

June 22, 2011 Exelon Generation Co., LLC, “Limerick Generating Station License Renewal Application 

Boundary Drawings.” (ADAMS Accession No. ML12009A107)

July 13, 2011 Letter from Holian, B. E., U.S. NRC, to Gallagher, M., Exelon Generation Co., LLC, 

“Receipt and Availability of the License Renewal Application for the Limerick Generating 

Station Units 1 and 2.” (ADAMS Accession No. ML11180A040)

July 13, 2011 Federal Register Notice, “Notice of Availability of the LRA for the Limerick Generating.” 

(ADAMS Accession No. ML11180A178)

August 12, 2011 Letter from Holian B. E., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“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 Limerick Generating Station.” 

(ADAMS Accession No. ML11206A206)

September 6, 2011 “Notice of Forthcoming Meeting to Discuss the License Renewal Process and 

Environmental Scoping for Limerick Generating Station, Units 1 And 2, License Renewal 

Application.” (ADAMS Accession No. ML11245A008)

September 15, 2011 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, “Plan for 

the Scoping and Screening Regulatory Audit Regarding the Limerick Generating Station, 

Units 1 and 2 License Renewal Application Review (TAC Nos. ME6555, ME6556).” 

(ADAMS Accession No. ML11255A032)
B-2

APPENDIX B: CHRONOLOGY

Date Subject

September 20, 2011 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, “Plan for 

the Aging Management Program Regulatory Audit Regarding the Limerick Generating 

Station, Units 1 and 2 License Renewal Application Review.” (ADAMS Accession No. 

ML11258A109)

November 18, 2011 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Requests for Additional Information for the Review of the Limerick Generating Station 

License Renewal Application.” (ADAMS Accession No. ML11308A001)

December 7, 2011 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC Document Control 

Desk, “Limerick, Units 1 and 2, Response to NRC Request for Additional Information, 

Dated November 18, 2011.” (ADAMS Accession No. ML113410144)

December 9, 2011 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Scoping and Screening Methodology Audit Report Regarding the Limerick Generating 

Station, Units 1 and 2 (TAC Nos. ME6555, ME6556).” (ADAMS Accession No. 

ML11342A205)

December 15, 2011 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Requests for Additional Information for the Review of the Limerick Generating Station 

License Renewal Application (TAC ME6555, ME6556).” (ADAMS Accession No. 

ML11343A438)

January 5, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, “RAI for 

the Review of the Limerick Generating Station License Renewal Application (TAC Nos. 

ME6555, ME6556).” (ADAMS Accession No. ML11335A317)

January 17, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Requests for Additional Information for the Review of the Limerick Generating Station 

License Renewal Application (TAC Nos. ME6555, ME6556).” (ADAMS Accession No. 

ML11347A360)

January 18, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Requests for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos. ME6555, ME6556).” (ADAMS 

Accession No. ML11361A083)

January 24, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Requests for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos. ME6555, ME6556).” (ADAMS 

Accession No. ML11361A079)

January 24, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC Document Control 

Desk, “Limerick, Units 1 & 2 - Response to NRC Request for Additional Information, dated 

December 15, 2011, Related to License Renewal Application.” (ADAMS Accession No. 

ML12024A507)

January 27, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, U.S. NRC Document Control Desk, 

“Limerick, Units 1 and 2, Response to NRC Request for Information, Dated January 5, 

2012, Related to License Renewal Application.” (ADAMS Accession No. ML12027A228)
B-3

APPENDIX B: CHRONOLOGY

Date Subject

January 30, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Requests for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos. ME6555, ME6556).” (ADAMS 

Accession No. ML11364A099)

January 31, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Request for Additional Information for the Review of the Limerick Generating Station 

Units 1 and 2 License Renewal Application (TAC Nos. ME6555, ME6556) TLAA 43 and 

468 RAIs.” (ADAMS Accession No. ML12005A251)

February 14, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Request for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos. ME6555, ME6556) RAPB AMR2 

RAIs.” (ADAMS Accession No. ML12018A033)

February 15, 2012 Letter from Gallagher M., Exelon Generation Co, LLC Exelon Nuclear, NRC/Document 

Control Desk, “Response to NRC RAI dated Jan. 17, 2012 re: Limerick Gen. Station LRA.” 

(ADAMS Accession No. ML120470084)

February 16, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Request for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos. ME6555 and ME6556).” (ADAMS 

Accession No. ML12017A159)

February 16, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Requests for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos. ME6555 and ME6556) OE and 

Other RAIs.” (ADAMS Accession No. ML12024A231)

February 16, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC Document Control 

Desk, “Limerick, Units 1 and 2 - Response to NRC Request for Additional Information, 

dated January 17, 2012.” (ADAMS Accession No. ML120470372)

February 17, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Requests for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC ME6555 and ME6556).” (ADAMS 

Accession No. ML12019A156)

February 23, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Requests for Addtional Information for the Review of the Limerick Generating Station, 

Units 1 & 2, License Renewal Application (TAC ME6555 and ME6556).” (ADAMS 

Accession No. ML12018A035)

February 28, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC Document Control 

Desk, “Limerick, Units 1 & 2, Response to NRC Request for Additional Information, dated 

January 30, 2012, Related to License Renewal Application.” (ADAMS Accession No. 

ML12059A345)

February 28, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, “Aging 

Management Programs Audit Report Regarding the Limerick Generating Station, Units 1 

and 2 (TAC Nos. ME6555 and ME6556)” (ADAMS Accession No. ML12018A332)
B-4

APPENDIX B: CHRONOLOGY

Date Subject

February 29, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, U.S. NRC Document Control Desk, 

“Limerick, Units 1 and 2 - Response to NRC Request for Additional Information, dated 

January 31, 2012 Related to License Renewal Application.” (ADAMS Accession No. 

ML12060A154)

March 5, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, U.S. NRC Document Control Desk, 

“Limerick, Units 1 and 2 - Response to NRC Requests for Additional Information, dated 

February 16, 2012, and February 17, 2012, Related to Renewal Application.” (ADAMS 

Accession No. ML12065A206)

March 9, 2012 Meeting Summary from Kuntz R. F., U.S. NRC, “Summary of the Telephone Conference 

Call Held on December 14, 2011, Between the U.S. Nuclear Regulatory Commission and 

Exelon on Generation Company, LLC, Concerning Requests For Additional Information 

Pertaining to the Limerick 12-14-11 Telecon Summary.” (ADAMS Accession No. 

ML12009A135)

March 9, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Request for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos. ME6555 and ME6556) Limerick 

App. J RAIs.” (ADAMS Accession No. ML12046A899)

March 13, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, U.S. NRC Document Control Desk, 

“Response to NRC Requests for Additional Information, dated February 14 and February 

16, 2012, Related to the Limerick Generating Station License Renewal Application.” 

(ADAMS Accession No. ML120730361)

March 20, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC Document Control 

Desk, “Limerick, Units 1 and 2, Response to NRC Requests for Additional Information, 

dated February 23 and March 9, 2012, Related to License Renewal Application.” (ADAMS 

Accession No. ML12080A118)

March 22, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, “Letter 

re: Request for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos. ME6555, ME6556) Buried Piping 

and FP Follow Up.” (ADAMS Accession No. ML12074A037)

March 27, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC Document Control 

Desk, “Limerick Generating Station, Units 1 and 2 - Response to NRC Request for 

Additional Information, dated February 28th, 2012, related to the License Renewal 

Application.” (ADAMS Accession No. ML12088A366)

March 30, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC Document Control

Desk, “Limerick, Units 1 and 2 - Response to NRC Request for Additional Information, 

dated March 22, 2012 and Information Addressing Minor Errors or Omissions Related to 

License Renewal Application.” (ADAMS Accession No. ML12090A489)

April 5, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Request for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC NOS. ME6555 and ME6556) BWR SCC 

SMP and CTWS follow up.” (ADAMS Accession No. ML12080A190)
B-5

APPENDIX B: CHRONOLOGY

Date Subject

April 9, 2012 Meeting Summary from Kuntz R. F., U.S. NRC, “February 9, 2012, Summary of 

Telephone Conference Call Held Between the U.S. Nuclear Regulatory Commission and 

Exelon Generation Company, LLC, Concerning Request For Additional Information 

Pertaining to the Limerick.” (ADAMS Accession No. ML12066A026)

April 11, 2012 Meeting Summary from Kuntz R. F., U.S. NRC, “February 23, 2012, Summary of 

Telephone Conference Call Held on February 23, 2012, between the U.S. Nuclear 

Regulatory Commission and Exelon Generation Company, LLC, Concerning Requests for 

Additional Information Pertaining to the Limerick Generating Station, License Renewal 

Application (ADAMS Accession No. ML12083A211)

April 13, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Request for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos. ME6556 and ME6555) Fluence 

and FP Followup RAIs.” (ADAMS Accession No. ML12089A377)

April 13, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC Document Control 

Desk, “Limerick, Units 1 and 2, Response to NRC Requests for Additional Information, 

dated April 5, 2012, Related to License Renewal Application.” (ADAMS Accession No. 

ML12104A118)

April 16, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Requests for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos. ME6555 and ME6556).” (ADAMS 

Accession No. ML12082A155)

April 17, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Request for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos ME6555 and ME6556)TLAA 

Followup RAIs.” (ADAMS Accession No. ML12095A398)

April 20, 2012 Meeting Summary from Kuntz R. F., U.S. NRC, “Summary of Telephone Conference Call 

Held on January 18, 2012, Between The U.S. Nuclear Regulatory Commission and 

Exelon Generation Company, LLC, Concerning Request for Additional Information 

Pertaining to the Limerick Generation 1-18-12 Telecon Summary.” (ADAMS Accession 

No. ML12025A051)

April 20, 2012 Meeting Summary from Kuntz R. F., U.S. NRC, “February 17, 2012, Summary of 

Telephone Conference Call Held between U.S. Nuclear Regulatory Commission and 

Exelon Generation Company, LLC, Concerning Request for Additional Information 

Pertaining to the Limerick 2-17-12 Telecon Summary.” (ADAMS Accession No. 

ML12059A080)

April 26, 2012 Meeting Summary from Kuntz R. F., U.S. NRC, “1/12/2012 Telecon Summary Between 

the U.S. Nuclear Regulatory Commission and Exelon Generation Company, LLC, 

Concerning Requests for Additional Information Pertaining to the Limerick Generating 

Station, License Renewal Application.” (ADAMS Accession No. ML12018A023)

April 27, 2012 Letter from Gallagher M., Exelon Generation Co, LLC Exelon Nuclear, to U.S. NRC 

Document Control Desk, “Limerick, Units 1 and 2 - Response to NRC Requests for 

Additional Information, dated April 13 and April 16, 2012, related to the License Renewal 

Application.” (ADAMS Accession No. ML12121A009)
B-6

APPENDIX B: CHRONOLOGY

Date Subject

April 30, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Request for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos. ME6555 and ME6556) SCC RAIs.” 

(ADAMS Accession No. ML12111A034)

May 1, 2012 Meeting Summary from Kuntz R. F., U.S. NRC, “02/14/2012 Summary of Telephone 

Conference Call Held between NRC and Exelon Generation Co., LLC, Concerning 

Requests for Additional Information Pertaining to the Limerick, License Renewal 

Application (TAC ME6555 and ME6556).” (ADAMS Accession No. ML12047A124)

May 4, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC Document Control 

Desk, “Limerick, Units 1 and 2, Responses to NRC Requests for Additional Information, 

dated April 17, 2012, Related to the License Renewal Application.” (ADAMS Accession 

No. ML12125A334)

May 7, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S NRC Document Control 

Desk, “Limerick, Units 1 and 2, Responses to NRC Requests for Additional Information, 

Dated April 30, 2012, Related to the License Renewal Application.” (ADAMS Accession 

No. ML12128A438)

May 18, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, “RAI for 

Review of the Limerick Generation Station, Units 1 & 2 & License Renewal Application.” 

(ADAMS Accession No. ML12123A092)

May 18, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Request for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, (TAC Nos. ME6555 AND ME6556) Scoping Drawings Followup RAI.” 

(ADAMS Accession No. ML12136A036)

May 24, 2012 Meeting Summary from Kuntz R. F., U.S. NRC, “4-17-12 Telecon Summary.” (ADAMS 

Accession No. ML12115A281)

May 31, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC Document Control 

Desk, “Limerick, Units 1 and 2, Responses to NRC Requests for Additional Information, 

dated May 18, 2012, Related to the License Renewal Application.” (ADAMS Accession 

No. ML12152A309)

June 5, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Requests for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos. ME6555 AND ME6556).” (ADAMS 

Accession No. ML12143A028)

June 7, 2012 Meeting Summary from Kuntz R. F., U. S. NRC, “4-30-12 Telecon Summary.” (ADAMS 

Accession No. ML12139A066)

June 8, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC Document Control 

Desk NRC/NRR, “Limerick, Units 1 and 2, Response to NRC Request for Additional 

Information, dated May 18, 2012, Related to License Renewal Application.” (ADAMS 

Accession No. ML12160A553)
B-7

APPENDIX B: CHRONOLOGY

Date Subject

June 12, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Request for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos. ME6555 AND ME6556).” (ADAMS 

Accession No. ML12152A305)

June 12, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Request for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos. ME6555 AND ME6556) OpE 

Followup RAI.” (ADAMS Accession No. ML12157A212)

June 12, 2012 Letter from Kuntz R. F., U. S. NRC, to Gallagher M., Exelon Generation Co., LLC, “LGS 

RWCU Followup 2 RAI.” (ADAMS Accession No. ML12160A012)

June 14, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC Document Control 

Desk NRC/NRR, “Limerick, Units 1 and 2, Response to NRC Request for Additional 

Information, dated June 5, 2012, Related to License Renewal Application.” (ADAMS 

Accession No. ML12166A286)

June 14, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC Document Control 

Desk NRC/NRR, “Limerick, Units 1 and 2, 10 CFR 54.21(b) Annual Amendment to 

License Renewal Application.” (ADAMS Accession No. ML12166A325)

June 19, 2012 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC Document Control 

Desk NRC/NRR, “Limerick, Units 1 and 2, Responses to NRC Requests for Additional 

Information, dated June 12, 2012, Related to the Limerick Generating Sation License 

Renewal Application.” (ADAMS Accession No. ML12171A487)

June 21 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Request for Additional Information for the Review of the Limerick Generating Station, 

Units 1 and 2, License Renewal Application (TAC Nos. ME6555 AND ME6556) OCCW 

followup RAI.” (ADAMS Accession No. ML12171A035)

June 22, 2012 Letter from Gallagher M., Exelon Generation Co, LLC Exelon Nuclear, to U.S. NRC 

Document Control Desk NRC/NRR, “Limerick Generating Station, Units 1 and 2, 

Response to NRC Requests for Additional Information, dated June 21, 2012, Related to 

License Renewal Application.” (ADAMS Accession No. ML12174A329)

June 25, 2012 Meeting Summary from Kuntz R. F., U.S. NRC, “Summary of Telephone Conference Call 

held on May 16, 2012 between the U.S. Nuclear Regulatory Commission and Exelon 

Generation Company, LLC, Concerning Requests for Additional Information Pertaining to 

the Limerick Generating Station License Renewal.” (ADAMS Accession No. 

ML12139A061)

July 10, 2012 Letter from Kuntz R. F., U.S. NRC, to Gallagher M., Exelon Generation Co., LLC, “RAI for 

the Review of the Limerick Generating Station, Units 1 and 2, License Renewal 

Application (TAC No. ME6555 and ME6556).” (ADAMS Accession No. ML12181A441)

July 11, 2012 Letter from Gallagher M., Exelon Generation Co, LLC Exelon Nuclear, to U.S. NRC 

Document Control Desk NRC/NRR, “Limerick Generating Station, Units 1 and 

2 - Response to NRC Request for Additional Information, dated July 10, 2012, the License 

Renewal Application.” (ADAMS Accession No. ML12193A535)
B-8

APPENDIX B: CHRONOLOGY

Date Subject

July 16, 2012 Meeting Summary from Kuntz R. F., U.S. NRC, “Summary of Telephone Conference Call 

held on January 4, 2012 between the U.S. Nuclear Regulatory Commission and Exelon 

Generation Company, LLC, Concerning Requests for Additional Information Pertaining to 

the Limerick Generating Station, License Renewal Application (TAC Nos. ME6555 and 

ME6556).” (ADAMS Accession No. ML12018A087)

July 20, 2012 Meeting Summary from Kuntz R. F., U.S. NRC, “6/11/2012 Telecon Summary with Exelon 

Generation Company, LLC.” (ADAMS Accession No. ML12164A800)

July 20, 2012 Meeting Summary from Kuntz R. F., U.S. NRC, “4/12/12 Telecon Summary with Exelon 

Generation Company, LLC.” (ADAMS Accession No. ML12139A071)

July 20, 2012 Meeting Summary from Kuntz R. F., U.S. NRC, “4/5/12 Telecon Summary with Exelon 

Generation Company, LLC.” (ADAMS Accession No. ML12139A074)

September 12, 2012 Letter from Gallagher M., Exelon Generation Co, LLC Exelon Nuclear, to U.S. NRC 

Document Control Desk NRC/NRR, “Exelon Generation Company, LLC Review of the 

Safety Evaluation Report with Open Items related to the Limerick Generating Station 

License Renewal Application” (ADAMS Accession No. ML12256A929)

October 10, 2012 Letter from Milano, P. D., U. S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Request for Additional Information for the Limerick Generating Station, Units 1 and 2, 

License Renewal Application (TAC No. ME6555 and ME6556).” (ADAMS Accession No. 

ML12283A096)

October 12, 2012 Letter from Gallagher M., Exelon Generation Co, LLC Exelon Nuclear, to U.S. NRC 

Document Control Desk NRC/NRR, “Exelon Generation Company, LLC Review of the 

Safety Evaluation Report with Open Items related to the Limerick Generating Station 

License Renewal Application” (ADAMS Accession No. ML12286A325)

October 12, 2012 Letter from Gallagher M., Exelon Generation Co, LLC Exelon Nuclear, to U.S. NRC 

Document Control Desk NRC/NRR, “Response to NRC Request for Additional 

Information, dated October 10, 2012, related to the Limerick Generating Station License 

Renewal Application” (ADAMS Accession No. ML12286A293)

October 19, 2012 Letter from Milano, P. D., U. S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Request for Additional Information for the Limerick Generating Station, Units 1 and 2, 

License Renewal Application (TAC No. ME6555 and ME6556).” (ADAMS Accession No. 

ML12290A853)

October 25, 2012 Letter from Gallagher M., Exelon Generation Co, LLC Exelon Nuclear, to U.S. NRC 

Document Control Desk NRC/NRR, “Response to NRC Request for Additional 

Information, dated October 25, 2012, related to the Limerick Generating Station License 

Renewal Application” (ADAMS Accession No. ML12299A393)

November 6, 2012 Letter from Gallagher M., Exelon Generation Co, LLC Exelon Nuclear, to U.S. NRC 

Document Control Desk NRC/NRR, “Exelon Generation Company, LLC Review of the 

Safety Evaluation Report with Open Items related to the Limerick Generating Station 

License Renewal Application” (ADAMS Accession No. ML12311A470)
B-9

APPENDIX B: CHRONOLOGY

Date Subject

December 20, 2012 Letter from Milano, P. D., U. S. NRC, to Gallagher M., Exelon Generation Co., LLC, 

“Change to Proposed License Condition Regarding Safety Evaluation Report Related to 

License Renewal of Limerick Generating Station, Units 1 and 2 (TAC No. ME6555 and 

ME6556).” (ADAMS Accession No. ML12352A056)

January 3, 2013 Letter from Gallagher M., Exelon Generation Co, LLC Exelon Nuclear, to U.S. NRC 

Document Control Desk NRC/NRR, “Exelon Generation Company, LLC Comments on the 

Proposed License Condition Related to License Renewal of Limerick Generating Station, 

Units 1 and 2.” (ADAMS Accession No. ML13003A211)

C-1

APPENDIX C

PRINCIPAL CONTRIBUTORS

This appendix lists the principal contributors for the development of this safety evaluation report 

(SER) and their areas of responsibility.

APPENDIX C: PRINCIPAL CONTRIBUTORS

Name Responsibility

Armstrong, Garry Reviewer – Scoping & Screening, Mechanical

Auluck, Rajender Management Oversight

Basturescu, Sergiu Reviewer – Scoping & Screening, Electrical

Brittner, Don Reviewer – Mechanical

Buford, Angela Reviewer – Structural

Casto, Greg Management Oversight

Dennig, Robert Management Oversight

Doutt, Cliff Reviewer – Electrical

Erickson, Alice Reviewer – Structural

Fu, Bart Reviewer – Mechanical

Gall, Jennifer Reviewer – Scoping & Screening, Mechanical

Galloway, Melanie Management Oversight

Gardner, William Reviewer – Mechanical

Gavula, Jim Reviewer – Mechanical

Green, Kim Reviewer – Mechanical

Hiser, Allen Management Oversight

Holian, Brian Management Oversight

Holston, Bill Reviewer – Mechanical

Iqbal, Naeem Reviewer – Fire Protection

Kalikian, Roger Reviewer – Mechanical
C-2

APPENDIX C: PRINCIPAL CONTRIBUTORS

Name Responsibility

Kichline, Michelle Reviewer – Mechanical

Klein, Alex Management Oversight

Klos, John Reviewer – Mechanical

Kuntz, Robert Management Oversight

Lehman, Bryce Reviewer – Structural

Li, Rui Reviewer – Electrical

Lupold, Tim Management Oversight

Medoff, Jim Reviewer – Mechanical

Min, Seung Reviewer – Mechanical

Morey, Dennis Management Oversight

Ng, Ching Reviewer – Mechanical

Nguyen, Duc Reviewer – Electrical

Obodoako, Alyoysius Reviewer – Mechanical

Parks, Benjamin Reviewer – Neutron Fluence

Pelton, Dave Management Oversight

Prinaris, Andrew Reviewer – Structural

Raval, Janak Reviewer – Scoping & Screening

Rogers, Bill Reviewer – Scoping & Screening Methodology

Sakai, Stacie Reviewer – Scoping & Screening Methodology

Sheikh, Abdul Reviewer – Structural

Smith, Ed Reviewer – Scoping & Screening, Mechanical

Sun, Robert Reviewer – Mechanical

Ulses, Anthony Management Oversight

Uribe, Juan Reviewer – Scoping & Screening, Structural

Wise, John Reviewer – Mechanical
C-3

APPENDIX C: PRINCIPAL CONTRIBUTORS

Name Responsibility

Wong, Emma Reviewer – Mechanical

Yee, On Reviewer – Mechanical

Yoder, Matthew Reviewer – Mechanical

CONTRACTORS

Name Responsibility

Argonne National Laboratory Technical Review

BLH Technologies, Inc. SER Support

D-1

APPENDIX D

REFERENCES

This appendix lists the references used throughout this safety evaluation report (SER) for review 

of the license renewal application (LRA) for Limerick Generating Station.

APPENDIX D: REFERENCES

Applicant’s Documents

Jesse, M. D., Exelon Generation Co., LLC, to U.S. Nuclear Regulatory Commission. “Request for License 

Amendment Regarding Measurement Uncertainty Recapture Power Uprate.” March 25, 2010, ADAMS Accession 

No. ML1008500380.

Benyak, D. M., Exelon Generation Co., LLC, to U.S. Nuclear Regulatory Commission. “Response to NRC Generic 

Letter 2007-01, ‘Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or 

Cause Plant Transients,’” May 7, 2007, ADAMS Accession No. ML071280098.

NRC Documents

U.S. Nuclear Regulatory Commission (U.S. NRC) Bulletin 80-11, “Masonry Wall Design,” May 1980.

– – – Generic Letter (GL) 88-01, “NRC Position On Intergranular Stress Corrosion Cracking (IGSCC) In BWR 

Austenitic Stainless Steel Piping,” January 1988.

– – – GL 88-14, “Instrument Air Supply System Problems Affecting Safety-Related Equipment,” August 1988.

– – – GL 89-13, “Service Water System Problems Affecting Safety-Related Equipment,” July 1989.

– – – GL 2007-01, “Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or 

Cause Plant Transients,” February 2007.

– – – Generic Safety Issue No. 190 (GSI-190), “Fatigue Evaluation of Metal Components for 60-Year Plant Life,” 

December 1999.

– – – Information Notice (IN) 87-67, “Lessons Learned from Regional Inspections of Licensee Actions in Response 

to IE Bulletin 80-11,” December 1987.

– – – IN 94-63, “Boric Acid Corrosion of Charging Pump Casings Caused by Cladding Cracks,” August 1994.

– – – IN 2005-23, “Vibration-Induced Degradation of Butterfly Valves,” August 2005.

– – – IN 2006-15, “Vibration-Induced Degradtion and Failure of Safety-Related Valves,” July 2006.

– – – IN 2009-26, “Degradation Of Neutron-Absorbing Materials in the Spent Fuel Pool,” October 2009.

– – – IN 2011-15, “Steel Containment Degradation and Associated License Renewal Aging Management Issues,” 

August 2011.

Limerick Generating Station - NRC Integrated Inspection Reports 05000352/2008003 and 05000353/2008003, 

August 13, 2008, ADAMS Accession No. ML082261341.
D-2

APPENDIX D: REFERENCES

Limerick Generating Station - NRC Integrated Inspection Reports 05000352/2008005 and 05000353/2008005, 

January 30, 2009, ADAMS Accession No. ML090330638.

Limerick Generating Station - NRC Integrated Inspection Reports 05000352/2010005 and 05000353/2010005, 

January 24, 2011, ADAMS Accession No. ML110250035.

NUREG-0313, “Technical Report On Material Selection And Processing Guidelines For BWR Coolant Pressure 

Boundary Piping,” Revision 2, 1988.

NUREG-0612, “Control of Heavy Loads at Nuclear Power Plants,” July 1980.

NUREG-0619, “BWR Feedwater Nozzle and Control Rod Driven Return Line Nozzle Cracking,” November 1980.

NUREG-0991, “Safety-Report Related to the Operation of Limerick Generating Station, Units 1 and 2,” August 

1983.

NUREG-1339, “Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants,” 

June 1990.

NUREG-1437, “Generic Environmental Impact Statement for License Renewal of Nuclear Plants (GEIS),” May 

1996.

NUREG-1557, “Summary of Technical Information and Agreements from Nuclear Management and Resources 

Counci1 Industry Reports Addressing License Renewal,” October 1996.

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-1924, “Electrical Raceway Fire Barrier Systems in U.S. Plants,” April 2010.

NUREG/CR-5704, “Effects of LWR Coolant Environments on Fatigue Design Curves of Austenitic Stainless 

Steels,” April 1999.

NUREG/CR-6260, “Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant

Components,” February 1995.

NUREG/CR-6583, “Effects of [Light-Water Reactor] LWR Coolant Environments on Fatigue Curves of Carbon and 

Low-Alloy Steels,” March 1998.

NUREG/CR-6909, “Effect of LWR Coolant Environments on the Fatigue Life of Reactor Materials,” February 2007.

U.S. NRC Regulatory Guide (RG) 1.36, “Nonmetallic Thermal Insulation for Austenitic Stainless Steel.”

– – – RG 1.43, “Control of Stainless Steel Weld Cladding of Low-Alloy Steel Components.”

– – – RG 1.45, “Guidance on Monitoring and Responding to Reactor Coolant System Leakage.”

– – – RG 1.54, “Service Level I, II, and III Protective Coatings Applied To Nuclear Power Plants.”

– – – RG 1.65, “Materials and Inspections for Reactor Vessel Closure Studs.”
D-3

APPENDIX D: REFERENCES

– – – RG 1.75, “Physical Independence of Electric Systems.”

– – – RG 1.89 “Environmental Qualification of Certain Electric Equipment Important to Safety for Nuclear Power 

Plants.”

– – – RG 1.99, “Radiation Embrittlement of Reactor Vessel Materials.”

– – – RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants.”

– – – RG 1.147, “Inservice Inspection Code Case Acceptability, ASME Code Section XI, Division 1.”

– – – RG 1.160, “Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.”

– – – RG 1.163, “Performance-Based Containment Leak-Test Program.”

– – – RG 1.188, “Standard Format and Content for Applications To Renew Nuclear Power Plant Operating 

Licenses.”

– – – RG 1.190, “Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence.”

Regulations

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, “Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions,” Part 51, 

2012.

CFR, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants,” Part 54, 2012.

Industry Documents

Boiling Water Reactor Owners’ Group (BWROG)-94037, “BWR Owners’ Group Topical Report on Upper-Shelf 

Energy Equivalent Margin Analysis – Approved Version,” March 21, 1994.

Electric Power Research Institute (EPRI) Boiling-Water Reactor Vessels Internal Program (BWRVIP)-05, “Reactor 

Vessel Shell Weld Inspection Guidelines,” EPRI, Palo Alto, CA, 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,” 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. Proprietary 

information. Not publicly available.

– – – BWRVIP 38, “BWR Shroud Support Inspection and Flaw Evaluation Guidelines” (EPRI TR-108823), 

September 1997.
D-4

APPENDIX D: REFERENCES

– – – BWRVIP-41, “BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines,” October 1997. 

Proprietary information. Not publicly available.

– – – BWRVIP-42-A, “BWR Vessel and Internals Project Boiling Water Reactor Low-Pressure Coolant Injection and 

Flaw Evaluation Guidelines,” February 2005. Proprietary information. Not publicly available.

– – – BWRVIP-47-A, “BWR Lower Plenum Inspection and Flaw Evaluation Guidelines,” November 2004. 

Proprietary information. Not publicly available.

– – – BWRVIP-48-A, “Vessel ID Attachment weld Inspection and Flaw Evaluation Guidelines,” November 2004. 

Proprietary information. Not publicly available.

– – – BWRVIP-49-A, “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, “Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules,” October 2005. 

Proprietary information. Not publicly available.

– – – BWRVIP-76-A, “BWR Core Shroud Inspection and Flaw Evaluation,” December 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-99-A, ““Crack Growth Rates in Irradiated Stainless Steels in BWR Internal Components,” October 

2008. Proprietary information. Not publicly available.

– – – 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-116, “Integrated Surveillance Program,” July 2003. Proprietary information. Not publicly available.

– – – BWRVIP-126, “BWR Vessel and Internals Project, RAMA Fluence Methodology Software,” 2003. Proprietary 

information. Not publicly available.

– – – BWRVIP-130, “BWR Water Chemistry Guidelines 2004 Revisions” (EPRI 1008192), October 2004.

– – – BWRVIP-183 “BWR Vessel and Internals Project, Top Guide Grid Beam Inspection and Flaw Evaluation 

Guidelines,” December 2007.

– – – BWRVIP-190, “BWR Water Chemistry Guidelines 2008 Revisions,” October 2008. Proprietary information. 

Not publicly available.

– – – EPRI 1007820, “Closed Cooling Water Chemistry Guideline, Revision 1: Revision 1 to TR-107396, Closed 

Cooling Water Chemistry Guideline” April 2004.

– – – EPRI 1013013, “An Evaluation of Flow-Accelerated Corrosion in the Bottom Head Drain Lines of Boiling 

Water Reactors,” March 2006.
D-5

APPENDIX D: REFERENCES

– – – EPRI 1011694, “BWR Vessel and Internals Project, Evaluation of Susquehanna Unit 2 Top Guide and Core 

Shroud Material Samples Using RAMA Fluence Methodology (BWRVIP-145),” November 2005. Proprietary 

information. Not publicly available.

– – – EPRI 1016949, “BWRVIP-191: BWR Vessel and Internals Project, Flow-Accelerated Corrosion in BWR 

Bottom Head Drain Lines: 2008 Update,” July 2008. Proprietary information. Not publicly available.

– – – EPRI NP-5769, “Degradation and Failure of Bolting in Nuclear Power Plants,” Volumes 1 and 2, May 1988.

– – – EPRI Nuclear Safety Analysis Center (NSAC)-202L-R3, “Recommendations for an Effective 

Flow-Accelerated Corrosion Program.” Non-proprietary version, August 2007.

– – – EPRI TR-1007820, “Closed Cooling Water Chemistry Guideline, Revision 1: Revision 1 to TR-107396, 

Closed Cooling Water Chemistry Guideline.” April 2004.

– – – EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide,” December 1995.

– – – EPRI TR-112657, “Revised Risk-Informed Inservice Inspection Evaluation Procedure,” Revision B-A, January 

2000.

“Bridge Scour and Stream Instability Countermeasures: Experience, Selection, and Design Guidance,” 3rd Edition, 

U.S. Department of Transportation, Federal Highway Administration, September 2009, 

<http://www.fhwa.dot.gov/engineering/hydraulics/pubs/09111/page00.cfm> (15 June 2012).

Crane Manufacturers Association of America (CMAA), Inc., Specification 70, “Specifications for Top Running 

Bridge & Gantry Type Multiple Girder Electric Overhead Traveling Cranes,” CMAA, Charlotte, NC, December 2008.

Eastman, “Tentite Plastics, Weathering of Tentite Butyrate.” Eastman Publication PP104B, May 1999, 

<http://www.eastman.com/Literature_Center/P/PP104.pdf> (15 June 2012).

General Electric Nuclear Energy, GE-NE-523-A71-0594-A, “Alternate BWR Feedwater Nozzle Inspection 

Requirements,” Revision 1, August 1999.

– – – NEDC-32983P-A, “General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux 

Evaluations,” December 2001. Proprietary information. Not publicly available.

– – – NEDO-32983P-A, “General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux 

Evaluations,” December 2001.

– – – NEDO-32205, “10 CFR 50 Appendix G Equivalent Margin Analysis for Low Upper-Shelf Energy in BWR-2 

through BWR-6 Vessels,” February 1994.

– – – NEDO-33484, “GEH Nuclear Energy Safety Analysis Report for Limerick Generating Station, Units 1 and 2 

Thermal Power Optimization,” Revision 0, March 2010.

Connecticut Department of Environmental Protection, “Guidelines for Inspection and Maintenance of Dams,” 

September 2001. 

<http://www.ct.gov/dep/lib/dep/water_inland/dams/guidelinesforinspectionandmaintenanceofdams.pdf> (15 June 

2012)

McKeen L., Fluorinated Coatings and Finishes Handbook: The Definitive Users Guide, William Andrew Publishing, 

Norwich, NY, 2006.
D-6

APPENDIX D: REFERENCES

Nuclear Energy Institute (NEI) 94-01 “Industry Guidance for Implementing Performance-Based Options of 10 CFR 

Part 50, Appendix J,” July 1995.

– – – 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.

Plastics Design Library Staff, Chemical Resistance of Plastics and Elastomers, (4th Electronic Edition), William 

Andrew Publishing/Plastics Design Library, 2008. 

<http://www.knovel.com/web/portal/browse/display?_EXT_KNOVEL_DISPLAY_bookid=2883&VerticalID=0> 

(15 June 2012)

Industry Codes and Standards

American Concrete Institute (ACI) 201.1R, “Guide for Making a Condition Survey of Existing Buildings,” July 2008.

– – – ACI 201.2R, “Guide to Durable Concrete,” June 2008.

– – – ACI 301-66, “Specifications for Structural Concrete for Buildings,” July 1966.

– – – ACI 318-71, “Building Code Requirements for Reinforced Concrete,” August 1972.

– – – ACI 349.3R-02, “Evaluation of Existing Nuclear Safety-Related Concrete Structures,” June 2002.

– – – ACI 605, “Recommended Practice for Hot Weather Concreting,” July 1959.

American National Standards Institute (ANSI)/American Nuclear Society (ANS) 56.8, “Containment System 

Leakage Testing Requirements,” 2002.

ANSI/American Society of Mechanical Engineers (ASME) B30.10, “Hooks,” 2009.

– – – ANSI/ASME B30.11, “Monorails and Underhung Cranes,” 2010.

– – – ANSI/ASME B30.16, “Overhead Hoist (Underhung) Inspection,” 2007.

– – – ANSI/ASME B30.2, “Overhead and Gantry Cranes–Top Running Bridge, Single or Multiple Girder, Top 

Running Trolley Hoist,” 2011.

– – – ANSI/ASME B31.1, “Power Piping.”

ANSI/ISA-S7.0.01, “Quality Standard for Instrument Air,” 1996.

ANSI/American Society of Civil Engineers (ASCE) 11-99, "Guideline for Structural Condition Assessment of 

Existing Buildings,” 2000.

American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessel Code, Section III, “Rules for 

Construction of Nuclear Power Plant Components,” American Society of Mechanical Engineers, New York, NY.

– – – ASME Code, Section XI, “Rules for Inservice Inspection of Nuclear Power Plant Components.”
D-7

APPENDIX D: REFERENCES

– – – ASME Code Case N-513, “Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 

2 or 3 Piping.”

– – – ASME OM-S/G-1998, Part 17, “Performance Testing of Instrument Air Systems Information Notice 

Light-Water Reactor Power Plants,” American Society of Mechanical Engineers, New York, NY, 1998.

ASM International, Metals Handbook, Volume 13, 9th edition, ASM International, Materials Park, OH, 1987.

– – – Metals Handbook, Desk Edition, 2nd Edition, 1998.

American Society for Testing and Materials, International (ASTM) C-33, “Standard Specification for Concrete 

Aggregates,” ASTM International, West Conshohocken, PA, January 2011.

– – – ASTM C289, “Standard Test Method for Potential Alkali Silica Reactivity of Cement Aggregates (Chemical 

Method),” 2007.

– – – ASTM C295, “Standard Guide for Petrographic Examination of Aggregates for Concrete,” April 2012.

– – – ASTM C449, “Standard Specification for Mineral Fiber Hydraulic-Setting Thermal Insulating and Finishing 

Cement,” 2007.

– – – ASTM D4057-95 (2000), “Standard Practice for Manual Sampling of Petroleum and Petroleum Products,” 

April 2000.

– – – ASTM D5163-08, “Standard Guide for Establishing a Program for Condition Assessment of Coating Service 

Level I Coating Systems in Nuclear Power Plants,” 2008.

– – – ASTM D7108, ‘Standard Guide for Establishing Qualifications for a Nuclear Coatings Specialist,” 2005.

National Association of Corrosion Engineers (NACE) International SP0169-2007, “Control of External Corrosion on 

Underground or Submerged Metallic Piping Systems,” NACE International, Houston, TX, March 2007.

National Fire Protection Association (NFPA) 25, “Standard for Inspection, Testing, and Maintenance of 

Water-Based Fire Protection Systems,” NFPA, Quincy, MA, 2008.




UNITED STATES

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

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OFFICIAL BUSINESS
 

 

NUREG-2171 Safety Evaluation Report Related to the License Renewal of 

Limerick Generating Station, Units 1 and 2